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spe papers_well deliverability

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spe papers_well deliverability Powered By Docstoc
					  Nov-09
NOTES:

           The papers listed here have been obtained by search SPE and IPTC papers post 2005 on the SPE's OnePetro
           The papers relating to reservoir engineering have been catergorised for inclusion on the   reservoirengineering.org.uk website
           The affiiations searched were;

                                                                    Total No Papers     Reservoir Engineering Related
                      BP                                                   551                      175
                      Shell                                                575                      279
                      Chevron                                              482                      238
                      ConocoPhillips                                       191                       68
                      Marathon                                             55                        37
                      Total                                                255                      129
                      Schlumberger                                        1130                      563
                      Imperial College, London                             95                        53
                      Heriot Watt University, Edinburgh                    235                      175
                      (Anywhere in Article)
                                                      Total               3569                          1717



                      Total number of papers published post 2005 =             10,000

                                                                   35% of papers published categorised
                                Paper
Organisation             Source No.          Chapter                  Section
SHELL                      SPE   101038   Well Deliverability      Acid Treatments
TOTAL                      SPE   107760   Well Deliverability      Acid Treatments
SCHLUMBERGER              IPTC    12368   Well Deliverability      Acid Treatments
SCHLUMBERGER               SPE   126066   Well Deliverability        Artificial Lift
CONOCO                     SPE   114912   Well Deliverability        Artificial Lift



CHEVRON                    SPE   128337   Well Deliverability        Artificial Lift
BP                         SPE   115950   Well Deliverability        Artificial Lift
CONOCO                     SPE   117489   Well Deliverability        Artificial Lift
SCHLUMBERGER               SPE   110103   Well Deliverability        Artificial Lift
SCHLUMBERGER               SPE   106094   Well Deliverability        Artificial Lift
Heriot Watt University     SPE   122231   Well Deliverability         Clean-up
Heriot Watt University    IPTC    12145   Well Deliverability      Compex Wells
CONOCO                     SPE   114011   Well Deliverability   Completion Optimisation
TOTAL                      SPE   102550   Well Deliverability   Completion Optimisation


CHEVRON                    SPE    89753   Well Deliverability   Completion Optimisation
BP                         SPE   106854   Well Deliverability   Completion Optimisation
SCHLUMBERGER               SPE   102544   Well Deliverability   Completion Optimisation
SCHLUMBERGER              IPTC    12364   Well Deliverability   Completion Optimisation
Heriot Watt University     SPE   108173   Well Deliverability   Completion Optimisation
SCHLUMBERGER               SPE   112476   Well Deliverability   Completion Optimisation
SCHLUMBERGER               SPE   112862   Well Deliverability   Completion Optimisation
SHELL                      SPE    99921   Well Deliverability   Completion Optimisation
SHELL                      SPE   100495   Well Deliverability   Completion Optimisation
SCHLUMBERGER               SPE   101720   Well Deliverability   Completion Optimisation
SCHLUMBERGER               SPE   102583   Well Deliverability   Completion Optimisation

CHEVRON                    SPE   100834   Well Deliverability      Complex Wells
SCHLUMBERGER               SPE   100834   Well Deliverability      Complex Wells
SCHLUMBERGER               SPE   110240   Well Deliverability      Complex Wells
Heriot Watt University     SPE   123682   Well Deliverability      Complex Wells
SCHLUMBERGER              IPTC    11630   Well Deliverability      Complex Wells
SCHLUMBERGER               SPE    84219   Well Deliverability      Complex Wells
SCHLUMBERGER               SPE   120744   Well Deliverability      Complex Wells
SHELL                      SPE    90959   Well Deliverability      Complex Wells
SCHLUMBERGER               SPE   126070   Well Deliverability      Complex Wells
SCHLUMBERGER               SPE   126061   Well Deliverability      Complex Wells
BP                         SPE    98359   Well Deliverability    Condensate Banking
SHELL                      SPE   102831   Well Deliverability     Controlled injection
MARATHON                   SPE    99718   Well Deliverability   Downhole Control Valves
BP                         SPE    99878   Well Deliverability         Dual ESP
Heriot Watt University     SPE    99878   Well Deliverability         Dual ESP
BP                         SPE   115546   Well Deliverability          Erosion
SCHLUMBERGER               SPE   102653   Well Deliverability            ESP
Imperial College         SPE     96722   Well Deliverability                 ESP
SCHLUMBERGER             SPE     96722   Well Deliverability                 ESP
SHELL                    SPE    105583   Well Deliverability               Foam flow

CHEVRON                   SPE   101987   Well Deliverability   Formation Damage/High Velocity Flow
SCHLUMBERGER             IPTC    12668   Well Deliverability             Fracture Design
CONOCO                    SPE   106050   Well Deliverability             Fracture Design
SCHLUMBERGER              SPE   106050   Well Deliverability             Fracture Design
Heriot Watt University    SPE    86485   Well Deliverability             Fracture Design
Heriot Watt University    SPE   100417   Well Deliverability             Fracture Design
SCHLUMBERGER              SPE   107979   Well Deliverability             Fracture Design
SCHLUMBERGER              SPE   112438   Well Deliverability             Fracture Design
SCHLUMBERGER              SPE   117061   Well Deliverability             Fracture Design
SCHLUMBERGER              SPE   119825   Well Deliverability             Fracture Design
SHELL                     SPE   108011   Well Deliverability             Fracture Design
SCHLUMBERGER              SPE   122307   Well Deliverability             Fracture Design
SCHLUMBERGER              SPE   103822   Well Deliverability             Fracture Design

CHEVRON                  SPE    112531   Well Deliverability             Fracture Design
SCHLUMBERGER             SPE    112435   Well Deliverability             Fracture Design
SCHLUMBERGER             SPE    125336   Well Deliverability             Fracture Design
Heriot Watt University   SPE    123466   Well Deliverability             Fracture Design
SCHLUMBERGER             SPE    122514   Well Deliverability             Fracture Design
SCHLUMBERGER             SPE    108126   Well Deliverability             Fracture Design
SCHLUMBERGER             SPE    107604   Well Deliverability             Fracture Design
BP                       SPE    102616   Well Deliverability             Fracture Design
SCHLUMBERGER             SPE    112171   Well Deliverability             Fracture Design
TOTAL                    SPE    107392   Well Deliverability             Fracture Design
SCHLUMBERGER             SPE     99419   Well Deliverability             Fracture Design
SCHLUMBERGER             SPE    118292   Well Deliverability             Fracture Design
SCHLUMBERGER             SPE    112442   Well Deliverability             Fracture Design
SCHLUMBERGER             SPE    114768   Well Deliverability             Fracture Design
SCHLUMBERGER             SPE    121204   Well Deliverability             Fracture Design
SCHLUMBERGER             SPE    121415   Well Deliverability             Fracture Design
BP                       SPE    101821   Well Deliverability             Fracture Design



CHEVRON                  SPE    101821   Well Deliverability             Fracture Design
Heriot Watt University   SPE    101821   Well Deliverability             Fracture Design
SCHLUMBERGER             SPE    113562   Well Deliverability             Fracture Design
SCHLUMBERGER             SPE    101722   Well Deliverability             Fracture Design
SCHLUMBERGER             SPE    119300   Well Deliverability             Fracture Design
SCHLUMBERGER             SPE    115556   Well Deliverability             Fracture Design
SCHLUMBERGER             SPE    119635   Well Deliverability             Fracture Design
SCHLUMBERGER             SPE    107730   Well Deliverability             Fracture Design
SCHLUMBERGER             SPE    100572   Well Deliverability             Fracture Design
SCHLUMBERGER             SPE    105657   Well Deliverability             Fracture Design
SCHLUMBERGER             SPE     98338   Well Deliverability             Fracture Design
SCHLUMBERGER             SPE    100524   Well Deliverability             Fracture Design
SCHLUMBERGER             SPE    102677   Well Deliverability             Fracture Design
SCHLUMBERGER             SPE    119586   Well Deliverability         Fracture Design

CHEVRON                   SPE   101019   Well Deliverability         Fracture Design
BP                        SPE   102227   Well Deliverability         Fracture Design
Heriot Watt University    SPE   107338   Well Deliverability         Fracture Design
SCHLUMBERGER             IPTC    11150   Well Deliverability         Fracture Design
Heriot Watt University    SPE   107432   Well Deliverability        Fracture Diagnosis
SCHLUMBERGER             IPTC    11347   Well Deliverability       Fracture Diagnostics
SCHLUMBERGER              SPE   102326   Well Deliverability       Fracture Diagnostics
SHELL                     SPE   102326   Well Deliverability       Fracture Diagnostics
Heriot Watt University    SPE   121916   Well Deliverability       Fracture Diagnostics




CHEVRON                  SPE    102326   Well Deliverability       Fracture Diagnostics
SCHLUMBERGER             SPE    110068   Well Deliverability       Fracture Diagnostics
SCHLUMBERGER             SPE    107662   Well Deliverability       Fracture Diagnostics
SCHLUMBERGER             SPE    102788   Well Deliverability       Fracture Diagnostics
BP                       SPE    102528   Well Deliverability       Fracture Diagnostics
SCHLUMBERGER             SPE    100556   Well Deliverability       Fracture Diagnostics
BP                       SPE    106301   Well Deliverability       Fracture Diagnostics
SCHLUMBERGER             SPE    102167   Well Deliverability       Fracture Diagnostics
SCHLUMBERGER             SPE    109909   Well Deliverability       Fracture Diagnostics
SCHLUMBERGER             SPE    109969   Well Deliverability       Fracture Diagnostics
SCHLUMBERGER             SPE    121888   Well Deliverability       Fracture Diagnostics
SCHLUMBERGER             SPE     98188   Well Deliverability       Fracture Diagnostics
SCHLUMBERGER             SPE    100321   Well Deliverability       Fracture Diagnostics
SCHLUMBERGER             SPE    106225   Well Deliverability       Fracture Diagnostics
SCHLUMBERGER             SPE    102469   Well Deliverability       Fracture Diagnostics
SCHLUMBERGER             SPE    106317   Well Deliverability       Fracture Diagnostics

CHEVRON                  SPE    108142   Well Deliverability       Fracture Diagnostics
SCHLUMBERGER             SPE    110696   Well Deliverability       Fracture Diagnostics
CHEVRON                  SPE    109247   Well Deliverability       Fracture Diagnostics
SCHLUMBERGER             SPE    106264   Well Deliverability       Fracture Diagnostics
SCHLUMBERGER             SPE    106043   Well Deliverability       Fracture Diagnostics
SCHLUMBERGER             SPE    102570   Well Deliverability       Fracture Diagnostics
Heriot Watt University   SPE    107634   Well Deliverability       Fracture Diagnostics
SCHLUMBERGER             SPE    102405   Well Deliverability       Fracture Diagnostics
SCHLUMBERGER             SPE     98746   Well Deliverability       Fracture Diagnostics
SHELL                    SPE     98746   Well Deliverability       Fracture Diagnostics

CHEVRON                   SPE   102990   Well Deliverability       Fracture Diagnostics
SCHLUMBERGER              SPE   122018   Well Deliverability       Fracture Diagnostics
SCHLUMBERGER             IPTC    12183   Well Deliverability       Fracture Diagnostics
SCHLUMBERGER              SPE   119351   Well Deliverability       Fracture Dignostics
CONOCO                    SPE   107793   Well Deliverability      Fracture Performance
Heriot Watt University    SPE   115726   Well Deliverability      Fracture Performance
TOTAL                     SPE   102475   Well Deliverability            Fracturing
CONOCO                    SPE   114804   Well Deliverability            Fracturing
CHEVRON                   SPE   103433   Well Deliverability   Gas Condensate Deliverability
SHELL                    SPE    112234   Well Deliverability      Gas Coning Control
SCHLUMBERGER             SPE    104202   Well Deliverability        Gas Lift Systems
SCHLUMBERGER             SPE    106854   Well Deliverability         Gas Production
SHELL                    SPE    110754   Well Deliverability   Heavy Oil-in-Water Emulsion

CHEVRON                   SPE   102773   Well Deliverability     High Velocity Coefficient
TOTAL                     SPE    98164   Well Deliverability         Horizontal Well
Heriot Watt University    SPE   104183   Well Deliverability         Horizontal Well
BP                       IPTC    11508   Well Deliverability         Horizontal Well
SCHLUMBERGER              SPE   113553   Well Deliverability         Horizontal Well
SCHLUMBERGER              SPE   114961   Well Deliverability         Horizontal Well
SCHLUMBERGER              SPE   112077   Well Deliverability         Horizontal Well
TOTAL                     SPE   112077   Well Deliverability         Horizontal Well
CONOCO                    SPE    97121   Well Deliverability         Horizontal Well
SHELL                     SPE   102678   Well Deliverability         Horizontal Well
BP                        SPE   100796   Well Deliverability         Hydrate Control
Heriot Watt University    SPE   107138   Well Deliverability       Inflow Performance
SHELL                     SPE   102077   Well Deliverability       Inflow Performance

CHEVRON                  SPE    84399    Well Deliverability       Inflow Performance
CHEVRON                  SPE    90541    Well Deliverability          Inflow Profiling

Imperial College          SPE    95843   Well Deliverability     Intelligent WAG Injector
SCHLUMBERGER              SPE   120800   Well Deliverability           Intelligent Well
BP                       IPTC    11784   Well Deliverability           Intelligent Well
Heriot Watt University    SPE   108700   Well Deliverability           Intelligent Well
SCHLUMBERGER              SPE   123008   Well Deliverability           Intelligent Well
Heriot Watt University    SPE   100191   Well Deliverability           Intelligent Well
SCHLUMBERGER              SPE   120799   Well Deliverability           Intelligent Well
Heriot Watt University    SPE    99929   Well Deliverability           Intelligent Well


CHEVRON                  SPE    103308   Well Deliverability         Intelligent Well
SCHLUMBERGER             SPE    110960   Well Deliverability         Intelligent Well
SCHLUMBERGER             SPE    113918   Well Deliverability         Intelligent Well
CONOCO                   SPE    103617   Well Deliverability    Lab Testing - Fracturing
SCHLUMBERGER             SPE    103617   Well Deliverability    Lab Testing - Fracturing
SHELL                    SPE    122133   Well Deliverability    Lab Testing - Stimulation
SHELL                    SPE    107790   Well Deliverability    Lab Testing - Stimulation
SHELL                    SPE    107795   Well Deliverability    Lab Testing - Stimulation
MARATHON                 SPE    120625   Well Deliverability         Liquid Loading

CHEVRON                  IPTC    11332   Well Deliverability         Liquid Loading
SHELL                     SPE   104605   Well Deliverability         Liquid Loading
SHELL                     SPE   107980   Well Deliverability         Liquid Loading
BP                        SPE   107467   Well Deliverability         Liquid Loading
SHELL                     SPE   115567   Well Deliverability         Liquid Loading
BP                       IPTC    11651   Well Deliverability         Liquid Loading
BP                        SPE   108380   Well Deliverability         Liquid Loading
BP                        SPE   110357   Well Deliverability         Liquid Loading
CHEVRON                  SPE    103266   Well Deliverability             Liquid Loading

CHEVRON                  SPE    116764   Well Deliverability           Liquid Loading
MARATHON                 SPE    103151   Well Deliverability           Liquid Loading
CONOCO                   SPE    107780   Well Deliverability       Modelling - Acid treatment

CHEVRON                  SPE    109588   Well DeliverabilityModelling - Coupled Reservoir/Geomechanical
SCHLUMBERGER             SPE    104629   Well Deliverability         Modelling - Flow Assurance
SCHLUMBERGER             SPE    116370   Well Deliverability         Modelling - Well Productivity
SCHLUMBERGER             SPE    120049   Well Deliverability        Modellling - Sanding Prediction
SCHLUMBERGER             SPE    105022   Well Deliverability             Perforation Methods
SCHLUMBERGER             SPE    106400   Well Deliverability             Perforation Methods
SCHLUMBERGER             SPE    102241   Well Deliverability             Perforation Methods
SCHLUMBERGER             SPE    112488   Well Deliverability             Perforation Methods
SHELL                    SPE    102656   Well Deliverability             Perforation Methods
SCHLUMBERGER             SPE    104099   Well Deliverability             Perforation Methods
SHELL                    SPE    101082   Well Deliverability             Perforation Methods
SCHLUMBERGER             SPE    120508   Well Deliverability             Perforation Methods
TOTAL                    SPE    120508   Well Deliverability             Perforation Methods
SCHLUMBERGER             SPE    101278   Well Deliverability             Perforation Methods


CHEVRON                   SPE   108088   Well Deliverability          Perforation Methods
MARATHON                 IPTC    12334   Well Deliverability          Perforation Methods
SHELL                    IPTC    12334   Well Deliverability          Perforation Methods
SCHLUMBERGER              SPE   112432   Well Deliverability          Perforation Methods
SCHLUMBERGER              SPE   113698   Well Deliverability          Perforation Methods



CHEVRON                  SPE    128334   Well Deliverability          Perforation Methods
SCHLUMBERGER             SPE    111538   Well Deliverability          Perforation Methods
SCHLUMBERGER             SPE    119639   Well Deliverability          Perforation Methods
SCHLUMBERGER             SPE    121931   Well Deliverability          Perforation Methods
SCHLUMBERGER             SPE    121964   Well Deliverability          Perforation Methods
Heriot Watt University   SPE    107864   Well Deliverability          Performance Decline
Heriot Watt University   SPE    100512   Well Deliverability          Performance Decline
BP                       SPE     98351   Well Deliverability        Produced Water Injection
Heriot Watt University   SPE    122266   Well Deliverability           Production Capacity
SCHLUMBERGER             SPE    110978   Well Deliverability         Production Optimisation
SCHLUMBERGER             SPE    112491   Well Deliverability              Sand Control
SHELL                    SPE    101187   Well Deliverability              Sand Control
SHELL                    SPE    101181   Well Deliverability              Sand Control
CONOCO                   SPE    105541   Well Deliverability              Sand Control
SCHLUMBERGER             SPE    105541   Well Deliverability              Sand Control
SCHLUMBERGER             SPE    117518   Well Deliverability              Sand Control
CHEVRON                  SPE     98563   Well Deliverability              Sand Control

CHEVRON                  SPE    112394   Well Deliverability              Sand Control
SHELL                    SPE    116091   Well Deliverability              Sand Control
SHELL                    SPE    111635   Well Deliverability     Sand Control
CONOCO                   SPE    105542   Well Deliverability     Sand Control
SCHLUMBERGER             SPE    105542   Well Deliverability     Sand Control
SCHLUMBERGER             SPE    128606   Well Deliverability     Sand Control
SCHLUMBERGER             SPE    112456   Well Deliverability     Sand Control
BP                       SPE    104532   Well Deliverability     Sand control
BP                       SPE    107297   Well Deliverability     Sand Control

CHEVRON                   SPE   110395   Well deliverability     Sand Control
Heriot Watt University    SPE   122054   Well Deliverability     Sand Control
Heriot Watt University    SPE   122064   Well Deliverability     Sand Control
SCHLUMBERGER              SPE   105758   Well Deliverability     Sand Control
SCHLUMBERGER              SPE   107297   Well Deliverability     Sand Control
SCHLUMBERGER              SPE   121093   Well Deliverability     Sand Control
SCHLUMBERGER              SPE   121834   Well Deliverability     Sand Control
SCHLUMBERGER              SPE   121912   Well Deliverability     Sand Control
TOTAL                    IPTC    12388   Well Deliverability     Sand Control
TOTAL                     SPE    98562   Well Deliverability     Sand Control
SCHLUMBERGER             IPTC    12448   Well Deliverability     Sand Control
SCHLUMBERGER              SPE    98151   Well Deliverability     Sand Control


CHEVRON                   SPE   106707   Well Deliverability     Sand Control
TOTAL                     SPE   107341   Well Deliverability     Sand Control
SCHLUMBERGER             IPTC    12581   Well Deliverability     Sand Control
SCHLUMBERGER              SPE   123495   Well Deliverability     Sand Control
BP                        SPE    98252   Well Deliverability     Sand control
SCHLUMBERGER              SPE   112050   Well Deliverability     Sand Control

CHEVRON                   SPE   112084   Well Deliverability     Sand Control
SCHLUMBERGER             IPTC    12385   Well Deliverability     Sand Control

CHEVRON                  SPE    107440   Well Deliverability     Sand Control
SCHLUMBERGER             SPE    107440   Well Deliverability     Sand Control
SCHLUMBERGER             SPE    102185   Well Deliverability     Sand Control

CHEVRON                  SPE    103821   Well Deliverability     Sand Control
Heriot Watt University   SPE    101994   Well Deliverability     Sand Control
SHELL                    SPE    116713   Well Deliverability     Sand Control
TOTAL                    SPE    107767   Well Deliverability     Sand Control
TOTAL                    SPE    100023   Well Deliverability     Sand Erosion
CONOCO                   SPE    121498   Well Deliverability   Sand Management
CONOCO                   SPE    102802   Well Deliverability   Sand Management
SHELL                    SPE    112099   Well Deliverability   Sand Management
SCHLUMBERGER             SPE    112904   Well Deliverability   Sand Management
CONOCO                   SPE    103244   Well Deliverability   Sand Management
Imperial College         SPE    100944   Well Deliverability    Sand Production
SCHLUMBERGER             SPE    100944   Well Deliverability    Sand Production
SCHLUMBERGER             SPE    104239   Well Deliverability    Sand Production
TOTAL                    SPE    104239   Well Deliverability    Sand Production
Imperial College         SPE     92715   Well Deliverability    Sand Production
SCHLUMBERGER             SPE     92715   Well Deliverability    Sand Production
BP                       SPE   89895    Well Deliverability    Sand production
Heriot Watt University   SPE   89895    Well Deliverability    Sand production

Imperial College         SPE    89895   Well Deliverability    Sand production
BP                       SPE    84500   Well Deliverability    Sand production
Imperial College         SPE    84500   Well Deliverability    Sand production
SCHLUMBERGER             SPE   102242   Well Deliverability    Sand Production
BP                       SPE   115058   Well Deliverability    Sand Production
BP                       SPE    90273   Well Deliverability    Sand Production

Imperial College         SPE    90273   Well Deliverability    Sand Production
SHELL                    SPE   102305   Well Deliverability    Sand Production
SCHLUMBERGER             SPE    98315   Well Deliverability    Sand Production
SCHLUMBERGER             SPE   101087   Well Deliverability    Sand Production
TOTAL                    SPE   100627   Well Deliverability    Scale Inhibitors
Imperial College         SPE   100371   Well Deliverability   Scale Management
Imperial College         SPE    82249   Well Deliverability      Skin Factor
CONOCO                   SPE    77363   Well Deliverability   Skin Factor Model
SCHLUMBERGER             SPE    90383   Well Deliverability   State of the Nation
CONOCO                   SPE   107978   Well Deliverability       Stimulation
SCHLUMBERGER             SPE   106272   Well Deliverability       Stimulation
SCHLUMBERGER             SPE   107978   Well Deliverability       Stimulation
SCHLUMBERGER             SPE   115525   Well Deliverability       Stimulation
SCHLUMBERGER             SPE   115528   Well Deliverability       Stimulation
BP                       SPE    90062   Well Deliverability       Stimulation
BP                       SPE   121483   Well Deliverability       Stimulation


CHEVRON                  SPE   86504    Well Deliverability       Stimulation

CHEVRON                  SPE   98221    Well Deliverability       Stimulation

CHEVRON                  SPE   122630   Well Deliverability       Stimulation
Heriot Watt University   SPE   110895   Well Deliverability       Stimulation
SCHLUMBERGER             SPE    98221   Well Deliverability       Stimulation
SCHLUMBERGER             SPE    98357   Well Deliverability       Stimulation
SCHLUMBERGER             SPE   105127   Well Deliverability       Stimulation
SCHLUMBERGER             SPE   106321   Well Deliverability       Stimulation
SCHLUMBERGER             SPE   106442   Well Deliverability       Stimulation
SCHLUMBERGER             SPE   112419   Well Deliverability       Stimulation
SCHLUMBERGER             SPE   116601   Well Deliverability       Stimulation
SCHLUMBERGER             SPE   116775   Well Deliverability       Stimulation
SHELL                    SPE   106321   Well Deliverability       Stimulation
SCHLUMBERGER             SPE   109911   Well Deliverability       Stimulation
SCHLUMBERGER             SPE   104610   Well Deliverability       Stimulation
SCHLUMBERGER             SPE   106444   Well Deliverability       Stimulation
SCHLUMBERGER             SPE   115558   Well Deliverability       Stimulation


CHEVRON                  SPE   102669   Well Deliverability       Stimulation
SCHLUMBERGER             SPE   104627   Well Deliverability       Stimulation
SHELL                    SPE   107749   Well Deliverability       Stimulation
Heriot Watt University   SPE   106012   Well Deliverability            Stimulation
SCHLUMBERGER             SPE   102681   Well Deliverability            Stimulation

CHEVRON                  SPE   111431   Well Deliverability           Stimulation
SCHLUMBERGER             SPE   107966   Well Deliverability           Stimulation
SCHLUMBERGER             SPE   111431   Well Deliverability           Stimulation
SCHLUMBERGER             SPE    98055   Well Deliverability     Stimulation Optimisation
CONOCO                   SPE   116711   Well Deliverability   Water and Condensate Blocks

CHEVRON                  SPE    98375   Well Deliverability         Water Blocking
SCHLUMBERGER             SPE   105367   Well Deliverability         Water Blocking
TOTAL                    SPE   105367   Well Deliverability         Water Blocking
SCHLUMBERGER             SPE   112176   Well Deliverability     Water Control/Stimulation
Heriot Watt University   SPE   113889   Well Deliverability      Water Entry Detection
BP                       SPE   112143   Well Deliverability         Water Injection
Heriot Watt University   SPE   112143   Well Deliverability         Water Injection
BP                       SPE   112282   Well Deliverability         Water Injection
Heriot Watt University   SPE   107168   Well Deliverability        Well Comparison
BP                       SPE   120708   Well Deliverability        Well Optimisation
SCHLUMBERGER             SPE   101420   Well Deliverability         Zonal Isolation
TOTAL                    SPE   101420   Well Deliverability         Zonal Isolation
        Subject
        Case Study
           ERW
  Production Optimisation
           ESP's
Formation Powered Jet Pump



          Gas Lift
         Gas Well
           SAGD
       SAGD ESP
     Staircase Lifting
     Intelligent Wells
  Downhole control Valves
     Big Bore Design
     Big Bore Design


      Gas Condensate
    High Rate Gas Wells
      Horizontal Wells
      Manati Gas Filed
       Marginal Wells
   Multilayered Reservoirs
    Near Wellbore Stress
          Openhole
          Openhole



    Carbonate Reservoir
    Carbonate Reservoir
    Complex Reservoirs
  Downhole Control Valves
  Downhole Control Valves
  Downhole Control Valves
  Downhole Control Valves
  Downhole Control Valves
        Intervention
  Production Performance
          Removal
Reservoir Damage Prevention
      West Brae Field
        Appications
        Appications
          Gas Well
    Perforation Methods
   Performance Analysis
   Performance Analysis
         Prediction

  Productivity Impairment
      Acid Fracturing
    Candidate selection
    Candidate selection
     Chalk Reservoirs
    Damage prevention
      Fiber Assisted
      Fiber Assisted
      Fiber Assisted
      Fiber Assisted
      Fiber Assisted
      Flowback Aids
Formation Modulus Contrast

         Frac Fluids
        Fracture Fluid
Fracture Fluids Optimisation
     Fracture Geometry
     Fracture Geometry
    Fracture Propagation
       Height Control
       Horizontal well
 Horizontal Well Application
 Influence ofHeterogeneity
        Mature Fields
 Multifrac Horizontal Wells
          Multistage
Multistage Horizontal Wells
Multistage Horizontal Wells
Multistage Horizontal Wells
   Non-Darcy/Multiphase



  Non-Darcy/Multiphase
  Non-Darcy/Multiphase
       Optimisation
   Performance Criteria
    Proppant Transport
 Samara Area Reservoirs
 Simultaneous Fracturing
Sliding Sleeve Application
Sliding Sleeve Applocation
      Soft Formations
   Surfactant Fracturing
   Surfactant Fracturing
   Surfactant Fracturing
    Surfactant Fracturing

     Water Control
      Water-Fracs
    Waxy-Oil Reservoir

 Clean-up Gas Condensate
      Acid Fracturing
         Clean-up
         Clean-up
 Clean-up Gas Condensate




Clean-up/Damage Mitigation
  Completion Optimisation
      Damage Analysis
     Deviation Surveys
        Diagnostics
       Fiber Assisted
    Fracture Conductivity
    Fracture Conductivity
     Fracture Geometry
     Fracture Geometry
     Fracture Geometry
      Gas Condensate
      Gas Condensate
High Permeability Formations
  Long-Term Rate Effects
      Low-Conductivity

  Microseismic Monitoring
  Microseismic Monitoring
     Non-Darcy Effects
    Proppant Flowback
        Refracture
   Reseridual Saturation
        Skin Factor
     Sonic Anisotropy
    State of the Nation
    State of the Nation

  Water Injector Fracturing
  Water Injector Fracturing

     Fracture Geometry
       Chalk reservoirs
  Gas-Condensate Mobility
Acid - Challenging Conditions
 Massive Annular Fracturing
    Distinguished Lecture
            Modelling
             Theory
          High rate wells
           Gas shut-off

          Two Phase Flow
             Clean-up
        Impact of Trajectory
             Injectivity
          Novel Open hole
          Novel Open hole
            OBM Effect
            OBM Effect
             Openhole
        Under Performance
               GOM
         Gas Condensate
          Horizontal wells

            Profiling
         Temperature Data

         Statoil Veslefrikk
          Complex Wells
    Development Optimisation
     Downhole Control Valves
     Downhole Control Valves
Downhole Control Valves - Placement
              ESP's
  Proactive and Reactive Control


      Production Optimisation
      Production Optimisation
     Uncertainty Management
            Heterogeneity
            Heterogeneity
  Behaviour of CO2 and N2 Foams
              Modelling
              Modelling
    Critical Velocity Calculations

            Dual Lateral
             Mitigation
             Mitigation
       North Sea Experience
             Prediction
          Horizontal Well

        Cavity Completion
     Productivity Improvement
          Heterogeneity

        Carboate Reservoir
           Case study
          Coiled Tubing
           Dynamic UB
          Limited Entry
      Negative Skin Factors
           Optimisation
            Orientation
            Orientation
     Productivity Improvement


       Propellant assisted
       Propellant assisted
       Propellant assisted
     Skin Variation Quantified
         UnderBalanced




         Scale Formation
         Scale Formation
      Fracture Propagation
         UBD - Vietnam
       SMART Completions
          Albacora Field
Associated with Hydraulic fracturing
     Challenging Conditions
    Completion Optimisation
    Completion Optimisation
         Complex Wells
            Deepwater

            Deepwater
            Deepwater
   Expandable Screen
         Failure
         Failure
    Failure Mitigation
         Failures
      Gravel Pack
      Gravel Pack

     Gravel Pack
     Gravel Pack
     Gravel Pack
     Gravel Pack
     Gravel Pack
     Gravel Pack
     Gravel Pack
     Gravel Pack
     Gravel Pack
     Gravel Pack
 Gravel Pack Modelling
    Gravel Packing


     Horizontal Wells
Microemulsion Technology
       Optimisation
  Perforate/Gravel Pack
    Perforating Policy
   Perforation Method

     Screen Failure
   Screen Technology

 Screenless Completions
 Screenless Completions
        Screens

       Steamflood
       Tapti Field


       Prediction
       Clean-out
Observations Post-Failure
   Risk Assessment
       Sarir Field

   Accurate Pediction
   Accurate Pediction
       Case Study
       Case Study
   Effect of water-Cut
   Effect of water-Cut
    Flowing conditions
    Flowing conditions

    Flowing conditions
     Horizontal wells
     Horizontal wells
       Mature Fields
        Mitigation
        Prediction

        Prediction
        Prediction
    Wellbore Stability
    Wellbore Stability
   Elgin/Franklin Fields

      Assessment
     Horizontal wells
     Acid treatment
     Acid Fracturing
     Acid Fracturing
     Acid Fracturing
     Acid Fracturing
     Acid Fracturing
     Acid Treatment
     Acid Treatment


      Acid treatment

      Acid treatment

      Acid treatment
     Acid Treatment
      Acid treatment
     Acid Treatment
     Acid Treatment
     Acid Treatment
     Acid Treatment
     Acid Treatment
     Acid Treatment
     Acid Treatment
     Acid Treatment
Chelating Agent Application
  Combined Treatments
  Diversion Techniques
     Foam Fracturing


     Gas Condensate
      Heterogeneity
     Horizontal wells
Relative Permeability Modifier
        Restimulation

    Surfactant Fracturing
    Surfactant Fracturing
    Surfactant Fracturing
       Mature Fields
    Chemical Treatment

     Gas Condensate
      Gas Reservoirs
      Gas Reservoirs
   Sufactant Treatment
     Intelligent Wells
       Flow Control
       Flow Control
     Hammer effects
 Gas Condensate - Layered
            LWD
    CBL Interpretation
    CBL Interpretation
                                               Title
A High-Success-Rate Acid Stimulation Campaign—A Case History
Acid Stimulation of Extended Reach Wells: Lessons Learnt From N'Kossa Field
Optimizing Well Productivity by Controlling Acid Dissolution Pattern During Matrix Acidizing of Carbonate Reservoirs
Case Study: First Successful Offshore ESP Project in Saudi Arabia
Formation Powered Jet Pump Use at Kuparuk Field in Alaska


A Simple Operational Approach To Ascertain the Viability of Your Offshore Gas Lift Project Before
Fully Committing: The Meji Jacket X and Y Pilot Case
Artificial Lift Selection Strategy for the Life of a Gas Well with some Liquid Production
SAGD Gas Lift Completions and Optimization: A Field Case Study at Surmont
Pushing the Boundaries of Artificial Lift Applications: SAGD ESP Installations at Suncor Energy, Canada
Staircase Lifting of Oil Using Venturi Principle: A New Artificial-Lift Technique
Efficient Intelligent Well Cleanup using Downhole Monitoring
Advanced Wells: A Comprehensive Approach to the Selection Between Passive and Active Inflow Control Completions
Revised Big Bore Well Design Recovers Original Bayu-Undan Production Targets
Big Bore Completion and Sand Control for High Rate Gas Wells

Exploring Reservoir Engineering Aspects of Completion in Gas/Condensate Reservoirs: West
African Examples
A Critical Review of Completion Techniques for High-Rate Gas Wells Offshore Trinidad
Selection of an Adequate Completion Type is the Key to Successful Reserves Recovery. Case History of Horizontal Drilling in t
The Challenges and Advantages of Openhole Completions in the Manati Gas Field
Multiple-Zone Completion in Marginal Production Wells
Multiple-Layer Completions for Efficient Treatment of Multilayer Reservoirs
Dipole Radial Profiling and Geomechanics for Near Wellbore Alteration Detection to Improve Productivity in a Matured Field
Openhole Completion Options: The Niger Delta Experience
Mechanistic Understanding of Rock/Phosphonate Interactions and the Effect of Metal Ions on Inhibitor Retention
Production Tubing String Design for Optimum Gas Recovery
Optimized Tubing-String Design Modeling for Improved Recovery

Application of a Maximum Reservoir Contact (MRC) Well in a Thin, Carbonate Reservoir in Kuwait
Application of a Maximum Reservoir Contact (MRC) Well in a Thin, Carbonate Reservoir in Kuwait
Succeeding With Multilateral Wells in Complex Channel Sands
A Generalized Predictive Control for Management of an Intelligent Well’s Downhole, Interval Control Valves—Design and
Using Down-Hole Control Valves to Sustain Oil Production From the First Maximum Reservoir Contact, Multilateral and Smart W
On Reservoir Fluid-Flow Control With Smart Completions
Case Study: The Use of Downhole Control Valves to Sustain Oil Production from the First Maximum Reservoir Contact, Multila
Optimization of Commingled Production Using Infinitely Variable Inflow Control Valves
Horizontal Open Hole, Dual-Lateral Stimulation, Using a Multilateral Entry with High Jetting Tool
Experimental and Numerical Study on Production Performance: Case of Horizontal and Dual-Lateral Wells
Evaluation of Alcohol-Based Treatments for Condensate Banking Removal
Online Water-Injection Optimization and Prevention of Reservoir Damage
Increasing Oil Recovery by Preventing Early Water and Gas Breakthrough in a West Brae Horizontal Well:�A Case History
Analysis of Possible Applications of Dual ESPs—A Reservoir-Engineering Perspective
Analysis of Possible Applications of Dual ESPs—A Reservoir-Engineering Perspective
Erosion Study for a 400 MMcf/D Completion: Cannonball Field, Offshore Trinidad
Development of an Integrated Solution for Perforation, Production and Reservoir Evaluation
Survival Analysis: The Statistically Rigorous Method for Analyzing Electrical Submersible Pump
System Performance
Survival Analysis: The Statistically Rigorous Method for Analyzing Electrical Submersible Pump System Performance
Hydraulic Predictions for Polymer-Thickened Foam Flow in Horizontal and Directional Wells
Effects of Formation Damage and High-Velocity Flow on the Productivity of Slotted-Liner Completed
Horizontal Wells
Long Term Evaluation of an Innovative Acid System for Fracture Stimulation of Carbonate Reservoirs in Saudi Arabia
Horizontal Fracture Stimulation Success in the Alpine Formation, North Slope, Alaska
Horizontal Fracture Stimulation Success in the Alpine Formation, North Slope, Alaska
Fracture Treatment Design and Execution in Low-Porosity Chalk Reservoirs
Field Case Studies: Damage Preventions Through Leakoff Control of Fracturing Fluids in Marginal/Low-Pressure Gas Reservo
Fiber-Laden Fracturing Fluid Improves Production in the Bakken Shale Multi-Lateral Play
Fiber-Based Fracture Fluid Technology a First for Oil Reservoirs in Western Siberia
Field Trials of Fiber Assisted Stimulation in Saudi Arabia: An Innovative Non-Damaging Technique for Achieving Effective Zona
Fiber-Laden Fluid: Applied Solution for Addressing Multiple Challenges of Hydraulic Fracturing in Western Siberia
An Engineered Fiber for the Fracturing of Unconsolidated Sand in Highly Deviated Wells in the Tali Field of Brunei
Comparison of Flowback Aids: Understanding Their Capillary Pressure and Wetting Properties
Effect of Formation Modulus Contrast on Hydraulic Fracture Height Containment

Weighted Frac Fluids for Lower-Surface Treating Pressures
A Faster Cleanup, Produced Water-Compatible Fracturing Fluid: Fluid Designs and Field Case Studies
Optimizing Fracturing Fluids From Flowback Water
Optimization of Hydraulic Fracture Geometry
Maximizing Effective Fracture Half-Length to Influence Well Spacing
Novel Frac-and-Pack Technique for Selective Fracture Propagation
A Novel Approach to Fracturing Height Control Enlarges the Candidate Pool in the Ryabchyk Formation of West Siberia’s M
Fracture Treatment Optimization for Horizontal Well Completion
Application of a Highly Efficient Multistage Stimulation Technique for Horizontal Wells
New Methodology of Effective Hydraulic Fracturing in High-Thickness Formation
Stimulating High-Water-Cut Wells: Results From Field Applications
Efficient Multifractured Horizontal Completions Change the Economic Equation in Latin America Through Improved Reservoir C
Continuous Pumping, Multistage, Hydraulic Fracturing in Kitina Field, Offshore Congo, West Africa
Successful Multistage Horizontal Well Fracturing in the Deep Gas Reservoirs of Saudi Arabia: Field Testing of a Promising Inno
Successful Multistage Hydraulic Fracturing Treatments Using a Seawater-Based Polymer-Free Fluid System Executed From a
Successful Continuous, Multi-Stage, Hydraulic Fracturing Using a Seawater-Based Polymer-Free Fluid System, Executed from
Designing Hydraulic Fractures in Russian Oil and Gas Fields to Accommodate Non-Darcy and Multiphase Flow


Designing Hydraulic Fractures in Russian Oil and Gas Fields to Accommodate Non-Darcy and
Multiphase Flow
Designing Hydraulic Fractures in Russian Oil and Gas Fields to Accommodate Non-Darcy and Multiphase Flow
Optimized Hydrualic Fracturing for the Gandhar Field
Production Performance Design Criteria for Hydraulic Fractures
Quantifying Proppant Transport for Complex Fractures in Unconventional Formations
Particularities of Hydraulic Fracturing in Dome-Type Reservoirs of Samara Area in the Volga-Urals Basin
Simultaneous Hydraulic Fracturing of Adjacent Horizontal Wells in the Woodford Shale
Novel Technology Replaces Perforating and Improves Efficiency During Multiple Layer Fracturing Operations
A Study of Fracture Initiation Pressures in Cemented Cased-Hole Wells Without Perforations
Semiphenomenological Model of Hydraulic Fracturing in Granular Media
Optimization of a Visco-Elastic Surfactant (VES) Fracturing Fluid for Application in High-Permeability Formations
Novel CO2-Emulsified Viscoelastic Surfactant Fracturing Fluid System Enables Commercial Production From Bypassed Pay in
Fracture Stimulation Utilizing a Viscoelastic-Surfactant-Based System in the Morrow Sands in Southeast New Mexico
Overcoming Excessive Fluid Loss in Tip-Screen-Out Stimulations of Depleted, High-Permeability Reservoirs Using a New-Gen

Water Control and Fracturing: A Reality
Water-Fracs: We Do Need Proppant After All
Hydraulic Fracturing With Heated Fluids Brings Success in High-Pour-Point Waxy-Oil Reservoir in India
Fracturing Technology for 4% Porosity Libya’s Reservoir: Application of Correct Diagnostic and Methodology to Optimize th
The Effects of Fracture Cleanup on the Productivity of Gas Condensate Systems
An Integrated Evaluation of Successful Acid Fracturing Treatment in a Deep Carbonate Reservoir Having High Asphaltene Con
New Results Improve Fracture Cleanup Characterization and Damage Mitigation
New Results Improve Fracture Cleanup Characterization and Damage Mitigation
Investigation of Cleanup Efficiency of Hydraulically Fractured Wells in Gas Condensate Reservoirs




New Results Improve Fracture Cleanup Characterization and Damage Mitigation
Optimizing the Completion of a Multilayer Cotton Valley Sand Using Hydraulic-Fracture Monitoring and Integrated Engineering
Comparative Analysis of Damage Mechanisms in Fractured Gas Wells
Borehole Deviation Surveys are Necessary for Hydraulic Fracture Monitoring
Hydraulic Fracture Diagnostics Used To Optimize Development in the Jonah Field
Evaluation of the Proppant-Pack Permeability in Fiber-Assisted Hydraulic Fracturing Treatments for Low-Permeability Formatio
Determining Realistic Fracture Conductivity and Understanding Its Impact on Well Performance—Theory and Field Examples
The Texture of Acidized Fracture Surfaces: Implications for Acid Fracture Conductivity
Complex Fracture Geometry Investigations Conducted on Western-Siberian Oilfields at Rosneft Company
A New Environmentally Acceptable Technique for Determination of Fracture Height and Width
Hydraulic Fracture Geometry Investigation for Successful Optimization of Fracture Modeling and Overall Development of Juras
Production Forecasting in a Limited-Data Environment: Evolving the Methodology in the Yamburgskoe Arctic Gas/Condensate
Correcting Underestimation of Optimal Fracture Length by Modeling Proppant Conductivity Variations in Hydraulically Fracture
Fracture Propagation in High-Permeability Rocks: The Key Influence of Fracture Tip Behavior
Acid Fracturing of Deep Gas Wells Using a Surfactant-Based Acid: Long-Term Effects on Gas Production Rate
Evaluation and Optimization of Low-Conductivity Fractures
Hydraulic Fracture Diagnostics In The Williams Fork Formation, Piceance Basin, Colorado Using
Surface Microseismic Monitoring Technology
Evidence of a Horizontal Hydraulic Fracture From Stress Rotations Across a Thrust Fault
Quantifying Non-Darcy Effects on the Productivity of a Cased-Hole Frac Pack (CHFP) Well
Prediction of Long-Term Proppant Flowback in Weak Rocks
Effect of Production Induced Stress Field on Refracture Propagation and Pressure Response
Hydraulic Fracturing and Filtration in Porous Medium
New Mechanical and Damage Skin Factor Correlations for Hydraulically Fractured Wells
Differential Cased Hole Sonic Anisotropy for Evaluation of Propped Fracture Geometry in Western Siberia, Russia
New Findings in Fracture Cleanup Change Common Industry Perceptions
New Findings in Fracture Cleanup Change Common Industry Perceptions

The Resiliency of�Frac-Packed Subsea Injection Wells
Eliminating the Poroelastic Problems Associated with Water Injection in the Kikeh Deep Water Development
Using Open and Cased Hole Sonic Anisotropy and Geomechanics Modeling for Hydraulic Fracturing Evaluation: A Case Study
Hydraulic Fracture Offsetting in Naturally Fractured Reservoirs: Quantifying a Long-Recognized Process
Well Productivity In North Sea Chalks Related To Completion And Hydraulic Fracture Stimulation Practices
Gas Condensate Relative Permeabilities in Propped Fracture Porous Media: Coupling Versus Inertia
Successful Acid-Fracturing in Adverse Conditions: Lessons Learnt and Integrated Evaluation in the Kharyaga Field
Massive Annular Fracturing Practices in BJC Gas Field, Sichuan, China
Deliverability of Gas-Condensate Reservoirs—Field Experiences and Prediction Techniques
Gas Coning Control for Smart Wells Using a Dynamic Coupled Well-Reservoir Simulator
Auto, Natural, or In-Situ Gas-Lift Systems Explained
A Critical Review of Completion Techniques for High-Rate Gas Wells Offshore Trinidad
Innovative Gas Shutoff Method Using Heavy Oil-in-Water Emulsion

Effect of Wettability on High-Velocity Coefficient in Two-Phase Gas/Liquid Flow
Delayed-Release Acid System for Cleanup of Al Khalij Horizontal Openhole Drains
The Effect of Well Trajectory on Horizontal Well Performance
Prudhoe Bay Study Of Horizontal Well Injectivity And Recommended Approach To Achieving Long Term Efficient Waterfloodin
Application of a Novel Open-Hole Horizontal Well Completion in Saudi Arabia
Successful Case History of a Novel Open-Hole Horizontal Well Completion in Saudi Arabia
A Case Study of Oil-Based Mud Effect on Horizontal-Well Productivity
A Case Study of Oil-Based Mud Effect on Horizontal-Well Productivity
Predicting Horizontal-Openhole-Completion Success on the North Slope of Alaska
Analyzing Underperformance of Tortuous Horizontal Wells: Validation With Field Data
Experience in AA-LDHI Usage for a Deepwater Gulf of Mexico Dry-Tree Oil Well: Pushing the Technology Limit
The Effect of Positive Coupling and Negative Inertia on Deliverability of Gas Condensate Wells
Cost-Effective Life-Cycle Profile Control Completion System for Horizontal and Multilateral Wells
Production and Injection Profiling Through Permanent-Downhole-Pressure-Gauge Recording During
a Coiled-Tubing-Conveyed Workover Operation
Flow Profiling by Distributed Temperature Sensor (DTS) System—Expectation and Reality
Improved Reservoir Management With Intelligent Multizone Water-Alternating-Gas (WAG) Injectors
and Downhole Optical Flow Monitoring
Slim Intelligent Completions Technology Optimize Production in Maximum Contact, Expandable Liner and Quad Laterals Comp
Na Kika Field Experiences in the Use of Intelligent Well Technology to Improve Reservoir Management
Inflow Control Devices: Application and Value Quantification of a Developing Technology
First Applications of Inflow Control Devices (ICD) in Open Hole Horizontal Wells in Block 15, Ecuador
Techniques for Optimum Placement of Interval Control Valve(s) in an Intelligent Well
Integrating ESPs with Intelligent Completions: Options, Benefits and Risks
Should “Proactive or “Reactive Control Be Chosen for Intelligent Well Management?


Maximizing Production Capacity Using Intelligent-Well Systems in a Deepwater, West-Africa Field
Intelligent Completions Technology Offers Solutions to Optimize Production and Improve Recovery in Quad–Lateral Wells in
Insurance Value of Intelligent Well Technology Against Reservoir Uncertainty
Laboratory Hydraulic Fracturing Test on a Rock With Artificial Discontinuities
Laboratory Hydraulic Fracturing Test on a Rock With Artificial Discontinuities
New Insights into Application of Foam for Acid Diversion
Modeling and CT-Scan Study of the Effect of Core Heterogeneity on Foam Flow for Acid Diversion
Modeling and CT-Scan Study of Foams for Acid Diversion
Guidelines for the Proper Application of Critical Velocity Calculations
A Combined Well Completion and Flow Dynamic Modeling for a Dual-Lateral Well Load-up
Investigation
On the Flow Performance of Velocity Strings To Unload Wet Gas Wells
A Novel Foamer for Deliquification of Condensate-Loaded Wells
Securing The Future In Mature Gas Fields
Prediction Onset and Dynamic Behaviour of Liquid Loading Gas Wells
Getting the Last Gasp: Deliquification of Challenging Gas Wells
Highly Successful Batch Application of Surfactant in North Sea Gas Wells
Gas-Well Liquid Loading From the Power Perspective
Automatic Concurrent Water Collection (CWC) System for Unloading Gas Wells

A New Method of Plunger Lift Dynamic Analysis and Optimal Design for Gas Well Deliquification
Investigation of Gas Carryover With a Downward Liquid Flow
An Acid-Placement Model for Long Horizontal Wells in Carbonate Reservoirs
The Use of a Fully Coupled Geomechanics-Reservoir Simulator To Evaluate the Feasibility of a
Cavity Completion
Managing Production in Maturing Assets: Increasing Intervention Success by Combining Production Logging With Nodal Analy
Forecasting the Productivity of Thinly Laminated Sands with a Single Well Predictive Model
Geomechanical Characterization of a Sandstone Reservoir in Middle East—Analysis of Sanding Prediction and Completion St
Effective Matrix Acidizing in Carbonate Reservoir—Does Perforating Matter?
Productivity Increase Using the Combination of Formation Isolation Valve and Dynamic Underbalanced Perforation
Coiled-Tubing Perforation and Zonal Isolation in Harsh Wellbore Conditions
Dynamic Underbalanced Perforating Application Increases Productivity in the Mature High-Permeability Gas Reservoirs of San
Limited Entry Perforations in HVO Recovery: Injection and Production in Horizontal Wells
Overbalanced Perforating Yields Negative Skins in Layered Reservoir
Optimized Perforation—From Black Art to Engineering Software Tool
Oriented Perforation in Dual Completion Wells: A Real Case in East Texas
Oriented Perforation in Dual Completion Wells: A Real Case in East Texas
New Perforating Technique Improves Well Productivity and Operational Efficiency

New Solution To Improve Perforation Penetration and Breakdown: San Jorge Field, Argentina Case
Histories
Propellant-Assisted Perforating—An Alternative Stimulation Solution in Heavily Karstified Carbonate Reservoirs
Propellant-Assisted Perforating—An Alternative Stimulation Solution in Heavily Karstified Carbonate Reservoirs
Quantifying Skin Variation for Underbalanced Perforating
Improved Method for Underbalanced Perforating With Coiled Tubing in the South China Sea


A Novel Technology for Through Tubing Perforation in Highly Deviated Wells Where Electric Line Is
Limited
Modeling Air and Water Perforator Swell for Better Risk Management
Novel Perforating Job Design Triples Well Productivity
Flow Performance of Perforation Tunnels Created With Shaped Charges Using Reactive Liner Technology
Overcoming Near Wellbore Damage Induced Flow Impairment with Improved Perforation Job Design and Execution Methods
Field-Data-Based Prediction of Well Productivity Decline Due to Sulphate Scaling
Injectivity Impairment Due to Sulfate Scaling During PWRI: Analytical Model
Fracture Propagation, Filter-Cake Buildup and Formation Plugging During PWRI
Predicting the Production Capacity During Underbalanced-Drilling Operations in Vietnam
Reduced Water Production and Increased Oil Production Using Smart Completions and MPFM Case Study""
Sand Control Completions for the Development of Albacora Leste Field
Innovative Use of Expandable Sand Screens Combined With Propped Hydraulic Fracturing Technology in Two Wells With Inte
Design and Implementation of a Sand-Control Completion for a Troublesome Shallow Laminated Gas Pay—A Case Study
Magnolia Deepwater Experience—Frac-Packing Long Perforated Intervals in Unconsolidated Silt Reservoirs
Magnolia Deepwater Experience--Frac Packing Long, Perforated Intervals in Unconsolidated Silt Reservoirs
TAML Level 3 tri-lateral with Sand Control application for Saudi Aramco
Deepwater Extended-Reach Sand-Control Completions and Interventions
Sanding Study for Deepwater Indonesia Development Wells: A Case History of Prediction and
Production
Screen Development to Withstand 4,000-psi Overbalance, Subhydrostatic Completion in Deepwater GOM Subsea Waterflood
Sandface Completion for a Shallow Laminated Gas Pay With High Fines Content
Lessons Learned on Sand-Control Failure and Subsequent Workover at Magnolia Deepwater Development
Lessons Learned on Sand-Control Failure and Subsequent Workover at Magnolia Deepwater Development
Novel Through Tubing Sand Control Solution for Failed Gravel Pack - Alpha Well - 4L Case Study
Sand Control Completion Failures: Can We Talk the Same Language?
Development Strategies of Soft-Friable Carbonate Gas Reservoirs Through Horizontal Open Hole Gravel Packed Completions
Greater Plutonio Openhole Gravel-Pack Completions: Fluid Design and Field Applications
High-Angle Well Deliverability Modeling for Openhole Gravel-Pack Completion Under Ultrahigh Gas
Rate
Horizontal Open Hole Gravel Pack Placement Requirements in Selective Completion Projects
A Comparison of Design Placement Methodologies for Horizontal Open Hole Gravel Pack in Multizone Completion Projects
A Step Change in Openhole Gravelpacking Methodology: Drilling-Fluid Design and Filter-Cake Removal Method
Greater Plutonio Openhole Gravel-Pack Completions: Fluid Design and Field Applications
Complex Through-Tubing Gravel-Pack Operation Increases Production on a Well in the Heidrun Field: A Case Study
Openhole Gravel Packing With Exposed Shales: Waterpack Case Histories From Underground Gas Storage Wells in Italy
Gravel Packing Long Openhole Intervals With Viscous Fluids Utilizing High Gravel Concentrations: Toe-to-Heel Packing Witho
Single Trip Multi-Zone Gravel Packing—Case Study at Handil, Bekapai & Sisi-Nubi Fields
Openhole Gravel Pack in the Roaring Forties for TOTAL AUSTRAL
Integrated Approach to Modeling Gravel Packs in Horizontal Wells
Openhole Gravel Packing With Oil-Based Fluids: Implementation of the Lessons Learned From Past Experiences Leads to the


Critical Conditions for Effective Sand-Sized Solids Transport in Horizontal and High-Angle Wells
First Application of Novel Microemulsion Technology for Sand Control Remediation Operations-A Successful Case History From
Effective Perforating and Gravel Placement: Key to Low Skin, Sand Free Production in Gravel Packs
Effective Perforating and Gravel Placement: Key to Low Skin, Sand-Free Production in Gravel Packs
Prediction of Sanding Using Oriented Perforations in a Deviated Well, and Validation in the Field
Determination of Optimum Perforation Design and Sanding Propensity in Long Horizontal Wells Based on Modified RP 19B Se

A Novel Technique for Determining Screen Failure in Offshore Wells: A GOM Case History
ICD Screen Technology in Stag Field to Control Sand and Increase Recovery by Avoiding Wormhole Effect

Screenless Completions as a Viable Through-Tubing Sand Control Completion
Screenless Completions as a Viable Through-Tubing Sand Control Completion
The Search for Alternative to Screen: Is Permeable Cement a Viable Option?

Evaluation of Sand-Control Completions in the Duri Steamflood, Sumatra, Indonesia
Evolution of Sand Control Completion Techniques in the South Tapti Field
Sand Quantification: The Impact on Sandface Completion Selection and Design, Facilities Design and Risk Evaluation
Sand Control Robustness in a Deepwater Development: Case Histories From Girassol Field (Angola)
Sand Erosion in Weakly Consolidated Reservoirs: Experiments and Numerical Modeling
Cleaning Large-Diameter Proppant in Low-Bottomhole Pressure, Extended-Reach Wells With Concentric Coiled Tubing Vacuu
Field and Laboratory Observations of Post-Failure Stabilizations During Sand Production
Applying Sand Management Process on the Lunskoye High Gas-Rate Platform Using Quantitative Risk Assessment
Case Study: The Application of a Sand Management Solution for the Sarir Field in Libya
Use of Reservoir Formation Failure and Sanding Prediction Analysis for Viable Well-Construction and Completion-Design Optio
Practical Approach to Achieve Accuracy in Sanding Prediction
Practical Approach to Achieve Accuracy in Sanding Prediction
Sanding—Not As It First Appeared
Sanding—Not As It First Appeared
Effect of Water Cut on Sand Production—An Experimental Study
Effect of Water Cut on Sand Production—An Experimental Study
Sanding: A Rigorous Examination of the Interplay Between Drawdown, Depletion, Startup Frequency, and Water Cut
Sanding: A Rigorous Examination of the Interplay Between Drawdown, Depletion, Startup Frequency, and Water Cut
Controls of Coal Fabric on Coalbed Gas Production and Compositional Shift in Both Field
Production and Canister Desorption Tests
Comprehensive Transient Modeling of Sand Production in Horizontal Wellbores
Comprehensive Transient Modeling of Sand Production in Horizontal Wellbores
Bokor--A New Look at Sand Production in a Mature Field
Case Study: Restoring Sand-Prone Subsea Wells to Production
Sand-Production Prediction: A New Set of Criteria for Modeling Based on Large-Scale Transient Experiments and Numerical In
Sand-Production Prediction: A New Set of Criteria for Modeling Based on Large-Scale Transient
Experiments and Numerical Investigation
Prediction of Sand Production Rate in Oil and Gas Reservoirs: Importance of Bean-Up Guidelines
Influence of Rock Failure Characteristics on Sanding Behavior: Analysis of Reservoir Sandstones from the Norwegian Sea
An Integrated Wellbore Stability and Sand-Production Prediction Study for a Multifield Gas Development
Development of Appropriate Test Methodologies for the Selection and Application of Lead and Zinc Sulfide Inhibitors for the El
Development and Implementation of a Scale-Management Strategy for Oseberg S�r
Assessment of Total Skin Factor in Perforated Wells
A New Skin-Factor Model for Perforated Horizontal Wells
Lessons Learned From Using Viscoelastic Surfactants in Well Stimulation
Recent Acid-Fracturing Practices on Strawn Formation in Terrell County, Texas
Small-Scale Fracture Conductivity Created by Modern Acid-Fracture Fluids
Recent Acid-Fracturing Practices on Strawn Formation in Terrell County, Texas
Field Trial of a New Non-Damaging Degradable Fiber-Diverting Agent Achieved Full Zonal Coverage during Acid Fracturing in a
Successful Application of Innovative Fiber-Diverting Technology Achieved Effective Diversion in Acid Stimulation Treatments in
Use of Viscoelastic-Surfactant-Based Diverting Agents for Acid Stimulation: Case Histories in GOM
First North Sea Application of Pinpoint-Stimulation Technology to Perform a Rig-Based Acid Fracture Treatment Through CT


Diversion and Cleanup Studies of Viscoelastic Surfactant-Based Self-Diverting Acid

Use of Novel Acid System Improves Zonal Coverage of Stimulation Treatments in Tengiz Field

A New Efficiency Criterion for Acid Fracturing in Carbonate Reservoirs
Acid Fracturing of Gas Wells by Use of an Acid Precursor in the Form of Solid Beads: Lessons Learned From First Field Applic
Use of Novel Acid System Improves Zonal Coverage of Stimulation Treatments in Tengiz Field
Optimization of Acid Stimulation for a Loosely Consolidated Brazilian Carbonate Formation--Multidisciplinary Laboratory Asses
A Novel Stimulation Technique for Horizontal Openhole Wells in Carbonate Reservoirs--A Case Study in Kuwait
Sandstone Matrix Stimulation Can Improve Brownfield Oil Production When the Chemistry and Procedures Are Correct
Development and Field Application of a New Hydrogen Sulfide Scavenger for Acidizing Sour-Water Injectors
Successful Stimulation of Thick, Naturally-Fractured Carbonates Pay Zones in Kazakhstan
Matrix Acidizing of Carbonate Reservoirs Using Organic Acids and Mixture of HCl and Organic Acids
An Innovative Acid Stimulation Technique for Reviving Dead Wells in the Ghawar Field of Saudi Arabia - A Holistic Approach
A New Technical Standard Procedure To Measure Stimulation and Gravel-Pack Fluid Leakoff Under Static Conditions
An Alternative Solution to Sandstone Acidizing Using a Nonacid Based Fluid System With Fines-Migration Control
Combining Acid- and Hydraulic-Fracturing Technologies Is the Key to Successfully Stimulating the Orito Formation
Chemical Diversion Techniques Used for Carbonate Matrix Acidizing: An Overview and Case Histories
Foam Fracturing: New Stimulation Edge in Western Siberia


Chemical Stimulation of Gas/Condensate Reservoirs
The Effect of Pore-Scale Heterogeneities on Carbonate Stimulation Treatments
Optimizing Diversion and Pumping Rate to Effectively Stimulate Long Horizontal Carbonate Gas Wells
Sensitivity Study on the Main Factors Affecting a Polymeric RPM Treatment in the Near-Wellbore Region of a Mature Oil-Produ
Restimulation: Candidate Selection Methodologies and Treatment Optimization
New Viscoelastic Surfactant Fracturing Fluids Now Compatible With CO2 Drastically Improve Gas
Production in Rockies
Case Study: Application of a Viscoelastic Surfactant-Based CO2 Compatible Fracturing Fluid in the Frontier Formation, Big Hor
New Viscoelastic Surfactant Fracturing Fluids Now Compatible With CO2 Drastically Improve Gas Production in Rockies
Optimized Stimulation Solutions for a Mature Field in Kazakhstan
A New Solution to Restore Productivity of Gas Wells With Condensate and Water Blocks
Wettability Alteration in Gas-Condensate Reservoirs to Mitigate Well Deliverability Loss by Water
Blocking
Preventive Treatment for Enhancing Water Removal from Gas Reservoirs by Wettability Alteration
Preventive Treatment for Enhancing Water Removal from Gas Reservoirs by Wettability Alteration
High-Water-Cut Wells Stimulation Combined Viscoelastic Surfactant
Real-Time Water Detection and Flow Rate Tracking in Vertical and Deviated Intelligent Wells with Pressure Sensors
Downhole Flow Control For High Rate Water Injection Applications
Downhole Flow Control For High Rate Water Injection Applications
Water Hammer Effects on Water Injection Well Performance and Longevity
Comparison of Vertical, Slanted, and Horizontal Wells Productivity in Layered Gas-Condensate Reservoirs
Improved Wellbore Delivery in a Deepwater Reservoir via the aid of Logging-While-Drilling Imaging and Formation Pressure Da
Reliability of Cement Bond Log Interpretations Compared to Physical Communication Tests Between Formations
Reliability of Cement Bond Log Interpretations Compared to Physical Communication Tests Between Formations
                                Author                                       Abstract
                                                                           Abstract A successful acid stimulation campaign w
N. Al-Araimi, SPE, Brunei Shell Petroleum Co. Sdn. Bhd. and L. Jin, SPE, Shell Intl. E&P
                                                                           Abstract
J.M. Mazel and H. Poitrenaud, Total E&P, and P. M’Bouyou, Total E&P Congo N’Kossa is an offshore field located 6
F.F. Chang, SPE, and M. Abbad, Schlumberger                                Abstract The chemical nature of carbonate rocks m
                                                                           Abstract The Electrical Sudhakar Khade, SPE, Sc
Ahmed R. Al Zahrani, SPE, Redha H. Al-Nasser, SPE, and Timothy W. Collen, SPE, Saudi Aramco; Submersible Pump (ESP)
                                                                           Abstract Formation powered jet pumps (FPJP)
J.W. Peirce, SPE, J.A. Burd, G.L. Schwartz, ConocoPhillips Alaska, Inc., and T.S. Pugh, SPE, Weatherford International we

Francis Nwaochei, SPE; Adebayo Olufemi, SPE; Vincent Eme, SPE; and
John Ibrahim, SPE, Chevron Nigeria Limited; Eseoghene Nakpodia, SPE,
and Wole Areo, SPE, Flostar Oil & Gas Nigeria Limited                      Abstract Application of improved Oil Recovery in m
Peter O. Oyewole, SPE, BP, and James F. Lea, SPE, PL Tech LLC              Abstract The Natural Gas industry is often faced w
T.C. Handfield, T. Nations, S.G. Noonan; ConocoPhillips                    Abstract Gas lift completions for SAGD1 producers
                                                                           SPE, Schlumberger
F. Gaviria, SPE, SUNCOR, and R. Santos, SPE, O. Rivas, SPE, and Y. Luy,Abstract The need for high-temperature electric su
Siddhartha Gupta, Schlumberger                                             Abstract Artificial lift systems are now being consid
                                                                           Abstract Effective Edinburgh, during well start-up
D.K. Olowoleru, K.M. Muradov, F.T. Al-Khelaiwi and D.R. Davies; SPE, Heriot-Watt University, well cleanupU.K.
                                                                           Abstract Advances (from conventional wells to Da
F.T. Al-Khelaiwi, SPE, and V.M. Birchenko, SPE, Heriot-Watt University; M.R. Konopczynski, SPE, WellDynamics; and D.R. ho
                                                                           Abstract The Bayu-Undan gas recycling project is l
L. B. Ledlow, W. W. Gilbert, N. P. Omsberg, G. J. Mencer and D. P. Jamieson, ConocoPhillips
Alain BOURGEOIS, Sebastien BOURGOIN, and Pierre PUYO, TOTAL AUSTRAL        Abstract This paper outlines and discusses the iss

C.S. Kabir, SPE, Chevron Energy Technology Co.; M.-M. Chang, SPE,
Chevron Intl. E&P; and O. Taghizadeh, SPE, U. of Texas at Austin            Summary This paper explores multiple completion
                                                                            Abstract BP Trinidad and Tobago B. Lanclos and
S.D. Cooper, S. Akong, K.D. Krieger, A.J. Twynam, F. Waters, and R. Morrison, BP; G. Hurst, Consultant; and(bpTT) has been
                                                                            Abstract SPE, Anna Zubareva, Andrey Vasiliev, Y
Sergey Ryzhov, SPE, Vladimir Malyshev, SPE, Shlumberger, and Tatyana Kruchkova,The Sporyshevskoye oil field developmen
                                                                            Abstract The offshore northeast Brazil Barbedo, S
A. Calderon, SPE, A.F. Arag�o, SPE, and C.M. Chagas, SPE, PETROBRAS, and C. Guimar�es, SPE, and R. Manati field
Guillermo Pitrelli and Maximiliano Giraldo, Repsol-YPF                      Abstract Concepts on well multiple zone completio
Gary Rytlewski, Schlumberger                                                Abstract A new method of completing multiple-laye
                                                                            Abstract Cartojani is a mature oil field with deplete
Surej Subbiah/Schlumberger; Wielemaker.E/Schlumberger; Joia P/Petrom SA; Hopper.L/Schlumberger; Fernandez LI/Schlum
                                                                             Services Co.; and S. Imie, SPE, U. of environmen
J. Arukhe, SPE, Petro-Canada; L. Nwoke, SPE, Shell; C. Uchendu, SPE, BJAbstract Within the Niger Delta clastic Stavanger
                                                                            Summary This A. Nasr-El-Din,* the effects of Ca2
Mason B. Tomson, Amy T. Kan, Gongmin Fu, and Dong Shen, Rice University; and Hisham paper discusses SPE, Hamad Al-S
B.D. Poe Jr., SPE, Schlumberger                                             Abstract This paper presents the results of an inve
B.D. Poe Jr., SPE, Schlumberger                                             Abstract This paper presents the results of an inve
M. Kabir, KOC; S. Ingham, Schlumberger; D. Sibley, K. Osman, A.K.
Ambastha, and M. Anderson, Chevron; and B. Rahman, KOC                      Abstract Mauddud reservoir in the Greater Burgan
                                                                            Abstract Mauddud reservoir in the Greater Burgan
M. Kabir, KOC; S. Ingham, Schlumberger; D. Sibley, K. Osman, A.K. Ambastha, and M. Anderson, Chevron; and B. Rahman, K
                                                                            Abstract The lower Minghuazhen is a shallow-wat
Liu Song, Li Jianping, and Lv Dingyu, CNOOC, and Jeffrey Kok and Shim Yen Han, Schlumberger
Yang Qing and D.R. Davies, Heriot Watt University                           Abstract This paper presents an advanced control
                                                                            Shafiq, This paper describes a case-study detaili
S.M. Mubarak, T.R. Pham, and S.S. Shamrani, SPE, Saudi Aramco, and M. AbstractSPE, Schlumberger
T.S. Ramakrishnan, Schlumberger-Doll Research                               Summary Poor displacement efficiency in hydroca
                                                                            Shafiq, SPE, Schlumberger
S.M. Mubarak, T.R. Pham, and S.S. Shamrani, SPE, Saudi Aramco, and M. Summary This paper describes a case study that
                                                                             E&P (SIEP); and J.-D. Jansen, SPE, DUT and SIE
M.M.J.J. Naus, SPE, Delft U. of Technology (DUT); N. Dolle, SPE, Shell Intl.Summary We developed an operational strategy f
                                                                            Abstract The number of multilateral Kharrat, SPE
Jose R. Amorocho, J. Ricardo Solares, Abdulmohsin Al-Mulhim, and Ali Al-Saihati, SPE, Saudi Aramco; Wassim gas producers
                                                                            Abstract Current A. Ayyad, SPE, Schlumberger; a
Mohammed M. Amro, SPE, and Mohamed S. Benzagouta, SPE, King Saud University; Hazim drilling technology is moving towa
                                                                             A. Restrepo, SPE, stimulation treatments based
G.A. Alzate, SPE, U. Nacional de Colombia-Medellin; C.A. Franco, SPE, andAbstract The use ofBP Colombia; and D.L. Barret
B.�. Bringedal, S.A. Morud, and N.A. Hall, ABB, and G. Huseman, Shell Abstract Waterflood injection on the Shell Bonga f
                                                                            Abstract Inflow control devices which Laidlaw, Ba
A. McIntyre, SPE, Marathon Oil U.K. Ltd.; R. Adam, SPE, Amerada Hess Denmark; and J. Augustine, SPE, and D. prevent ear
                                                                            Summary Relatively University
D.R. Davies, SPE, R. Narayanasamy, SPE, B. Kristensen, and J.M. Somerville, SPE, Heriot-Watt few field installations of a dua
                                                                            Summary Relatively University
D.R. Davies, SPE, R. Narayanasamy, SPE, B. Kristensen, and J.M. Somerville, SPE, Heriot-Watt few field installations of a dua
                                                                            Abstract The Cannonball Field is a one Tcf gas con
J.C. Healy, Consultant, John Martin, BP plc, Brenton McLaury, University of Tulsa, and Raynald Jagroop, BP Trinidad and Toba
J. Jaua and O. Rivas, SPE, Schlumberger, and A. Mej�as, Repsol YPF Abstract As a result of the increasing emphasis on
                                                                               Summary A rigorous statistical methodology using
W.J. Bailey, SPE, Schlumberger-Doll Research; I.S. Weir, U. West of England; B. Cou�t, SPE, Schlumberger-Doll Research
                                                                               Summary A rigorous statistical methodology using
W.J. Bailey, SPE, Schlumberger-Doll Research; I.S. Weir, U. West of England; B. Cou�t, SPE, Schlumberger-Doll Research
                                                                                and J. Hallman, has proved International
Z. Chen , M. Duan, S.Z. Miska, M. Yu, and R.M. Ahmed, University of Tulsa;Summary Foam Weatherfordto be effective and ec
Yula Tang, Chevron Energy Technology Co.; Turhan Yildiz and Erdal
Ozkan, Colorado School of Mines; and Mohan Kelkar, U. of Tulsa                 Abstract Slotted-liner is a relatively simple and cos
                                                                               Abstract Acid Fracturing has been a successful m
F.O. Garzon, H.M. Al-Marri, J.R. Solares, and C.A. Franco Giraldo, SPE, Saudi Aramco, and V. Ramanathan, SPE, Schlumber
                                                                               Abstract The SPE, field located on the North Slop
Tim S. Schneider, David O. Uldrich, and Richard Hodge, ConocoPhillips Co.; Bob Barree, AlpineBarree�& Assocs.; and Mich
                                                                               Abstract The SPE, field located on the North Slop
Tim S. Schneider, David O. Uldrich, and Richard Hodge, ConocoPhillips Co.; Bob Barree, AlpineBarree�& Assocs.; and Mich
                                                                               Summary This
C.L. Cipolla, Pinnacle Technologies; and K.K. Hansen and W.R. Ginty, Amerada Hess A/S paper details the results for 33 pro
                                                                               Summary The primary purpose of surfactants CE
J. Paktinat, J.A. Pinkhouse, and C. Williams, Universal Well Services Inc.; G.A. Clark, Phillips Production; and G.S. Penny, use
                                                                               Abstract T. Vizurraga, Schlumberger
A. Powell, Headington Oil Co., O. Bustos, W. Kordziel, T. Olsen, D. Sobernheim, and Since the horizontal lateral Bakken dolom
                                                                               and Albert Gayfullin, SPE, Dmitry Senchenko, and
D. Oussoltsev, SPE, K. K. Butula, SPE, and A. Klyubin SPE, Schlumberger, Abstract Successful hydraulic fracturing in various
                                                                               Abstract Saudi Aramco, and Venkateshwaran Ar
Maytham I. Al-Ismail, SPE, Moataz M. Al-Harbi, SPE, and Abdulaziz K. Al-Harbi, SPE,Acid fracturing has been part of Saudi Ra
                                                                               Abstract This paper Oussoltsev, SPE, and K.K. B
S. Sitdikov, SPE, A. Serdyuk, and A. Nikitin, SPE, Rosneft, and A.Yudin, SPE, K. Mullen, SPE, D.describes successful impleme
                                                                               Abstract This paper discusses the application of fib
Matthew Law, George W. Chao, Hafeez A. Alim, Ahmad F. Hashim, Elsamma Samuel, and Mathew Samuel, Schlumberger W
                                                                               Abstract Flowback aids are usually Dismuke, CES
Paul R. Howard, Sumitra Mukhopadhyay, Nita Moniaga, Laura Schafer, Schlumberger, and Glenn Penny, Keith surfactants or c
Hongren Gu, SPE, and Eduard Siebrits, SPE, Schlumberger                        Summary Much study has been conducted on the
Lloyd Simms III and Brad Clarkson, Halliburton, and Gilbert Navaira,
Chevron                                                                        Abstract With Gulf of Mexico (GOM) hydrocarbon d
                                                                               Abstract Natural gas reservoir development Shen
Daren Bulat, SPE, Talisman Energy Inc., and Yiyan Chen, Matthew K. Graham, Richard Marcinew, Goke Adeogun, Jackcontin
S.M. Rimassa, SPE, P.R. Howard, SPE, and K.A. Blow, SPE, SchlumbergerAbstract As mature fields produce larger quantities
                                                                               Abstract An optimized design for hydraulic fracturi
H. Mahdiyar, Shiraz University, and M. Jamiolahmady and M. Sohrabi, Heriot-Watt University
                                                                               Abstract The key and Tarik Itibrout, tight-gas field
Bilu Cherian, SPE, Schlumberger; Kirk Fields, SPE, and Seth Crissman, SPE, ConocoPhillips; to the success of aSPE, and Mal
                                                                               Abstract Frac-pack is a pervasively used completi
O. Hidalgo, Schlumberger Well Services; O. Gonz�lez and V. Gonz�lez, PDVSA; and A. S�nchez, and A. Pe�a, Sch
                                                                               Abstract
A.V. Yudin and K.K. Butula, Schlumberger, and Y.V. Novikov, OAO Tomskneft VNK The productive pay of the low permeability
                                                                                Dean Prather, Halliburton
M.Y. Soliman, Reinhard Pongratz, Halliburton; Martin Rylance, TNK-BP; andAbstract Fracturing has become a viable and impo
                                                                               Abstract In the recent years Liu, SPE, Redha Kelk
Majdi Al Mutawa, SPE, Bader Al Matar, SPE, and Yousef Abdul Rahman, SPE, Kuwait Oil Company; Haihorizontal well technol
                                                                               Abstract BJ Aguada
Raul Sanchez, Regis Agut, and David Coulon, Total Australia, and Roberto Sentinelli,The Services Pichana field is located in the
                                                                               Abstract A Malonga, SPE, Eni Congo
R. Arangath, SPE, Schlumberger, and J.F. Obamba, SPE, P. Saldungaray, SPE, and H. common scenario in many mature oilf
                                                                               Abstract Apache; Fabio Pe�acorada, YPF; ge
Pedro Saldungaray, Schlumberger; Efrain Huidobro Salas, Pemex; Sebastian Vargas,Latin America hasn’t escaped theJos
                                                                               Abstract Many West Cantaloube, SPE, Schlumber
Alberto Casero, SPE, and Giamberardino Pace, SPE, Eni E&P; Brad Malone, SPE, and Francois Africa offshore fields are matu
                                                                               Abstract One Aramco; strategies in Saudi Aramc
J.R. Solares, SPE, C.A. Franco, SPE, H.M. Al-Marri, SPE, and H.A. Al-Jubran, SPE, Saudi of the keyVenkateshwaran Ramana
                                                                               Alexandru Dragomir, SPE, and Viorel Ghita, Petro
Tomislav Bukovac, Rafik Belhaouas and Daniel Perez, SPE, Schlumberger; Abstract Offshore operations are extremely expens
                                                                               Alexandru Dragomir, System, Executed extremely
                                                                                           Free offshore operations are from OM
Tomislav Bukovac, Rafik Belhaouas and Daniel Perez, SPE, Schlumberger; Abstract Current FluidSPE, Petrom member ofa Su
                                                                               Summary SIAM; Alexey G. Zagurenko, SPE, Ros
Andrey V. Dedurin, TNK-BP; Vadim A. Majar, Gazpromneft; Andrey A. Voronkov, SPE, Non-Darcy and multiphase flow effects
Andrey V. Dedurin, TNK-BP; Vadim A. Majar, Gazpromneft; Andrey A.
Voronkov, SPE, SIAM; Alexey G. Zagurenko, SPE, Rosneft; and Alexander
Y. Zakharov, SPE, Terry Palisch, SPE, and M.C. Vincent, SPE, Carbo
Ceramics                                                                       Summary Non-Darcy and multiphase flow effects
                                                                               Summary SIAM; Alexey G. Zagurenko, SPE, Ros
Andrey V. Dedurin, TNK-BP; Vadim A. Majar, Gazpromneft; Andrey A. Voronkov, SPE, Non-Darcy and multiphase flow effects
                                                                               Rohit Panse, Ikhsan Nugraha, Pankaj Taneja bro
Rajiv Sagar, Schlumberger; A.K. Pandey, Durga Prasad, A.K. Vinod ONGC, Abstract Gandhar is one of ONGC’s majorSch
B.D. Poe Jr., SPE, Schlumberger, and J.F. Marique, SPE, Consultant             Abstract This paper presents the results of an inve
T.N. Olsen, T.R. Bratton, and M.J. Thiercelin, Schlumberger                    Abstract Since the widespread proliferation micro-
                                                                               Abstract The majority of hydraulic fracturing work
A.N. Parfenov, SPE, S.S. Sitdikov, SPE, O.V. Evseev, SPE, and V.A. Shashel, Rosneft, and K.K. Butula, SPE, Schlumberger
                                                                               Abstract Hydraulic fracturing of horizontal wells in
George Waters, Barry Dean, and Robert Downie, Schlumberger, and Ken Kerrihard, Lance Austbo, and Bruce McPherson, Co
G. Rytlewski and J. Lima, Schlumberger, and B. Dolan, Petrogulf                Abstract A new method of completing multiple laye
G.L. Rytlewski and J.M. Cook, Schlumberger                                     Abstract A new method of completing multiple-lay
Olga Alekseenko, Schlumberger                                                  Abstract Petroleum engineers have faced the prob
                                                                               Schlumberger, and D. Surfactant (VES) fluids are
P.F. Sullivan, B. Gadiyar, R.H. Morales, R. Hollicek, D. Sorrells, and J. Lee, Abstract Visco-ElasticFischer, Remington Oil and
                                                                               Abstract A F.A. carbon Y. Chen, J.W. emulsifi
M.E. Semmelbeck, W.E. Deupree, and J.K. von Plonski, SPE, Escondido Resource, andnovel Mueller,dioxide- (CO2-)Lewis, L.
                                                                               Abstract This paper discusses the selection A. Bu
Vibhas J. Pandey and Tarik Itibrout, SPE, Schlumberger; Larry S. Adams, SPE, Chevron; and Tracy L. Cowan and Oscarcriteri
                                                                         Abstract Tip-Screen-Out and M. Mill�n, PDVSA
                                                                                     Permeability Reservoirs Using a of Flu
                                                                                                 Generation Viscoelastic hig
P. Parra, E. Miquilena, A. S�nchez, and A. Pe�a, Schlumberger Well Services, and A. Garc�a(TSO) stimulationsNew
M. Mahajan, SPE, and N. Rauf, SPE, BJ Services; T. Gilmore, SPE,
Chevron; and A. Maylana, SPE, Pertamina                                  Abstract Water production in mature fields is a com
                                                                         Abstract The key objective of hydraulic fracturing i
L.K. Britt and M.B. Smith, NSI Technologies; Z. Haddad and P. Lawrence, Devon Energy Co.; S. Chipperfield, Santos Corp.; an
                                                                         Summary Most existing production of waxy oils oc
                                                                                     Oil Reservoir in India
Josef Shaoul, SPE, and Winston Spitzer, SPE, Pinnacle Technologies, and Michael Ross, Stuart Wheaton , SPE, Paul Maylan
                                                                         Abstract Offshore
Areiyando Makmun, Schlumberger, and Fathi Issa and Gadalla Hameed, Sirte Oil Company A drilling program on North Rag
                                                                         Abstract The performance
M. Jamiolahmady, D. Ganesh, M. Sohrabi, and A. Danesh, Petroleum Engineering Inst., Heriot-Watt U. of fracturing treatments
                                                                         Abstract Kuwait Oil presents the process of candid
Qasem Dashti, SPE, Mir Kabir, SPE, Raju Vagesna, SPE, Feras Al-Ruhaimani, SPE, This paper Company, and Hai Liu, SPE, S
                                                                         Abstract It is well documented in C.N. Emiliani, S
J.A. Ayoub, SPE, and R.D. Hutchins, SPE, Schlumberger; F. Van der Bas, SPE, Shell; S. Cobianco, SPE, andthe literature that
                                                                         Abstract It is well documented in C.N. Emiliani, S
J.A. Ayoub, SPE, and R.D. Hutchins, SPE, Schlumberger; F. Van der Bas, SPE, Shell; S. Cobianco, SPE, andthe literature that
P. Ghahri, M. Jamiolahmady, and M. Sohrabi, Heriot Watt University       Abstract In tight gas reservoirs gas well production

J.A. Ayoub, SPE, and R.D. Hutchins, SPE, Schlumberger; F. Van der Bas,
SPE, Shell; S. Cobianco, SPE, and C.N. Emiliani, SPE, Eni; M. Glover,
SPE, BP America Inc.; S. Marino, SPE, Schlumberger; G. Nitters, SPE,
Shell; D. Norman, SPE, Chevron, and G. Turk, SPE, BP America Inc.           Abstract It is well documented in the literature that
                                                                            Abstract Microseismic hydraulic fracture Brook, an
Jason Baihly, Schlumberger; Andrew Coolidge and Steven Dutcher, Devon; and Ruben Villarreal, Mike Craven, Keith monitorin
                                                                            Abstract Productivity impairment in
Torsten Friedel, George Mtchedlishvili, Aron Behr, Hans-Dieter Voigt, and Frieder H�fner, Freiberg Universitytight-gas forma
                                                                            Summary Geophysical Inst. of the Academy azim
P. Bulant, Charles U.; L. Eisner, Schlumberger Cambridge Research; I. PšenĿ�k, Significant errors in the calculated of Sc
                                                                            SPE, and T.J. Young, SPE, on America; and M.J.
S.L. Wolhart, SPE, Pinnacle Technologies; T.A. Harting, SPE, J.E. Dahlem, Abstract This paper reports BP a study conducted
                                                                            Abstract To achieve maximum production tight-g
                                                                                        Permeability SPE, Schlumberger
M.N. Bulova, SPE, A.N. Cheremisin Jr., SPE, K.E. Nosova, SPE, J.T. Lassek, SPE, and D. Willberg,Formations
                                                                             Lucas Bazan, SPE, Harmon J. Heidt, SPE, and la
Terry Palisch, SPE, and Robert Duenckel, SPE, CARBO Ceramics Inc., and Abstract To hydraulically fracture a well requiresGe
C. Malagon, SPE, M. Pournik, SPE, and A.D. Hill, SPE, Texas A&M University  Summary In an acid-fracturing treatment fracture
A. Nikitin and A. Shirnen, Rosneft, and J. Maniere, Schlumberger            Abstract The generalization of Hydraulic fracturing
                                                                            Abstract For years radioactive tracers have been
R.R. McDaniel, SPE, and J.F. Borges, SPE, Hexion Specialty Chemicals, and S.S. Dakshindas, SPE, Marathon Oil Corporation
                                                                            Abstract The focus of our research is SPE, and G
Alexey Nikitin, SPE, Rosneft-Yuganskneftegaz; Alexey Yudin, SPE, Schlumberger; and Ilyas Latypov, Azat Haidar, on a remote
                                                                            Abstract Though there are many proven ways of p
Y. Shumakov, A.A. Burov, and K.K. Butula, SPE, Schlumberger, and I.A. Zynchenko, Gazprom
A.H. Akram, SPE, and A. Samad, SPE, Schlumberger                            Abstract A study was carried out to forecast the p
                                                                             E.M. Chekhonin, Schlumberger the tip of a hydrau
V.M. Entov, Inst. for Problems in Mechanics, Russian Academy of Sciences;Abstract Pressure distribution at Moscow Researc
                                                                            Abstract H. Al-Ghadban, V. Ramanathan, S. Kelk
H.A. Nasr-El-Din, SPE, S. Al-Driweesh, SPE, and K. Bartko, SPE, Saudi Aramco, and The deep tight carbonate formations in S
                                                                            Abstract This
J.F. Manrique, SPE, Occidental Oil and Gas Corp., and B.D. Poe Jr., SPE, Schlumberger paper presents the results of an inve
David Abbott, Chris Neale, and James Lakings, Microseismic Inc., and
Lynn Wilson, Jay C. Close, and Evan Richardson, Chevron                     Abstract A surface microseismic array was utilized
                                                                            Summary Microseismic imaging of a hydraulic-fra
S.C. Maxwell, U. Zimmer, R. Gusek, and D. Quirk, Pinnacle Technologies Canada
Liang-Biao Ouyang, SPE, Chevron Energy Technology Company                   Abstract Well completion plays a critical role in the
                                                                            Abstract Proppant flowback is an extremely import
G.R. Aidagulov and M. Thiercelin, Schlumberger, and V.N. Nikolaevskiy, S.M. Kapustyanskiy, and A.G. Zhilenkov, Inst. of Phys
X. Weng and E. Siebrits, Schlumberger                                       Abstract In this work the propagation of an orthogo
                                                                            Abstract The practical problem arises in enhancin
Smirnov N.N., Kisselev A.B., Nikitin V.F., and Zvyaguin A.V., Moscow M.V. Lomonosov State U.; Thiercelin M. SRE, Schlumbe
H. Mahdiyar, M. Jamiolahmady, and A. Danesh, Heriot-Watt U.                 Abstract Hydraulic fracturing is one of the most com
                                                                            Abstract Kalyanaraman, and S. Tcherkashnev, S
A. Nikitin and A. Pasynkov, Rosneft YNG, and G. Makarytchev, J. Maniere, R. SunderIn a waterflooded reservoir hydrocarbon
                                                                            Abstract S. Cobianco, SPE, and C.N. Emiliani, S
J.A. Ayoub, SPE, and R.D. Hutchins, SPE, Schlumberger; F. van der Bas, SPE, Shell;This paper summarizes part of the resul
                                                                            Abstract S. Cobianco, SPE, and C.N. Emiliani, S
J.A. Ayoub, SPE, and R.D. Hutchins, SPE, Schlumberger; F. van der Bas, SPE, Shell;This paper summarizes part of the resul

R.A. McCarty, SPE, Chevron IE&P, and W.D. Norman, SPE, Chevron ETC Abstract This paper documents the utilization of fr
                                                                          Abstract Kikeh Field is a Ivan Munoz, Hugo Morale
Tamara Webb, Jusni Omar, Murphy Oil Corporation, Saifon Daungkaew, Lee Chin Lim, Ray Tibbles, deepwater project located
                                                                          Abstract Hydraulic fracturing plays a
Almeida, C.M.C. de, Schlumberger; Melo, R.L.C., Petrobras; Holzberg, B. B.; Guimaraes, C., SPE, Schlumberger very importan
                                                                           Schlumberger RTC UG
R.G. Jeffrey and X. Zhang, SPE, CSIRO Petroleum, and M. Thiercelin, SPE,Abstract Offsets along the hydraulic fracture path
                                                                          Abstract The Joint Chalk Norway; Rene Frederikse
Bart Vos and Hans de Pater, Pinnacle Technologies; Chris Cook, Norsk Hydro; Tommy Skjerven, BP Research (JCR) initiative
M. Jamiolahmady, M. Sohrabi, and Shaun Ireland, Heriot-Watt University Abstract Hydraulic fracturing is one of the most com
                                                                          Abstract The Kharyaga
H. Poitrenaud, P. Ferrand, and P. Pouget, SPE, Total E&P, and J. Mani�re, SPE, Schlumberger field is located in Timan-P
                                                                          Abstract Massive hydraulic fracturing China Ltd
Xing Zhenhui, Saint-Gobain (Guanghan) Proppant; Andrew Pfaff, Thomas Weller, David Wendt, EOG Resources has been suc
Jairam Kamath, Chevron                                                    Distinguished Author Series articles are general d
                                                                           Abstract Science increase in gas Peters, TNO Bu
A.P. Leemhuis, E.D. Nennie, and S.P.C Belfroid, SPE, and G.J.N. Alberts, SPE, TNO A strong and Industry; E. inflow due to ga
Adam Vasper, SPE, Schlumberger                                             Summary The terms auto natural and in-situ gas
                                                                           Abstract BP Trinidad and Tobago B. Lanclos and
S.D. Cooper, S. Akong, K.D. Krieger, A.J. Twynam, F. Waters, and R. Morrison, BP; G. Hurst, Consultant; and(bpTT) has been
K. Zeidani, SPE and M. Polikar, SPE, University of Alberta                 Abstract Laboratory investigations were conducted
Myeong Noh* and Abbas Firoozabadi, SPE, Reservoir Engineering
Research Institute (RERI) * now with Chevron Corporation                   Summary Gas-well productivity is affected by two
                                                                           Abstract Halliburton
P. Leschi, SPE, and G. Demarthon, Total E&P, and E. Davidson, SPE, and D. Clinch, It is well known that the use of hydrochlo
                                                                           Abstract A&M U.
A. Bond, Pioneer Natural Resources Alaska Inc., and D. Zhu and R. Kamkom, Texas Horizontal wells provide extended contact
V.U. Imeh, L. Murray, D. Lenig, and D. Robertson, BP, and M. Panda, PRA Abstract Thermal fracturing in water injectors plays
                                                                           Abstract M. Shaheen, SPE, Z. Al-Jalal, Schlumbe
K. M. Al-Naimi, SPE, B. O. Lee, SPE, K. M. Bartko, Saudi Aramco, S. K. Kelkar, SPE,Horizontal completion technology has pro
                                                                           Abstract Schlumberger, B. Johnston, Packer pro
K. M. Al-Naimi, B. O. Lee, S. M. Shourbagi, Saudi Aramco, S. K. Kelkar, M. Shaheen,Horizontal completion technology hasPlus
                                                                           Abstract Completing horizontal wells with openhole
Hassan Chaabouni, Schlumberger, Pierre Baux, Dasa Manalu, Muhammad Sobirin, Total E&P Indonesie, Philippe Enkababian
                                                                           Abstract Completing horizontal wells with openhole
Hassan Chaabouni, Schlumberger, Pierre Baux, Dasa Manalu, Muhammad Sobirin, Total E&P Indonesie, Philippe Enkababian
                                                                           Summary The Colville River
Michael D. Erwin, SPE, ConocoPhillips Alaska, and David O. Ogbe,SPE, University of Alaska Fairbanks field represents the fi
                                                                            SPE, Shell E&P B.V
M. Kerem, SPE, Shell E&P B.V.; M. Proot, Shell GSI B.V.; and P. Oudeman,Summary This paper presents the results of a pro
A.F. Harun, SPE, G. Fung, SPE, and M. Erdogmus, SPE, BP America            Summary A dry tree well in the Gulf of Mexico (GO
                                                                           Abstract Most of the
G.A. Carvajal, E. Arreaza, C. Gonz�lez, C. Cesin, M. Fern�ndez, and J. Bello, PDVSA E&P cases in gas condensate well
                                                                           Abstract A new cost effective life-cycle profile cont
V. Ogoke, SPE, Shell; C. Aihevba, SPE, Petroleum Development Oman; and F. Marketz, SPE, Shell
Liang-Biao Ouyang, SPE, Chevron E&P Technology Co., and Ramzy
Sawiris, SPE, Chevron Overseas Petroleum Co.                                                      Tubing
                                                                           Summary Production and injection profiling throug
Liang-Biao Ouyang, SPE, and Dave Belanger, SPE, Chevron Corp.              Summary Permanent downhole monitoring can pr

                                                                             and E.S. A four-zone intelligent Vold, SPE, Wea
B. Sand�y, SPE, T. Tjomsland, SPE, D.T. Barton, and G.H. Daae, Statoil;Summary Johansen, SPE, and G.water-alternating
                                                                             Abstract This paper describes an innovative comp
Muhammad Shafiq and Athar Ali, SPE, Schlumberger; and Haider Al-Haj, Ibrahim Obaidi, Muhammad Qasim Qazi, and S.M. M
                                                                             Abstract Wedgwood, project America
A. Chacon, SPE, J.B. McCutcheon, SPE, D.W. Schott, SPE, B. Arias, SPE, and J.M. The Na Kika SPE, BPlocated in the deepw
                                                                             Abstract Horizontal and
F.T. Alkhelaiwi, Heriot-Watt University and Saudi Aramco, and D.R. Davies, Heriot-Watt University multilateral completions ar
                                                                             Abstract Horizontal wells are superior in productio
E. Davila, R. Almeida, I. Vela, J. Pazos, and K. Coello, Petroamazonas;�F. Chinellato and�O. Humbert, Schlumberger; an
F. Ebadi, SPE, and D.R. Davies, SPE, Heriot-Watt U.                          Abstract Intelligent Well (IW) Technology improve
M.A. Ali, SPE, and M. Shafiq, SPE, Schlumberger                              Abstract Intelligent completions have been in com
F. Ebadi, SPE, and D.R. Davies, SPE, Heriot-Watt U.                          Abstract Intelligent Well (IW) Technology combin
D.J. Goggin, M.A. Ovuede, N. Liu, U. Ozdogan, P.B. Coleman, and D.P.
Meinert, Chevron Intl. E&P Co.; I. Nygard, Statoil; and J. Gontijo, Petroleo
Brasileiro Nigeria Ltd.                                                      Abstract Large deepwater fields with a limited num
Mohammed A. Abduldayem, SPE, Saudi Aramco, Muhammad Shafiq, SPE, Abstract This paper describes an innovative comp
                                                                             Schlumberger, Nader D. Al Douhan, SPE, and Zul
                                                                             Abstract Significant challenges remain in London
E.A. Addiego-Guevara, SPE, and M.D. Jackson, SPE, Department of Earth Science and Engineering, Imperial Collegethe deve
                                                                              Green, The design and subsequent results of a h
L. Casas and J.L. Miskimins, Colorado School of Mines, and A. Black and S.Abstract TerraTek
                                                                              Green, The design and subsequent results of a h
L. Casas and J.L. Miskimins, Colorado School of Mines, and A. Black and S.Abstract TerraTek
                                                                             Abstract Foam is widely used to divert acid or aban
Rouhollah Farajzadeh, SPE, Shell International Exploration and Production, and Department of Geotechnology, Delft University
                                                                             Delft U. We present a new 2D analysis based on t
F. Farshbaf Zinati, R. Farajzadeh, and P.L.J. Zitha, Dept. of Geotechnology, Abstract of Tech.
                                                                             Geotechnology, Delft U. present
M.D. Carretero-Carralero, R. Farajzadeh, D.X. Du, and P.L.J. Zitha, Dept. of Abstract In this paper we of Tech. a 1D and 2D ana
                                                                             Abstract Critical velocity calculations in the form of
Robert P. Sutton and Stuart A. Cox, Marathon Oil Company; James F. Lea, PLTech LLC; and O. Lynn Rowlan, Echometer Com

Yula Tang and W.S. (Bill) Huang, Chevron Energy Technology Company Abstract A dual-lateral well was completed in a Ch
P. Oudeman, SPE, Shell Intl. E&P                                          Abstract In depleted gas wells the produced gas r
                                                                          Abstract Continuous increase in worldwide brown-
D.Orta, S. Ramanchandran, J. Yang, M. Fosdick, T. Salma, J. Long, and J. Blanchard, Baker Petrolite Corp., and A. Allcorn, C.
Werner Schinagl and Mark Denny, BP                                        Abstract As North Sea gas fields become mature
                                                                          Abstract As reservoir pressures decrease in matur
S.P.C. Belfroid, SPE, W. Schiferli, SPE, and G.J.N. Alberts, SPE, TNO Science and Industry, C.A.M. Veeken, SPE, and E. Biez
A.V. Bondurant, SPE, B.D. Dotson, SPE, and P.O. Oyewole, SPE, BP America  Abstract A common characteristic of “challeng
                                                                          Abstract Liquid loading in gas wells is a phenomen
Werner Schinagl, SPE, Steve R. Green, and Alan C. Hodds, BP, and Mark Caskie and Martin Docherty, Baker Petrolite
B. Dotson and E. Nu�ez-Paclibon, BP America Production Company          Abstract A new perspective is introduced to the pr
B. Khoshnevis, R. Rastegar Moghadam, SPE, and I. Ershaghi, SPE, U. of
Southern California, and K. Larbi, SPE, and V. Villagran, SPE, Chevron       Abstract Several methods for unloading water from
Yula Tang, SPE, Chevron Energy Technology Company, Zheng Liang,
Southwest Petroleum Institute                                                Abstract This work presents a new dynamic model
                                                                             Summary An investigation into gas carryover
R.P. Sutton, T.K. Skinner, Marathon Oil Company; R.L. Christiansen, Colorado School of Mines; and L. Wilson, Centrilift resu
                                                                             Abstract In several places around the world notab
Varun Mishra, D. Zhu, and A.D. Hill, Texas A&M U., and K. Furui, ConocoPhillips
E. Zuluaga and J.H. Schmidt, Chevron ETC, and R.H. Dean, Simwulf
Systems                                                                      Abstract Cavity completions have been widely use
R. North, SPE, C.P. Lenn, SPE, and I. Stowe, SPE, Schlumberger               Abstract A new processing workflow has been eng
                                                                             Abstract As Nor Hisham Mohd Azam, Edna Malim
Saifon Daungkaew, Michel Claverie, Boon Cheong, Steve Hansen, Richard Leech, Mohd the cost of exploration wells continue
                                                                             Abstract Sanding Operations, and C. P. Tan, Schlu
M. A. Mohiuddin, Schlumberger, M. M. Najem, Y. R. Al-Dhaferi, H. A. Bajunaid, Al-Khafji Joint problems are often observed in f
                                                                              Ian C. Walton, Schlumberger
Kirk M. Bartko, Saudi Aramco, and Frank F. Chang, Larry A. Behrmann, andAbstract It is well known that in cased-hole comple
                                                                             Abstract The transition from completion to produc
Achille Tiribelli, Giovanni Luca Minneci, and Ahmed Daoud, Groupement Sonatrach Agip, and Fathi Ghodbane and Ahmed Dah
                                                                             Abstract Coiled tubing has been widely E. Parta, S
M.I. Omar, SPE, A. Md Ali, SPE, and Z. Ali, Petronas Carigali Sdn. Bhd., and A. Parapat, SPE, W. Speck, SPE, and used world
                                                                             Abstract Located in J. Romero, and Y. Gonzalez,
M. Medina, SPE, Helix RDS; G. Morantes, SPE, and J. Morales, PDVSA; and W. Guevara, SPE,Eastern Venezuela the Santa A
                                                                             Abstract
A. Burtsev, B. Kuvshinov, E. de Rouffignac, and A.M. Mollinger, Shell Intl. E&P b.v. This paper presents an assessment of th
                                                                             Abstract China National Khong, Oil Behrmann, (
Italo Pizzolante, Steve Grinham, Tian Xiang, and Jihong Lian, CACT Operators Group, and Chee KinOffshoreL.A. Corporation a
                                                                             Abstract While
M.R.G. Bell, SPE, and J.B. Davies, SPE, Shell Intl. E&P, and S. Simonian, SPE, FloDynamicassisting production engineers in m
                                                                             Abstract Fracturing Total E&P USA, Inc.
Cesar Gama, David Gerez, and Paul A. Babasick, SPE, Schlumberger, and Jose Piedras, SPE, is an important technique for s
                                                                             Abstract Fracturing Total E&P USA, Inc.
Cesar Gama, David Gerez, and Paul A. Babasick, SPE, Schlumberger, and Jose Piedras, SPE, is an important technique for s
                                                                              and Majed Shaaban Abu Lawi, Schlumberger
Al-Marri Faisal and Hassan Ibrahim Khalil, ADMA-OPCO, and Alan SalsmanAbstract A major challenge identified by ADMA OP
Ashraf Aly Abou Elnaga, Chevron San Jorge S.R.L., and Edgar Almanza,
Marcelo Batocchio, Kent Folse, and Martin�Schoener-Scott, Halliburton
Energy Services Inc.                                                         Abstract Chevron San Jorge S.R.L. operates in the
                                                                             Abstract Two gas fields offshore now employed
Fergus Robinson, SPE, Sarawak Shell Berhad; Kent C. Folse, SPE, Halliburton Energy Services (M) Sdn Bhd*Sarawak Malayb
                                                                             Abstract Two gas fields offshore now employed
Fergus Robinson, SPE, Sarawak Shell Berhad; Kent C. Folse, SPE, Halliburton Energy Services (M) Sdn Bhd*Sarawak Malayb
                                                                             Abstract Reliable estimates of post perforation SP
Lang Zhan, SPE, Fikri Kuchuk, SPE, Jim Filas, SPE, Dhani Kannan, SPE, Jawaid Saeedi, SPE, and Charles Van Petegem, dam
                                                                             Abstract In Jock Munro, Schlumberger
Graeme Rae, Mohd. Bakri Yusof, and Juanih Ghani, Talisman, and Shahril Mokhtar andMalaysia coiled tubing (CT) conveyanc
Emmanuel Ifediora, Charles Ibrahim, and Davis Ekeke, SPE, Addax
Petroleum Development (Nigeria) Ltd.; Francis Nwaochei and Emeka
Ogugua, SPE, Chevron Nigeria Ltd.; Emeka C. Ene, Sylvester Orumwese,
and Kingsley Idedevbo, SPE, Oildata Wireline Services                        Abstract Electric line remedial work such as throug
C. Han, Michael H. Du, and Ian C. Walton, SPE, Schlumberger                  Abstract A detonated shaped charge fired from a p
                                                                              and Alan Salsman SPE, is driven by establishing
Hanaey Ibrahim, SPE, and Sameer Balushi, Petroleum Development Oman,Abstract Well productivityAlvaro Javier Nunez, and
                                                                             Abstract We report on a series of
D.C. Atwood, SPE, W. Yang, SPE, B.M. Grove, SPE, L.A. Behrmann, SPE; Schlumberger Technology Corp. laboratory flow e
                                                                             Abstract Optimal well productivity is Situmorang; S
Hanaey Ibrahim SPE, Ali Harrasi, Petroleum Development Oman, Alan Salsman, Alvaro Javier Nunez, Haposan achieved by es
                                                                             Abstract J.A.T. Gomes, and V.C. Amorim, Petrobr
P.G. Bedrikovetsky and R.P.S. Monteiro, North Fluminense State U., and J.S. Daher, The system where sulphate scaling dama
                                                                             Abstract Previous work has derived an and F. Pa
P. Bedrikovetsky, SPE, North Fluminense State U. (LENEP/UENF); E. Mackay, SPE, Herriot-Watt U.; R.P. Monteiro analytical
                                                                             Abstract and L.R. Murray, BP
K.S. Zaki, SPE, M.D. Sarfare, SPE, and A.S. Abou-Sayed, SPE, Advantek Intl. Corp., Produced water reinjection (PWRI) offer
                                                                             Abstract During recent years interest in underbala
C. Nguyen, J.M. Somerville, SPE, and B.G.D. Smart, SPE, Heriot-Watt University
                                                                             Abstract Saudi Aramco's drilling strategy witnesse
Mohammad S. Al-Shenqiti, Alaa A. Dashash, Ibrahim H. Al-Arnaout, Saad M. Al-Driweesh, Saudi Aramco, and Zaki Bakhteyar,
                                                                             Abstract The Campos Basin in Brazil SPE, of the
C.A. Pedroso, SPE, E.M. Sanches, and N.S. Oliveira, Petrobras, and I.J. Mickelburgh, SPE, and C.R Guimaraes, is oneSchlum
                                                                              Lim, Jit Oil Lim, and Kuo Chuan Ong, Halliburto
Sakamrin Abdul-Rahman, Brunei Shell Petroleum Co. Sdn. Bhd., and Derek AbstractJuanand gas producers have long been lo
                                                                             Abstract The Shallow Clastics Field operated by S
J.H. Terwogt, N.S. Hadfield, and A.A. Van Karanenburg, Sarawak Shell Berhad, and S. Salahudin and K. King, Halliburton Ene
                                                                             Abstract ConocoPhillips and Kenyon the Magnolia
Luke F. Eaton and W. Randall Reinhardt, ConocoPhillips Co.; J. Scott Bennett, Devon Energy Corp.; is developingBlake and Hu
                                                                             Summary SPE, Devon Energy Corporation; Kenyo
Luke F. Eaton, SPE, and W. Randall Reinhardt, SPE, ConocoPhillips; J. Scott Bennett, ConocoPhillips is developing the Magno
                                                                             Abstract Schlumberger, Tim O’Rourke, Schlum
Ibrahim Refai, SPE Saudi Aramco, Anwar Assal, SPE Schlumberger, Jeremie Fould, A number of the wells reach there econom
Robert D. Pourciau, Chevron Corporation                                      Summary Extended-reach naturally perforated w
Ian D. Palmer and Nigel G. Higgs, Higgs-Palmer Technologies; Robert M.
Mathers & Scott R. Herman, Chevron                                           Abstract A detailed sand prediction has been made
                                                                             Abstract SPE, and describes challenges test an
George Gillespie, SPE, Weatherford International; Chuck Hinnant, SPE, Chris Davis, This paperJamie Schober, SPE, Shell;equ
                                                                          Summary The Shallow Clastics field operated by
Neil S. Hadfield, Jan H. Terwogt, and Aart A van Kranenburg, Sarawak Shell; and Sharifudin Salahudin and Kimberly King, Hal
                                                                          Abstract ConocoPhillips is developing the Magnolia
George Colwart, Robert C. Burton, Luke F. Eaton, and Richard M. Hodge, ConocoPhillips Co., and Kenyon Blake, Schlumberg
                                                                          Summary ConocoPhillips is developing the Magno
George Colwart, SPE, Robert C. Burton, SPE, Luke F. Eaton, SPE, and Richard M. Hodge, SPE, ConocoPhillips Company, an
                                                                          Abstract Alpha field Udeh, T. in SPDC’s OM
I.O. Yahaya, A. Opusunju, B. Ajaraogu, G. Agbogu, O. Williams, and C. Uchendu, SPDC; and M. is situatedOyetade, and M. Ba
                                                                           and Abraham T. Faga, SPE, and Howard L. McKi
Brian T. Wagg, SPE, and Jonathan L. Heseltine, SPE, C-FER Technologies,Abstract Several operators have recently launched
                                                                       0            0
                                                                          Abstract and Open Hole Gravel Pack
Kevin Whaley, Colin Price-Smith, Allan Twynam, and David Burt, BP Exploration Ltd.,InitialPhillip Jackson, Baroid (OHGP) co

Yula Tang, W.S. (Bill) Huang, Chevron Energy Technology Company              Abstract Open-hole Gravel packing is increasingly
                                                                             Abstract Horizontal Open Hole Gravel and (HOHG
B.V. Loureiro, UCL - Faculdade do Centro Leste, J.V.M. de Magalh�es, SPE, M.V.D. Ferreira, A. Calderon, SPEPack A.L. Ma
                                                                             Abstract Horizontal SPE, and A. Calderon, SPE,
B.V. Loureiro, UCL-Faculdade do Centro Leste, and�J.V.M. de Magalhaes, SPE, A.L. Martins,Open hole gravel pack is the c
                                                                             Abstract The major trend and Aziz Ejan, Abdul in
Matthew Law, George W. Chao, Hafeez Ab Alim, and Elsamma Samuel, Schlumberger Well Services, of completion method Ha
                                                                             Abstract and Open Hole Gravel Pack
Kevin Whaley, Colin Price-Smith, Allan Twynam, and David Burt, BP Exploration Ltd.,InitialPhillip Jackson, Baroid (OHGP) co
                                                                             Abstract Well Heidrun Ridene, SPE, and Norweg
Ina H. Stroemsvik, Kjell Tore Nesvik, SPE, Frode Vik, and Karin Stene, StatoilHydro, and MohamedA-45 located in theDaniele
                                                                             Abstract One of the major challenges in undergrou
A. Zanchi, Stogit; G. Ripa, M. Colombo, and G. Ferrara, SPE, Eni E&P; and E. Belleggia, R. Barbedo, R.�Illuminati, J. Rezen
                                                                             Abstract Openhole gravel packing is one of the mo
M. Tolan, BG Group, and R.J. Tibbles, J. Alexander, P. Wassouf, L. Schafer, and M. Parlar, Schlumberger
                                                                             Abstract Indonesia
Mark Banman, Eric Delattre, Muhammad Sofyan, and Siswara Suryadana, Total E&P Stacked gravel-packs involve limited tech
                                                                             Abstract TOTAL AUSTRAL
P. Puyo and A. Bourgeois, Total Austral, and A. Penno and A. Oliveira, Halliburton Energy Services Inc. operates the Carina a
                                                                             Abstract Gravel packing
Samyak Jain, SPE, Rajesh Chanpura, SPE, Renato Barbedo, and Marcos Moura, SPE, Schlumbergerhas routinely been used
                                                                             Abstract M. Parlar, Schlumberger
E.P. Ofoh and M.E. Wariboko, Nigerian Petroleum Development Co., F.E. Uwaifo and A large majority of the recent deepwate
Mingqin Duan, Stefan Miska, Mengjiao Yu, Nicholas Takach, and
Ramadan Ahmed,SPE, University of Tulsa; and Claudia Zettner, SPE,
ExxonMobil                                                                   Summary Effective removal of small sand-sized s
                                                                             Abstract This paper documents a novel engineerin
F. Lavoix, P. Leschi, and E. Aubry, Total E&P, and L. Quintero, X. Le Prat, and T. Jones, Baker Hughes Drilling Fluids
                                                                             Abstract Cased-hole gravel packing is commonly
Samyak Jain, SPE, Raymond Tibbles, and Jock Munro, SPE, Schlumberger, Rajeswary Suppiah and Norhisham Safin, SPE, P
                                                                              Munro, Cased-hole gravel and Rajeswary Supp
Shahryar Saebi, SPE, Samyak Jain, SPE, Raymond Tibbles, SPE, and Jock AbstractSPE, Schlumberger,packing is commonly
                                                                             Krieger, The
I. Palmer and N. Higgs, Higgs Technologies, and I. Ispas, K. Baksh, and K. Abstract BP X-1 well in a gas field in Trinidad wa
                                                                             Abstract Gj�a Atwood, SPE, J. Heiland, SPE,
J. S. Andrews, SPE, H. Bj�rkesett, SPE, J. Djurhuus, StatoilHydro; I. C. Walton, SPE, D. C.is an oil and gas field located off B
G. Navaira, SPE, Chevron; M. Hupp, T. Palisch, SPE, CARBO Ceramics
Inc; J. Renkes, SPE, PropTester, Inc                                         Abstract Offshore completions in the Gulf of Mexic
                                                                             Abstract This paper presents
S. Wibawa, S. Kvernstuen, Schlumberger, and A. Chechin, J. Graham, and K.R. Dowling, Apache Energy the first installation o
M.R. Wise and R.J. Armentor, Chevron, R.A. Holicek, B.R. Gadiyar, M.D.
Bowman, R.A. Jansen, and S.N. Krenzke, Schlumberger                          Abstract Screenless sand control completions pro
                                                                             Abstract Screenless sand control completions pro
M.R. Wise and R.J. Armentor, Chevron, R.A. Holicek, B.R. Gadiyar, M.D. Bowman, R.A. Jansen, and S.N. Krenzke, Schlumbe
B. Vidick, SPE, S. James, SPE, and B. Drochon, SPE, Schlumberger             Abstract The search for a cost-effective alternative
David Underdown, SPE, Chevron; Henky Chan, SPE, Chevron Pacific
Indonesia                                                                    Summary The Duri field in Sumatra Indonesia sh
J.D. Holmes and M.P. Tolan, BGEPIL, and C. Hale, BJ Services                 Abstract The stacked sands of the South Tapti fie
                                                                              SEIC, H. Subhi, SEIC, J.A. Hother, Proneta
M.A. Addis, SIEP, M.C. Gunningham, SEIC, Ph. Brassart, SEIC, J. Webers, Abstract Sand Quantification involves predicting th
G. Petit, H. Foucault, and A. Iqbal, Total E&P                               Abstract Wells in the Girassol field offshore Angol
                                                                              J.-F. Nauroy, IFP
G. Servant, IFP; P. Marchina, Total S.A.; and Y. Peysson, E.�Bemer, and Abstract Allowing sand to be produced is widely k
J. Skufca and J. Li, BJ Services Company                                                Reach sand With of large diameter d
                                                                             Abstract Cleaning Wells fill outConcentric Coiled Tu
N. Morita, Waseda U., and G.-F. Fuh and B. Burton, ConocoPhillips            � Abstract Sand flow models have been succe
M.C. Gunningham, SPE, Sakhalin Energy Investment Company; M.A. Addis,Abstract This paper is a case study which describ
                                                                              SPE, Shell International E&P;and J.A. Hother, SP
                                                                             Abstract Sand production from the Sarir field becam
K. Qiu, SPE, Schlumberger; Y. Gherryo and M. Shatwan, SPE, AGOCO, Libya; R. Marsden, J. Alexander, and A. Retnanto, SP
                                                                             Abstract Using two field
G.-F. Fuh, I. Ramshaw, K. Freedman, and N. Abdelmalek, ConocoPhillips, and N. Morita, Waseda U.case examples this pape
                                                                             This paper was also presented SPE, Agoco
K. Qiu, J.R. Marsden, J. Alexander, and A. Retnanto, Schlumberger, and O.A. Abdelkarim and M. Shatwan, as SPE�100948
                                                                             This paper was also presented SPE, Agoco
K. Qiu, J.R. Marsden, J. Alexander, and A. Retnanto, Schlumberger, and O.A. Abdelkarim and M. Shatwan, as SPE�100948
                                                                             Abstract This paper Alexander, case study involve
Ahmed Abulsayen and Abdulwahab Enneamy, VEBA (Libya), and Kaibin Qiu, Rob Marsden, Joe described a and Muhammad S
                                                                             Abstract This paper Alexander, case study involve
Ahmed Abulsayen and Abdulwahab Enneamy, VEBA (Libya), and Kaibin Qiu, Rob Marsden, Joe described a and Muhammad S
                                                                             Summary It is commonly acknowledged in the pet
Bailin Wu, SPE, and Chee P. Tan (Now with Schlumberger Oilfield Support Sdn Bhd.), SPE, CSIRO Petroleum, and Ning Lu, C
                                                                             Summary It is commonly acknowledged in the pet
Bailin Wu, SPE, and Chee P. Tan (Now with Schlumberger Oilfield Support Sdn Bhd.), SPE, CSIRO Petroleum, and Ning Lu, C
                                                                         Summary Factors Peter Robinson, leading to san
Hans Vaziri, BP America; Robbie Allam, Gordon Kidd, Clive Bennett, and Trevor Grose, BP plc;and mechanisms BP Australia;
                                                                         Summary Factors Peter Robinson, leading to san
Hans Vaziri, BP America; Robbie Allam, Gordon Kidd, Clive Bennett, and Trevor Grose, BP plc;and mechanisms BP Australia;

Xiaojun Cui and R. Marc Bustin, U. of British Columbia                      Summary The production rates of coalbed gas we
                                                                            Summary Installing sand control in long horizonta
Alireza Nouri, SPE, Dalhousie University; Hans Vaziri, SPE, BP-America Inc.; and Hadi Belhaj, SPE, and M. Rafiqul Islam, SPE
                                                                            Summary Installing sand control in long horizonta
Alireza Nouri, SPE, Dalhousie University; Hans Vaziri, SPE, BP-America Inc.; and Hadi Belhaj, SPE, and M. Rafiqul Islam, SPE
                                                                            Summary Although the stacked
Abdullah Kasim, SPE, Petronas Carigali; and Frank Wijnands, SPE, and Surej Subbiah, SPE, Schlumberger reservoirs of the B
M. Vazir and L.G. Acosta, BP                                                Abstract This paper provides a case study of an in
                                                                            Summary This paper introduces a
Alireza Nouri, Dalhousie U.; Hans Vaziri, BP plc America Inc.; and Hadi Belhaj and Rafiqul Islam, Dalhousie U. predictive tool t

                                                                                Summary This paper introduces a
Alireza Nouri, Dalhousie U.; Hans Vaziri, BP plc America Inc.; and Hadi Belhaj and Rafiqul Islam, Dalhousie U. predictive tool t
P.J. van den Hoek, SPE, and M.B. Geilikman, SPE, Shell Intl. E&P B.V.           Abstract Most sand production prediction models
J. Heiland, SPE, and M.E. Flor, Schlumberger                                    Abstract During production of hydrocarbons the f
                                                                                Abstract This Scientific Services Sdn. Bhd.; C.P.
B. Wu, SPE, CSIRO Petroleum; Nulwhoffal Arselan Mohamed, SPE, Petronas Research &paper presents a geomechanical stu
                                                                                 Heath and C. zinc and iron sulphide scales Simp
S. Dyer, Scaled Solutions; K. Orski and C. Menezes, Total E&P U.K. Ltd.; S.Abstract LeadMacPherson, Clariant; and C. are k
                                                                                Summary Oseberg S�r field operated by Hydro
Niall Fleming, SPE, Kari Ramstad, SPE, Synn�ve H. Eriksen, SPE, Erlend Moldrheim, SPE, and Thomas Rudberg Johansen
Turhan Yildiz, SPE, Colorado School of Mines                                    Summary In this study the available methods and
                                                                                Summary Using now with Texas analytical calcul
K. Furui* , D. Zhu**, and A.D. Hill**, University of Texas at Austin * now with ConocoPhillips ** a combination ofA&M University
                                                                                Summary Well Services
Hisham A. Nasr-El-Din, SPE, Saudi Aramco, and Mathew Samuel, SPE, Schlumberger Viscoelastic surfactant systems are use
                                                                                Abstract The SPE, an acid fracture treatment is t
G. Zaeff and C. Sievert, SPE, ConocoPhillips, and O. Bustos, SPE, A. Galt, SPE, D. Stief,goal ofL. Temple, SPE, and V. Rodrig
                                                                                 Texas A&M effects of acid solutions injected
M. Pournik, C. Zou, C. Malagon Nieto, M.G. Melendez, D. Zhu, and A.D. Hill,Abstract TheU., and X. Weng, Schlumberger into
                                                                                Abstract The SPE, an acid fracture treatment is t
G. Zaeff and C. Sievert, SPE, ConocoPhillips, and O. Bustos, SPE, A. Galt, SPE, D. Stief,goal ofL. Temple, SPE, and V. Rodrig
                                                                                Abstract Acid fracturing has been an integral part o
J. Ricardo Solares, SPE, J.J. Duenas, SPE, Moataz Al-Harbi, SPE, Abdulaziz Al-Sagr, SPE, Saudi Aramco, Venkateshwaran R
                                                                                Abstract Amorocho, SPE, Saudi an integral part
J. Ricardo Solares, SPE, Moataz Al-Harbi, SPE, Abdulaziz Al-Sagr, SPE, and Ricardo Acid fracturing has beenAramco, and Ve
Chuck Zeiler, SPE, David Alleman, and Qi Qu, SPE, BJ Services                   Summary Viscoelastic-surfactant (VES) -based di
                                                                                Abstract Alastair Chisholm, BP
David Barclay, SPE, and Iain Trodden, SPE, Halliburton, and Robbie Allam, SPE, and This paper presents the prejob engineeri
Bernhard Lungwitz, SPE, Chris Fredd, SPE, Mark Brady, SPE, and
Matthew Miller, SPE, Schlumberger; Syed Ali, SPE and Kelly Hughes,
SPE, ChevronTexaco                                                              Summary A self-diverting-acid based on viscoelas
M.A.P. Albuquerque, SPE, Schlumberger; A.G. Ledergerber, SPE,
Chevron; and C. Smith, SPE, and A. Saxon, SPE, Schlumberger                     Abstract Between December 2003 and February
M.S. Newman, Chevron Australia Pty. Ltd., and�M.M. Rahman, SPE,
The University of Adelaide                                                      Abstract The success of a stimulation technique is
                                                                                Summary Acid-fracturing SPE, H.M. Al-Marri, SPE
H.A. Nasr-El-Din, SPE, A.A. Al-Zahrani, SPE, F.O. Garzon, SPE, C.A.F. Giraldo, SPE, I.M. Al-Hakami, treatments are used com
                                                                                and C. Between December 2003 and February
M.A.P. Albuquerque, SPE, Schlumberger; A.G. Ledergerber, SPE, Chevron;Abstract Smith, SPE, and A. Saxon, SPE, Schlumb
                                                                                Abstract The Maca� formation (Cretaceous ag
B. Lungwitz, SPE, Schlumberger; R. Hathcock, SPE, K. Koerner, SPE, D. Byrd, SPE, and M. Gresko, SPE, Devon Energy Cor
                                                                                Summary Effective matrix acidizing in Kuwait’
Hai Liu, SPE, Chad Coston, and Mohamed Yassin, SPE, Schlumberger; Shahab Uddin, SPE, Kuwait Gulf Oil Company; and Fa
                                                                                Abstract and Surasak Srisa-ard, Well Services Br
Yin-Chong Yong and Karim Saaikh, Brunei Shell Petroleum; Joao Queiros, Yan Song,Improving oil and gas production from the
                                                                                SPE, and M. Samuel, SPE, Schlumberger
H.A. Nasr-El-Din, SPE, and M. Zabihi, SPE, Saudi Aramco, and S.K. Kelkar,Abstract In treating sour water injectors in carbon
                                                                                Lungershausen, Zhaikmunai LLP; and N.T. is ofte
R. Arangath, SPE, Schlumberger; K.W. Hopkins, Aral Petroleum Capital; D. Abstract Stimulation of carbonate reservoirsBolysp
                                                                                Abstract T. Lindvig and X.W. Qiu, Schlumberger
F.F. Chang, SPE, Schlumberger; H.A. Nasr-El-Din, SPE, Texas A&M University; and Hydrochloric acid is the most commonly u
                                                                                Abstract The Uthmaniyah field is Venkateshwaran
Surajit Haldar, SPE, Ahmed A. Al-Jandal, SPE, Saad M. Al-Driweesh, Mufeed H. Al-Eid, SPE, Saudi Aramco; one of the bigges
                                                                                Abstract A group of industry experts have compiled
M. Asadi, ProTechnics; G.S. Penny, CESI Chemical; B.R. Ainley, Chandler Engineering; D.J. Archacki, Weatherford; F. Bas va
                                                                                Abstract The Caballos formation is thick Soler, SP
Rafael Rozo, SPE, and Javier Paez, Petrominerales; Alberto Mendoza, SPE, Ecopetrol; and Arthur Milne, SPE, Diegolaminated
                                                                                Abstract The Orito field in the south of Colombia
Rafael Rozo and Javier Paez, Petrominerales; Alberto Mendoza, Ecopetrol; and Arthur Milne and Diego Soler, Schlumberger w
                                                                                Abstract The purpose of matrix treatments in carb
Frank F. Chang and Xiangdong Qiu, Schlumberger, and Hisham A. Nasr-El-Din, Saudi Aramco
                                                                                Abstract The majority of oil exploited from I. Faizu
D. Oussoltsev, I. Fomin, K.K. Butula, and K. Mullen, SPE, Schlumberger, and A. Gaifullin, A. Ivshin, D. Senchenko, andRussian
V. Kumar, SPE, V. Bang, SPE, G.A. Pope, SPE, and M.M. Sharma, SPE,
U. of Texas at Austin, and P.S. Ayyalasomayajula, SPE, and J. Kamath,
SPE, Chevron                                                                    Abstract Significant productivity loss occurs in gas
Murtaza Ziauddin, SPE, and Emmanuel Bize, SPE, Schlumberger                     Abstract Most carbonate reservoirs are heterogen
Liang Jin and Paul Wong, Shell Intl. E&P, and Brent Sinanan, BJ Services Co.    Abstract Malaysia is a significant gas producer and
                                                                          Abstract SPE, Baker Petrolite
O. Vazquez, M. Singleton, SPE, and K.S. Sorbie, SPE, Heriot-Watt U., and R. Weare,This paper describes a sensitivity study o
L.P. Moore, SPE, and H. Ramakrishnan, SPE, Schlumberger                   Abstract Restimulation of existing wells represents
K. Hughes and N. Santos, SPE, Chevron, and R.E. Arias and S.V.
Nadezhdin, SPE, Schlumberger Well Services                                Abstract Historically carbon dioxide (CO2)–foam
                                                                          Abstract and based fluids are Petroleum
O. Bustos, Y. Chen, M. Stewart, K. Heiken, and T. Bui, Schlumberger, and P. MuellerCO2 E. Lipinski, Sagacommonly used to f
                                                                          Abstract Historically carbon dioxide
K. Hughes and N. Santos, SPE, Chevron, and R.E. Arias and S.V. Nadezhdin, SPE, Schlumberger Well Services (CO2)–foam
                                                                          Abstract Well stimulation techniques
S.A. Utegalyev and S.K. Duzbayev, KazMunaiGas RD, and K. Kulbatyrov and S.V. Nadezhdin, SPE, Schlumbergerlike hydraul
                                                                          Abstract During at Austin; from gas Baran Jr., re
Vishal Bang, SPE, Gary A. Pope, SPE, and Mukul M. Sharma, SPE, The University of Texasproduction Jimmie R.condensate3M
Myeong Noh* and Abbas Firoozabadi, RERI *currently with Chevron
Corporation                                                               Summary Liquid blocking in some gas-condensate
                                                                          Abstract Cheneviere, and condensate drop Samu
Mohan K.R. Panga and�Suzylawati Ismail, Schlumberger Well Services;�Pascal Water blocks Total;�and Mathew out n
                                                                          Abstract Cheneviere, and condensate drop Samu
Mohan K.R. Panga and�Suzylawati Ismail, Schlumberger Well Services;�Pascal Water blocks Total;�and Mathew out n
                                                                          Abstract Dual completed Redha�Kelkouli, the
Majdi Al Mutawa, Bader Al Matar, SPE, and Abdulaziz Abdulla Dashti, SPE, Kuwait Oil Company, andwells producing fromSPE
George Aggrey* and David Davies, Heriot-Watt University, UK               Abstract Value addition via real-time reservoir mon
Mark F. Barrilleaux and Thomas A. Boyd, BP                                Abstract Smart completions that can remotely con
Mark F. Barrilleaux and Thomas A. Boyd, BP                                Abstract Smart completions that can remotely con
                                                                          Abstract Water
Xiuli Wang and Knut Hovem, BP; Daniel Moos, GMI; and Youli Quan, Stanford University hammer effects resulting from the
M. Jamiolahmady, P. Ghahri, O.E. Victor, and A. Danesh, Heriot-Watt U.    Abstract: The performance of a horizontal (highly s
                                                                          Abstract As capital costs continue to Jebutu, in th
Ron Day, Ramsey Fisher, SPE, and Louise Jacobsen Plutt, SPE, BP America Inc., and Nesny Pardo, SPE, Segunescalate SPE
                                                                          Abstract Two classes (sonic and ultrasonic) of cem
Douglas Boyd, Salah Al-Kubti, Osama Hamdy Khedr, Naeem Khan, and Kholoud Al-Nayadi, ZADCO; Didier Degouy, ADMA-OP
                                                                          Abstract Two classes (sonic and ultrasonic) of cem
Douglas Boyd, Salah Al-Kubti, Osama Hamdy Khedr, Naeem Khan, and Kholoud Al-Nayadi, ZADCO; Didier Degouy, ADMA-OP
ul acid stimulation campaign was conducted in 2004 in Brunei Shell Petroleum (BSP). This paper discusses what have been done differently
a is an offshore field located 60 km west of the coasts of Congo in water depths of 170 m. The field is producing light sweet oil from an Albian
 al nature of carbonate rocks makes acidizing an effective matrix stimulation technique. Acid dissolves carbonates at high reaction rate to cre
 al Submersible Pump (ESP) a form of artificial lift technology has proven to be a durable solution for delivering the required rates from Sau
 owered jet pumps (FPJP) were pioneered for use in Kuparuk Field wells on the North Slope of Alaska. Unlike conventional surface powered



 of improved Oil Recovery in mature fields is almost inevitable. However the method applied in the IOR process is dependent on the econom
 Gas industry is often faced with the challenge of selecting an optimal Artificial Lift method for a well in the midst of various artificial lift type ch
pletions for SAGD1 producers are unique. Conventional gas lift valves and mandrels with a packer completion cannot be used due to the ext
or high-temperature electric submersible pump (ESP) systems is growing as the oil industry matures. Canada's nonconventional oil reserves
 ystems are now being considered of extreme importance as the reserves across the globe are depleting and the wells are unable to flow nat
 l cleanup during well start-up ensures efficient formation damage removal and maximises the resulting well production potential. Horizontal w
 from conventional wells to horizontal and then multi-lateral) in well architecture for maximising reservoir contact have been paralleled by adv
ndan gas recycling project is located north of Australia in the East Timor Sea and is designed to produce 1 100 MMscf/D of wet gas strip ou
outlines and discusses the issues surrounding the TOTAL AUSTRAL Carina and Aries field development project and the engineering issues


r explores multiple completion options in gas/condensate reservoirs with compositional simulations. Besides intelligent-well completion (IWC
 and Tobago (bpTT) has been developing highrate gas fields in Trinidad & Tobago since 1999 and has six high rate gas fields currently on p
 hevskoye oil field development started in 1995. In 2002 by the time when all the designed vertical wells had been drilled practically all the re
 e northeast Brazil Manati field is located in the Camamu Bay with water depths less than 50 m. The sandstone gas reservoirs in this field hav
n well multiple zone completion systems applied in marginal wells in Los Perales Oil Field located in the Gulf of San Jorge Basin Santa Cruz
od of completing multiple-layer formations has been successfully tested in the United States and Canada. This new method places sliding sle
 a mature oil field with depleted reservoir pressure supported by an aquifer in the deeper Cretaceous horizon. The Cartojani structure is loca
Niger Delta clastic environment horizontal well completions have been widely used with success. Although conventional wells have been app
r discusses the effects of Ca2+ Mg2+ and Fe2+ on inhibitor retention and release. Better understanding of phosphonate reactions during in
presents the results of an investigation of the design of production tubing string setting depths in gas wells to optimize gas recovery in wells t
presents the results of an investigation of the design of production tubing string setting depths in gas wells to optimize gas recovery in wells t

  servoir in the Greater Burgan field is a thin carbonate reservoir containing light oil in a 10-20 ft target zone with “good porosity.� Matri
  servoir in the Greater Burgan field is a thin carbonate reservoir containing light oil in a 10-20 ft target zone with “good porosity.� Matri
Minghuazhen is a shallow-water delta-plain sedimentary-deposit reservoir sand in Bohai Bay China. It has relatively heavy oil in place that is
presents an advanced control method for online regulation of downhole Interval Control Valves (ICVs) to achieve optimal production via chok
describes a case-study detailing planning completion testing and production of the first Maximum Reservoir Contact (MRC) Multilateral (M
acement efficiency in hydrocarbon formations is often caused by the natural variation in the mobility of fluids across the reservoir strata. Histo
r describes a case study that details the planning completion testing and production of the first maximum reservoir contact (MRC) multilate
oped an operational strategy for commingled production with infinitely variable inflow control valves (ICVs) using sequential linear programmin
 r of multilateral gas producers drilled in the Ghawar field has significantly increased over the past few years as part of the reservoir developm
 ing technology is moving towards maximum reservoir contact (MRC) by means of extended-reach horizontal and multilateral wells in all type
  stimulation treatments based on alcohol to remove liquid blockage or condensate banking in the near well zone date from sixties. Among th
 injection on the Shell Bonga field offshore Nigeria is accomplished via a network of subsea flowlines and 15 subsea injection wells. Maximizi
rol devices which prevent early water breakthrough by passively controlling the inflow profile of a well have had a long and successful histo
 few field installations of a dual-electric submersible-pump (DESP) completion have been reported. In general the purpose of the second pum
 few field installations of a dual-electric submersible-pump (DESP) completion have been reported. In general the purpose of the second pum
 ball Field is a one Tcf gas condensate development offshore Trinidad producing at a sustained rate in excess of 800 MMcf/D from three wel
of the increasing emphasis on reducing operating costs and minimizing deferred production a new system was designed for perforating well
 statistical methodology using survival analysis (SA) was developed and applied to electrical submersible pump (ESP) system performance d
 statistical methodology using survival analysis (SA) was developed and applied to electrical submersible pump (ESP) system performance d
 proved to be effective and economical in underbalanced operations (UBO) and is gaining wider applications in many areas. It provides the d

 is a relatively simple and cost-effective well completion technique for horizontal wells. However fluid flow into a slotted-liner completion is qu
uring has been a successful method to stimulate the Khuff Carbonate wells of Saudi Arabia since the beginning of the gas development prog
 eld located on the North Slope of Alaska was developed using open-hole horizontal completions drilled along the maximum principle stress a
 eld located on the North Slope of Alaska was developed using open-hole horizontal completions drilled along the maximum principle stress a
r details the results for 33 propped-fracture treatments in low-porosity zones in the South Arne (SA) field Danish North Sea. To date seven h
 ry purpose of surfactants used in stimulating sandstone reservoirs is to reduce surface tension and contact angle and provide leakoff control
 rizontal lateral Bakken dolomite play began in 1999 in eastern Montana more than 330 wells have been permitted and more than 200 wells
hydraulic fracturing in various risky" oil reservoirs has been the biggest challenge for fracturing engineers in the Western Siberia basin as a s
 ng has been part of Saudi Aramco’s gas development strategy to maximize productivity from for vertical wells in the Khuff carbonates ov
describes successful implementation of degradable fiber-laden fluids for hydraulic fracturing in one of the largest oilfield in Western Siberia. P
 iscusses the application of fibers for the Frac and Pack application for Brunei Shell Petroleum (BSP). Seven wells with a total of seventeen f
ds are usually surfactants or cosolvents added to stimulation treatments to reduce capillary pressure and water blocks. As the gas reservoirs
 y has been conducted on the effect of formation Young’s modulus and in situ stress on hydraulic fracture height containment in layered

  Mexico (GOM) hydrocarbon discoveries reaching record depths and very high bottomhole pressures the need for proven weighted fracturin
 reservoir development continues at a record pace in North America. Additionally reservoir pressure depletion and declining quality of reserve
 elds produce larger quantities of water operators and service companies find themselves challenged with disposing flowback and produced
 d design for hydraulic fracturing is of great importance especially with the growing demand for this method as a means of production enhanc
 he success of a tight-gas field development program in a fluvial environment is to understand the reservoir’s deliverability and what the o
s a pervasively used completion technique in wells targeting high permeability poorly consolidated and depleted sandstone formations locate
  ve pay of the low permeability Ryabchyk formation in the mature fields of Western Siberia is separated from underlying water zones by a we
has become a viable and important option for completing horizontal wells. There are many fracturing processes and methods to consider for
   years horizontal well technology evolved in the Middle East field development strategies becomes favored over vertical and deviated wells o
  Pichana field is located in the center of the Neuqu�n Basin in the province of Neuqu�n being at present one of the main gas producer
n scenario in many mature oilfields is to have most of the wells producing hydrocarbons with high water cuts. These wells are commonly not
 ca hasn’t escaped the general industry trend of finding reserves in ever challenging environments. Complex geology and low permeabilit
Africa offshore fields are maturing and operators are completing secondary targets in their wells to maintain the economic operation of their v
key strategies in Saudi Aramco’s optimum gas development project is drilling single and multilateral wells to achieve maximum reservoir
erations are extremely expensive because of the operational environment and the necessary infrastructure. In this environment emphasis is
d System, Executed from a Supply Vessel; Black Sea Offshore
y and multiphase flow effects in hydraulic fractures have been well documented in the last several years. The pressure losses caused by thes



y and multiphase flow effects in hydraulic fractures have been well documented in the last several years. The pressure losses caused by thes
y and multiphase flow effects in hydraulic fractures have been well documented in the last several years. The pressure losses caused by thes
one of ONGC’s major brownfields discovered in 1983 and located in Gujarat. The Field produces approximately 30 000 bopd and is on d
presents the results of an investigation of the design and analysis of the boundary-dominated flow production performance of a vertically frac
 idespread proliferation micro-seismic fracture mapping it has been observed that some naturally fractured formations exhibit a non planar o
y of hydraulic fracturing work in Russia is being done in the Western Siberian basin where operators and service companies have gathered s
acturing of horizontal wells in shale gas reservoirs is now an established commercially successful technique.� The evolution of the compl
od of completing multiple layer wells has been successfully tested in the Piceance basin for Petrogulf Corporation. This new method placed s
hod of completing multiple-layer tight gas wells is being investigated. The main concept is to place sliding sleeve valves in the casing string
engineers have faced the problem of hydraulic fracturing in soft rock formations for many years. However existing programs used with soft ro
  ic Surfactant (VES) fluids are polymer-free fluids that generate viscosities suitable for fracturing operations without the use of polymer addit
 rbon dioxide- (CO2-) emulsified viscoelastic surfactant (VES) fluid system has recently been used to improve the Olmos production in the C
discusses the selection criteria design methodology and analysis of hydraulic fracturing treatments pumped using a solids-free liquid CO2 f
   Generation Viscoelastic Fluid: Successful Case Histories in West Venezuela

 uction in mature fields is a common situation.� In many mature areas every barrel of oil is being produced with six to ten barrels of water.
 ective of hydraulic fracturing in tight formation gas reservoirs is the creation of “effective fracture length.� The creation of effective frac

drilling program on North Raguba field in Libya has been suspended since the current well’s performance in this area was not promising
 ance of fracturing treatments has been an issue for over fifty years and considerable effort has been devoted to improve its prediction perfor
 resents the process of candidate well selection design execution and evaluation that lead to the successful implementation of acid fracturin
cumented in the literature that hydraulic fracture treatments although successful often underperform: Frac and Pack completions exhibit pos
cumented in the literature that hydraulic fracture treatments although successful often underperform: Frac and Pack completions exhibit pos
 eservoirs gas well production after hydraulic fracturing (HF) is often greatly impaired through various mechanisms by invasion of fracturing




cumented in the literature that hydraulic fracture treatments although successful often underperform: Frac and Pack completions exhibit pos
  c hydraulic fracture monitoring is having a major impact in how wells are being completed in tight sand reservoirs.� This existing technolo
 impairment in tight-gas formations is a typical phenomenon for fractured wells. Processes responsible for this behavior are related to the cha
   errors in the calculated azimuth and other parameters of a monitored fracture can be caused by not performing accurate borehole deviation
reports on a study conducted to assist with field development in the Jonah Field in Wyoming. Microseismic and surface tiltmeter fracture map
 lity Formations
cally fracture a well requires large investments in equipment horsepower materials and manpower.� An engineer can be overwhelmed w
  fracturing treatment fracture conductivity is created by differential etching of the fracture surface by the acid; without nonuniform dissolution
 lization of Hydraulic fracturing in West Siberia and the increase of job size over the recent year can impact the field development strategy. Th
 adioactive tracers have been used in combination with standard industry logging tools to gain valuable insight about the fracture height (near
  f our research is on a remote oilfield in western Siberia currently in the initial stages of development. There are two producing horizons of Ju
ere are many proven ways of predicting productivity in hydraulically fractured wells in medium-permeability oil reservoirs there is still no sim
 s carried out to forecast the productivity of a hydraulically fractured well in a retrograde gas-condensate sandstone reservoir using a numer
stribution at the tip of a hydraulic fracture is a key element for controlling fracture propagation. In low-permeability formations under downhol
  ght carbonate formations in Saudi Arabia are ideally suited for acid fracturing treatments. Various types of acids such as regular in-situ gelle
presents the results of an investigation of the design and analysis of low conductivity fractures. The mathematical model used in this work is

microseismic array was utilized to perform hydraulic fracture diagnostics during stimulation of the Chevron Skinner Ridge (SR) #698-22-1 well
mic imaging of a hydraulic-fracture stimulation showed significant fracture reorientation across a thrust fault. Fracture orientations were identi
 etion plays a critical role in the performance of a well in its entire life. More and more advanced well completion options are available for pote
 wback is an extremely important phenomenon in hydraulic fracturing technology and may cause severe problems for well completion. Variou
  the propagation of an orthogonal fracture and reopening along the initial fracture during a refracture treatment is studied by taking into accou
 al problem arises in enhancing oil recovery and is relevant to hydraulic fracturing process and subsequent frontal displacement of fluids from
  cturing is one of the most common well stimulation techniques. Hence considerable amount of efforts has been devoted to study their perfo
ooded reservoir hydrocarbon recovery optimization is impacted by well spacing and hydraulic fracture extent. An excessive fracture length m
  summarizes part of the results of an investigation of fracture clean-up mechanisms undertaken under a Joint Industry Project active since th
  summarizes part of the results of an investigation of fracture clean-up mechanisms undertaken under a Joint Industry Project active since th

documents the utilization of fracpack completion technology for water injectors in sand control environments.� This paper is a look back a
 s a deepwater project located in Malaysia. The development plan for this field requires fifteen water injectors eighteen producers and one g
acturing plays a very important role in these mature and complex geology fields located onshore northeast Brazil – Carm�polis and Siriz
ng the hydraulic fracture path have been observed in mapping of mined fractures and attempts have been made to reproduce their effects on
halk Research (JCR) initiative is set up by a group of operators and partners in the Southern North Sea. The objective of the initiative is to inc
 cturing is one of the most common well stimulation techniques for gas-condensate reservoirs. In recent years considerable effort has been d
 ga field is located in Timan-Petchora region of Northern Russia 60 km North of the Arctic Polar Circle. The field is producing principally from
 raulic fracturing has been successfully applied in tight gas reservoir development. Economic completion of tight gas sands with large hydrau
 Series articles are general descriptive representations that summarize the state of the art in an area of technology by describing recent deve
 rease in gas inflow due to gas coning and the resulting bean-back because of Gas to Oil Ratio (GOR) constraints can severely limit oil produ
 auto natural and in-situ gas lift all refer to artificial lift systems that use gas from a gas-bearing formation to gas lift a well. The gas lift gas is
and Tobago (bpTT) has been developing highrate gas fields in Trinidad & Tobago since 1999 and has six high rate gas fields currently on p
nvestigations were conducted to examine the effectiveness of heavy oil-in-water emulsion in plugging the near wellbore matrix thereby reduc

 roductivity is affected by two distinct mechanisms: liquid blocking and high-velocity flow in two-phase flow. The former has been studied exte
 own that the use of hydrochloric acid to clean up and restore permeability of open holes drilled in limestone formations is a questionable pro
 ells provide extended contact with the reservoir and have unique advantages over vertical wells in many applications. As nominally horizonta
cturing in water injectors plays a large role in controlling and determining injectivity. Vertical wells cannot always deliver the required rates to s
ompletion technology has progressed dramatically over the last six years with the latest technical barriers being eclipsed with open-hole tech
ompletion technology has progressed dramatically over the last six years with the latest technical barriers being eclipsed with open-hole tech
horizontal wells with openhole sections or non-cemented liners is a common practice. This type of openhole wells is preferred to maximize re
horizontal wells with openhole sections or non-cemented liners is a common practice. This type of openhole wells is preferred to maximize re
 e River field represents the first widespread and successful application of horizontal openhole completions on the North Slope of Alaska and
r presents the results of a project that was initiated to analyze the inflow performance and inflow distribution of one smart and two problemati
 well in the Gulf of Mexico (GOM) has been producing oil with more than 50% water cut. This raises a concern because the existing Anti-Agg
cases in gas condensate wells produce below dew point pressure generating a saturated zone in liquid that blockage the gas flow efficiency t
effective life-cycle profile control completion system has been developed to solve major problems associated with surveillance and interventio

             Conveyed Workover Operation
 t downhole monitoring can provide valuable information for production decisions in real time without the need to perform an intervention to c

 e intelligent water-alternating-gas (WAG) injector was installed at the Statoil Veslefrikk Field in the North Sea in May 2004. The completion in
describes an innovative completion solutions with reservoir monitoring and control completion technologies that allows commingled oil produ
  project located in the deepwater Gulf of Mexico is a unique development which ties-back six small to medium-sized oil and gas fields to the
nd multilateral completions are a proven superior development option compared to conventional solutions in many reservoir situations. How
wells are superior in production and recovery to conventional wells however they are subjected to early water coning towards the heel (water
Well (IW) Technology improves well and field performance management by combining zonal production control using Interval Control Valves
ompletions have been in commercial use for over ten years. Application of intelligent completions technology has evolved from intervention-l
Well (IW) Technology combines zonal production control using Interval Control Valves (ICVs) together with installation of appropriate flow m


water fields with a limited number of wells may require intelligent well systems to maximize production capacity under facility constraints. Agb
describes an innovative completion solution with state-of-the-art reservoir monitoring and control completion technologies that allows commin
challenges remain in the development of optimized control techniques for intelligent wells particularly with respect to properly incorporating th
 and subsequent results of a hydraulic fracturing test performed on a large block of high modulus and low permeability rock (Colton sandston
 and subsequent results of a hydraulic fracturing test performed on a large block of high modulus and low permeability rock (Colton sandston
ely used to divert acid or abandon the high permeable layers. In this type of application foam should considerably reduce gas mobility. The n
 a new 2D analysis based on the recently developed stochastic bubble population foam model focusing on the effect of the core heterogenei
  we present a 1D and 2D analysis of foam development in porous media based upon a new stochastic bubble population foam model and pr
city calculations in the form of charts or simple equations are frequently used by field personnel to evaluate a gas well’s flowing condition

al well was completed in a Chevron subsea condensate field with high peak rate. Within one year the production significantly declined with h
gas wells the produced gas rate and consequently the velocity will drop to the extent that produced liquids are no longer carried to surface. T
 increase in worldwide brown-field activity and overall depletion of current gas fields has renewed focus on maximizing gas production from e
a gas fields become mature significant production losses are increasingly caused by liquid loading. The reservoir energy is insufficient to tra
 pressures decrease in maturing gas wells liquid drop-out forms an increasing restriction on gas production. Even though virtually all of the w
characteristic of “challenging unconventional gas resources namely low permeability sands shale and coal bed methane is that the ultim
ng in gas wells is a phenomenon that increasingly limits production in mature gas wells where reservoir pressures are insufficient to lift liquid
pective is introduced to the problem of liquid loading in gas wells. Gas wells cease producing as reservoir pressure depletes and gas velocity
thods for unloading water from gas wells have been used in the industry. These methods commonly have a combination of the following cha

esents a new dynamic model to describe the plunger motion by considering the changes of the tubing and casing pressures liquid accumula
gation into gas carryover resulting from the downward flow of water was conducted. Water accumulation in a gas well is responsible for well-
aces around the world notably the North Sea and the Middle East carbonate reservoirs are being accessed with very long horizontal wells (2

 letions have been widely used to increase productivity from non-conventional sources such as coalbed methane reservoirs and “heavy o
essing workflow has been engineered to combine reservoir deliverability defined by production logging (PL) measurements with nodal analy
 of exploration wells continue to escalate we need more than ever to evaluate each well quickly and efficiently to improve the appraisal proce
blems are often observed in fields after a period of relatively smooth operation. These occurrences usually coincide with an increase in deple
own that in cased-hole completions productivity is enhanced by maximizing shaped charge penetration and shot density while minimizing per
on from completion to production often requires the well to be killed immediately after perforation is completed thus exposing the formation t
 g has been widely used worldwide to perform perforating and zonal isolation operation due to the ability in intervening highly deviated and lon
 astern Venezuela the Santa Ana Field is part of the most important gas province of Venezuela: Anaco District. Its main productive zones are
presents an assessment of the performance of a horizontal well completed by limited-entry perforation (LEP) technique based on reservoir
nal Offshore Oil Corporation (CNOOC) Chevron and ENI the field operator are partners in the development of the HZ oil and gas fields op
ting production engineers in managing the perforating process Shell recognized the need for an engineering software tool to guide and advis
  an important technique for stimulating production in low-permeability formations and requires special consideration in designing the preced
  an important technique for stimulating production in low-permeability formations and requires special consideration in designing the preced
 lenge identified by ADMA OPCO is the time delay and subsequent lost�production between a well being completed with the drilling rig un


n Jorge S.R.L. operates in the Loma Negra area and El Trapial field located in the Neuqu�n Basin Argentina. El Trapial wells are charact
elds offshore Sarawak Malaysia are characterised by heavily karstified carbonate reservoirs.� These reservoirs are typified by significant
elds offshore Sarawak Malaysia are characterised by heavily karstified carbonate reservoirs.� These reservoirs are typified by significant
 imates of post perforation damage skin are important for designing remedial solutions and productivity enhancement operations. Underbalan
 coiled tubing (CT) conveyance is used to optimize underbalanced perforating especially for rig-related operations. Well trajectory temperatu



  remedial work such as through tubing perforation has been successfully carried out in most vertical/deviated wells. However in high angle/h
  shaped charge fired from a perforating string or perforating gun will not only perforate its targets but also possibly cause excessive damage
 ivity is driven by establishing a clean connection through the near wellbore zone of drilling and completion induced permeability impairment c
n a series of laboratory flow experiments comparing the productivity of perforations created with reactive liner charges against those created
  productivity is achieved by establishing a clean connection to the wellbore through the near wellbore zone of drilling and completion induced
 where sulphate scaling damage occurs is determined by two governing parameters: the kinetics coefficient characterising the velocity of che
 ork has derived an analytical model for simultaneous flow of incompatible waters in porous media with sulphate salt precipitation determine
water reinjection (PWRI) offers an efficient and effective means of disposing of the PW waste stream and provides an opportunity for a wate
nt years interest in underbalanced drilling (UBD) has grown rapidly. As a drilling technique it has gained acceptance because it provides a m
 co's drilling strategy witnessed a change in the last few years by drilling horizontal and extended reach maximum reservoir contact (MRC) we
s Basin in Brazil is one of the most challenging areas for completions in the world due to the lack of formation consolidation the large percen
 producers have long been looking for effective sand control methods that allow completion flexibility and improved productivity throughout a
w Clastics Field operated by Sarawak Shell targets two shallow gas-bearing reservoirs H1 and H2 at approximately 2 650 ft true vertical de
 ps is developing the Magnolia field with a Tension Leg Platform (TLP) in 4 674 ft of water at Garden Banks block 783 in the Gulf of Mexico. T
 illips is developing the Magnolia field with a tension-leg platform (TLP) in 4 674 ft of water at Garden Banks Block 783 in the Gulf of Mexico.
  the wells reach there economical production limit and are consequently abandoned or mothballed until viable solutions are available to enha
 reach naturally perforated water-injection frac-pack producing completions and frac-pack producing selective completion interventions wer

and prediction has been made for three wells at Chevron’s West Seno field based on logs/lab data and the results have been calibrated
 escribes challenges test equipment test program and results in the development of a screen product and contingency fluid-loss control (FL
 llow Clastics field operated by Sarawak Shell primarily targets two shallow gas-bearing reservoirs H1 and H2 at approximately 2 650 ft true
 ps is developing the Magnolia field with a tension leg platform (TLP) in 4 674 ft of water at Garden Banks block 783 in the Gulf of Mexico. Th
 illips is developing the Magnolia field with a tension leg platform (TLP) in 4 674 ft of water at Garden Banks Block 783 in the Gulf of Mexico.
s situated in SPDC’s OML 22 in the eastern part of the Niger delta belt some 60kM NW of Port Harcourt. The field discovered in 1986 c
rators have recently launched a new industry-wide initiative on sand control reliability. The aim of the initiative is to gain a better understandin

Hole Gravel Pack (OHGP) completions that have been installed in Greater Plutonio to date have all achieved complete annular packs and ze

Gravel packing is increasingly becoming a standard practice in the deep-water subsea completion environment. A Chevron offshore gas res
 pen Hole Gravel Pack (HOHGP) is the conventional sand control technique for offshore non consolidated reservoirs in Brazil. Gravel pack p
Open hole gravel pack is the conventional sand control technique for offshore non consolidated reservoirs in Brazil. Gravel pack placement re
 rend of completion method in offshore reservoirs with sand control requirement is Horizontal Open Hole Gravel Packing (OHGP).� Thoug
Hole Gravel Pack (OHGP) completions that have been installed in Greater Plutonio to date have all achieved complete annular packs and ze
 n A-45 located in the Norwegian Sea was completed in an unconsolidated sandstone reservoir that required sand control. The lower zone w
major challenges in underground gas storage wells in Italy is to maximize the sand layers exposure by drilling slanted or sub-horizontal wells
 ravel packing is one of the most popular completion techniques due to its high reliability along with the ability to deliver high-productivity well
avel-packs involve limited technical risk but require considerable rig time when completing deep multi-zone sand control wells. Four field dev
 STRAL operates the Carina and Aries fields which are located in offshore Tierra del Fuego in the most southern region of Argentina. These
 king has routinely been used as a sand control method in open-hole horizontal wells. With the advances in drilling technology in recent years
ajority of the recent deepwater developments in West Africa require sand control applications. Openhole gravel packing is the preferred sand


emoval of small sand-sized solids is critical for successful drilling and completion operations in sand reservoirs. Recent experience in extend
 ocuments a novel engineering approach and the operational methodology used to achieve high efficiency remediation on two offshore applic
e gravel packing is commonly utilized to control sand production from oil and gas wells. The success of a cased-hole gravel-pack job depend
 gravel packing is commonly utilized to control sand production from oil and gas wells. The success of a cased-hole gravel-pack job depends
ell in a gas field in Trinidad was designed to be a high-rate gas producer from a 65� deviated well through the S1U S1L and S2U sands a
 n oil and gas field located off the Norwegian Coast that is due to be developed with subsea infrastructure tied back to a floating production fa

mpletions in the Gulf of Mexico must typically address sand control. Our industry has made significant progress with respect to sand control e
presents the first installation of nozzle-based passive inflow control devices (ICD) for Apache Corporation in Australasia. This recent technolo

 sand control completions provide a cost-effective means of completing wells in the Gulf of Mexico by eliminating the need to have a rig on lo
 sand control completions provide a cost-effective means of completing wells in the Gulf of Mexico by eliminating the need to have a rig on lo
 for a cost-effective alternative to screens has been intensive in the sand control field. Different systems have been proposed in the past incl

 eld in Sumatra Indonesia shown in Fig. 1 and operated by Chevron Pacific Indonesia (CPI) is one of the largest onshore steamflood opera
d sands of the South Tapti field have presented completion challenges from field start-up in 1997 to the present-day. A large part of these ch
 fication involves predicting the volumes of sand which can be produced at the sandface completion and transported to the surface facilities f
 Girassol field offshore Angola are situated in very deep water and have being completed in unconsolidated sandy turbiditic reservoirs. Toda
  nd to be produced is widely known to enhance oil production rates particularly for heavy-oils fields. However in such a situation it is very im
ells With Concentric Coiled Tubing Vacuuming Technology
 low models have been successfully applied to heavy oil reservoirs .1 2 3 However when these models are applied to light oil and gas reserv
 s a case study which describes how Quantitative Risk Assessment (QRA) is applied to sand management in the specific case of Lunskoye
ction from the Sarir field became a major concern for AGOCO at the end of the 1980s when ESPs were introduced to the field. The sanding s
 eld case examples this paper presents our current well construction and completion design analysis based on the following approach: (1) ca
presented as SPE�100948 at the 2006 SPE International Oil & Gas Conference and Exhibition in China held in Beijing 5-7 December 200
presented as SPE�100948 at the 2006 SPE International Oil & Gas Conference and Exhibition in China held in Beijing 5-7 December 200
  escribed a case study involved an investigation in a field in Libya where massive unexplained fill had been reported accompanying obstructi
  escribed a case study involved an investigation in a field in Libya where massive unexplained fill had been reported accompanying obstructi
 only acknowledged in the petroleum industry that water cut increases sand-production risk and a number of possible mechanisms have bee
 only acknowledged in the petroleum industry that water cut increases sand-production risk and a number of possible mechanisms have bee
nd mechanisms leading to sanding are described within an integrated-rock and soil-mechanics framework.� While the conventional sandin
nd mechanisms leading to sanding are described within an integrated-rock and soil-mechanics framework.� While the conventional sandin

 ction rates of coalbed gas wells commonly vary significantly even in the same field with similar reservoir permeability and gas content. The c
sand control in long horizontal wells is difficult and particularly challenging in offshore fields. It is therefore imperative to make decisions with
sand control in long horizontal wells is difficult and particularly challenging in offshore fields. It is therefore imperative to make decisions with
he stacked reservoirs of the Bokor field offshore Sarawak Malaysia are prone to sand production the field-development team did not opt a
 rovides a case study of an intervention effort which returned to production three wells that had been on extended shut in two subsea and on
r introduces a predictive tool that forecasts the drawdown associated with the onset of sanding as well as it predicts the sanding rate in real t

r introduces a predictive tool that forecasts the drawdown associated with the onset of sanding as well as it predicts the sanding rate in real t
production prediction models to date have the capability to indicate whether initial sand production may take place during the lifetime of a res
duction of hydrocarbons the formation is subjected to increasing levels of effective stress resulting from the reduction in pore pressure. In
presents a geomechanical study on the potential of wellbore instability and sand production for a multi-field gas development in offshore Pen
and iron sulphide scales are known to be particular issues with gas production fields particularly those producing from HP/HT reservoirs.�
S�r field operated by Hydro Oil & Energy is situated 130 km west of the Norwegian coast on the eastern flank of the Viking Graben structu
dy the available methods and software to predict the well productivity and total skin factor in fully perforated vertical wells have been reviewe
ombination of analytical calculations and 3D finite-element simulation we have developed a comprehensive skin-factor model for perforated h
 ic surfactant systems are used in the industry for several applications. Initially the application was focused on low-friction and solids-suspens
an acid fracture treatment is to generate a highly conductive pathway of sufficient length from the reservoir to the wellbore. Depth of penetrat
 of acid solutions injected into hydraulic fractures created in carbonate formations can be assessed at the laboratory scale in acid fracture co
an acid fracture treatment is to generate a highly conductive pathway of sufficient length from the reservoir to the wellbore. Depth of penetrat
ng has been an integral part of Aramco’s gas development strategy for the vertical wells in the Khuff carbonates over the last several yea
  ng has been an integral part of Aramco’s gas development strategy for the vertical wells in the Khuff carbonates over the last several ye
 ic-surfactant (VES) -based diverting products have been used successfully in matrix acidizing in the Gulf of Mexico (GOM) in recent years.ï¿
presents the prejob engineering process and executional summary of the first North Sea application of a novel tubing-conveyed fracturing tec


 rting-acid based on viscoelastic surfactant (SDVA) has been successfully used recently on numerous stimulation treatments of carbonate fo

ecember 2003 and February 2005 eight wells were stimulated in Tengiz field in Kazakhstan using a viscoelastic diverting acid system to eva

 s of a stimulation technique is often measured by its stimulation ratio. This paper however presents a novel way of calculating the value tha
uring treatments are used commonly to enhance the productivity of carbonate formations with low-permeability zones. Various forms of hydro
 ecember 2003 and February 2005 eight wells were stimulated in Tengiz field in Kazakhstan using a viscoelastic diverting acid system to eva
¿½ formation (Cretaceous age Campos Basin Brazil) is predominantly an oolitic and oncolitic grainstone and packstone limestone with a b
matrix acidizing in Kuwait’s horizontal openhole wells is a big challenge. Reservoir heterogeneity and the length of the horizontal wells ma
 il and gas production from the Brown Fields is now more important than ever to the operating companies as the oil price remains record hig
 our water injectors in carbonate formations in Saudi Arabia sulfide scavenging prevention of sulfur and iron sulfide precipitation is a major
of carbonate reservoirs is often considered a routine operation. When the reservoirs are thick (more than 200 m) the stimulation process is m
  acid is the most commonly used acid for carbonate acidizing due to its low cost and high dissolving power. However there are two major dr
 iyah field is one of the biggest sub fields and older producing sections in the giant Ghawar structure. A few wells have been dead for sometim
ndustry experts have compiled their years of experiences in developing a new technical standard to measure stimulation and gravel-pack flui
os formation is thick laminated sandstone with less than 10% of total clays and permeability ranging from 20 mD to as high as one Darcy.�
 ld in the south of Colombia was initially put on production in 1969 and has produced continuously since then. The most prolific reservoir is th
e of matrix treatments in carbonate reservoirs is to increase connectivity of a formation with the wellbore in the entire zone of interest. Succe
y of oil exploited from Russian oilfields today comes from the Volga-Urals and Western Siberian basin where large-scale fracturing and coile


productivity loss occurs in gas-condensate wells when the bottom hole flowing pressure drops below the dewpoint pressure. The decline in p
nate reservoirs are heterogeneous at multiple-length scales.� These heterogeneities strongly influence the outcome of acid stimulation tre
a significant gas producer and LNG exporter within Asia-Pacific region. Many of the country’s gas fields are offshore carbonate reservoir
describes a sensitivity study on the main factors affecting a polymeric Relative Permeability Modifier (RPM) treatment in the near wellbore re
n of existing wells represents a vast underexploited resource. A successful refracturing treatment is one that creates a fracture having highe

  carbon dioxide (CO2)–foamed fracturing fluids were used to stimulate wells in the Waltman field in Wyoming—due to the low formation p
fluids are commonly used to fracture stimulate formations with low reservoir pressure as well as formations that are more sensitive to water t
  carbon dioxide (CO2)–foamed fracturing fluids were used to stimulate wells in the Waltman field in Wyoming—due to the low formation p
 lation techniques like hydraulic fracturing which can involve large financial investments call for a basin- or reservoir-specific approach to m
uction from gas condensate reservoirs significant productivity loss occurs after the pressure near the production wells drops below the dew p

cking in some gas-condensate reservoirs is a serious problem when the permeability is low (for example of the order of 10 md or less). The
 s and condensate drop out near the wellbore in a gas reservoir can cause rapid production decline. The liquid (water/condensate) is trapped
 s and condensate drop out near the wellbore in a gas reservoir can cause rapid production decline. The liquid (water/condensate) is trapped
 ted wells producing from the mature carbonate formation in northern Kuwait are encroached by injected water from adjacent wells presentin
on via real-time reservoir monitoring and optimisation is one of the main drivers for the increasing implementation of intelligent (I-)well comple
pletions that can remotely control the flow from multiple layers of a reservoir interval were introduced in the mid 1990’s. Downhole flow-co
pletions that can remotely control the flow from multiple layers of a reservoir interval were introduced in the mid 1990’s. Downhole flow-co
mer effects resulting from the shutting in of water injection wells are an often ignored issue in petroleum production operations but they have c
mance of a horizontal (highly slanted) well (HW) or a slanted well (SW) is generally believed to be better than that of a vertical well (VW) due
 osts continue to escalate in the deepwater environment there is greater pressure on operators to deliver wells in a more efficient manner. Th
  (sonic and ultrasonic) of cement bond log tools are run in tandem as part of ZADCO’s standard cement evaluation program. The effecti
  (sonic and ultrasonic) of cement bond log tools are run in tandem as part of ZADCO’s standard cement evaluation program. The effecti
 ses what have been done differently best practices and learning. What is different in this campaign from previous ones? Detailed design
oducing light sweet oil from an Albian age reservoir buried between 3100m and 3400m TVD. In order to access reserves located in the south
 arbonates at high reaction rate to create flow channels (wormholes"). The high reaction rate often needs to be reduced to allow wormholes to
elivering the required rates from Saudi Aramco fields. Therefore this form of artificial lift was selected to increase production rate from one o
Unlike conventional surface powered jet pumps these pumps are hydraulically powered by a prolific producing upper zone called the C sand



process is dependent on the economics and value of the method. In the Southern Offshore area of Chevron operations there are huge cost
 e midst of various artificial lift type choices. These challenges become more complex with increasing dynamic changes in well characteristic
pletion cannot be used due to the extreme temperatures of the downhole environment. Most lift gas enters the production stream downhole v
                                                                                          Suncor's
 nada's nonconventional oil reserves are estimated at just over 1 trillion barrels andOnePetro heavy oil reserves in northern Alberta Canada
g and the wells are unable to flow naturally. Over the years a number of artificial lift techniques have evolved as a result of extensive research
 well production potential. Horizontal wells are more susceptible than vertical wells to formation damage due to the longer completion length
 contact have been paralleled by advances in completion equipment development of both Passive" Inflow Control Devices (ICDs) and "Active
                                                                                        OnePetro
 e 1 100 MMscf/D of wet gas strip out 110 000 B/D of condensate/LPG initially reinject 950 MMscf/D of lean gas and later export up to 700
nt project and the engineering issues addressed to facilitate achieving the project goals of producing gas at high rates from the shallow uncon


ides intelligent-well completion (IWC) options included commingling two reservoirs of contrasting conductivity (permeability-thickness produc
six high rate gas fields currently on production with several more in planning stages. All of the wells require sand control and this has resulte
had been drilled practically all the reserves of the main reservoirs within the production targets were put into production. There emerged a ne
dstone gas reservoirs in this field have net pays with a thickness greater than 300 m and an average true vertical depth (TVD) of 1 400 m. T
                                                                                        by Repsol-YPF. The
 Gulf of San Jorge Basin Santa Cruz province Argentina. The field is fully operatedOnePetro OnePetro paper narrates the challenge and e
a. This new method places sliding sleeve valves in the casing string and completes the well with normal cementing operations. The sliding sl
 rizon. The Cartojani structure is located in the central alignment of the Moesic Platform. It is a monocline with large dimensions and low laye
gh conventional wells have been applied to drain reservoirs in Niger-Delta extensively in recent years horizontal wells have also gained acc
g of phosphonate reactions during inhibitor squeeze treatments has direct implication on how to design and improve scale inhibitor squeeze
lls to optimize gas recovery in wells that produce free liquids in conjunction with the gas.� Particularly important in this work has been the
lls to optimize gas recovery in wells that produce free liquids in conjunction with the gas.� Particularly important in this work has been the

one with “good porosity.� Matrix permeability is low and natural fracture density can be quite variable in this reservoir.� Thus this re
one with “good porosity.� Matrix permeability is low and natural fracture density can be quite variable in this reservoir.� Thus this re
                                                                                        horizontal
has relatively heavy oil in place that is high in viscosity. With the understanding thatOnePetro or multilateral profiled wells are the most favora
  achieve optimal production via choke performance management. A Generalized Predictive Controller (GPC) has been shown to be capable
ervoir Contact (MRC) Multilateral (ML) and Smart Completion (SC) deployment in Ghawar Field.� The well was drilled and completed as
uids across the reservoir strata. Historically completions with cemented casing packers conformance controlling fluids/gels and selective p
um reservoir contact (MRC) multilateral (ML) and smart completion (SC) deployment in Ghawar Field Saudia Arabia. A well was drilled and
s) using sequential linear programming (SLP). The optimization algorithm requires instantaneous and derivative information. We propose a w
                                                     OnePetro
 ars as part of the reservoir development strategy to maximize well productivity through maximum reservoir contact. Although these wells are
 ontal and multilateral wells in all types and shapes. Horizontal and Multilateral applications become more commonplace to improve the well p
well zone date from sixties. Among the proposed mechanisms to explain the enhancement in gas effective permeability and also the higher
                                                                                        OnePetro OnePetro
d 15 subsea injection wells. Maximizing water injection volume is an important economic objective for Bonga. Water injection is used for main
have had a long and successful history in the Norwegian Sector of the North Sea and in Saudi Arabia.�This paper will document the first
 neral the purpose of the second pump was either to increase the pumping capacity or to act as a backup to improve the reliability of the pu
                                                                                        OnePetro
 neral the purpose of the second pump was either to increase the pumping capacity or to act as a backup to improve the reliability of the pu
 xcess of 800 MMcf/D from three wells. The completion design selected was 7 inch production tubing with an open-hole gravel pack. The initi
em was designed for perforating wells lifted with electrical submersible pumps (ESPs). The purpose of this project was to develop and apply
                                                                                        OnePetro
e pump (ESP) system performance data. The approach extracts unbiased information from performance data and permits lifetime modeling
e pump (ESP) system performance data. The approach extracts unbiased information from performance data and permits lifetime modeling
ions in many areas. It provides the desired flexibility in controlling pressure profile and equivalent circulating density (ECD). However the kn

w into a slotted-liner completion is quite complicated due to three dimensional flow convergence around slots and limited open-to-flow areas.
ginning of the gas development program. Various types of acid systems including conventional emulsified and surfactant-based have been u
 along the maximum principle stress and dominant fault orientation (northwest/southeast). Open-hole completions were considered the best c
 along the maximum principle stress and dominant fault orientation (northwest/southeast). Open-hole completions were considered the best c
   Danish North Sea. To date seven horizontal wells (2900 m total vertical depth [TVD]) have been completed using 100 tip screenout (TSO)
                                                                                        OnePetro
 act angle and provide leakoff control. However many of these chemicals adsorb rapidly within the first few inches of the sandstone formatio
n permitted and more than 200 wells are now producing. The lateral play began in Richland County Montana and the success there is now a
s in the Western Siberia basin as a significant number of the oil-bearing formations in the basin are located near a water zone. These hydrau
 rtical wells in the Khuff carbonates over the last several years. During acid fracturing the wormholes created by the reaction with the formatio
e largest oilfield in Western Siberia. Placement advantage of fiber-assisted fluid already becomes obvious after initial campaign of four fractu
even wells with a total of seventeen fracturing treatments in this study are on a multilayered unconsolidated formation where sand control is
d water blocks. As the gas reservoirs being stimulated become tighter the perceived value of these additives has grown. This value must be
acture height containment in layered formations. It has been well documented that in situ stress contrast is the dominant parameter controllin

 e need for proven weighted fracturing stimulation fluids has become urgent. As previous studies have shown frac packs have a significant
  letion and declining quality of reserves have resulted in escalating drilling completion and workover costs per unit of gas produced. This in
 th disposing flowback and produced water to reduce costs handling the logistics of getting enough water to hydraulically fracture the well as
 od as a means of production enhancement from tight gas reservoirs. The first optimum fracture design (OFD) approach which maximizes w
voir’s deliverability and what the optimum fracture half-length is as a function of geological setting and stress state.� The application an
depleted sandstone formations located in Bachaquero T�a Juana and Lagunillas fields in West Venezuela. This technique combines stim
from underlying water zones by a weak stress barrier. Operating and service companies alike applied various techniques to prevent the brea
 cesses and methods to consider for placement fractures. Optimization of the completion process including the number and size of fractures
red over vertical and deviated wells offering the advantage of maximized reservoir contact higher production rates and better access to rese
 resent one of the main gas producers in Argentina. The completion programs of Aguada Pichana wells imply the stimulation of Middle Mulic
 cuts. These wells are commonly not considered as good candidates for matrix stimulation. Water based treating fluids would enter preferen
Complex geology and low permeability are the common denominator in today’s environment. Developing reserves under these conditions
 tain the economic operation of their valuable assets. Large quantities of reserves can be found in low permeability consolidated formations
                                                                                       OnePetro OnePetro
  wells to achieve maximum reservoir contact to maximize well productivity. This strategy has proven very successful over the past few years
                                                   OnePetro
ure. In this environment emphasis is placed on high-efficiency operations based on specially tailored solutions combining available resources
                                                   OnePetro
   The pressure losses caused by these phenomena are accepted widely to be of great significance in most gas-well completions in the United



  The pressure losses caused by these phenomena are accepted widely to be of great significance in most gas-well completions in the United
  The pressure losses caused by these phenomena are accepted widely to be of great significance in most gas-well completions in the United
pproximately 30 000 bopd and is on decline. A joint team from ONGC and Schlumberger carried out a rigorous process of candidate selectio
 ction performance of a vertically fractured well located in a closed rectangularly bounded reservoir.� The solution for dimensionless produ
                                                                                      OnePetro
 ed formations exhibit a non planar or complex set of micro seismic events. This fracture mapping technique has provided some valuable ins
d service companies have gathered significant amount of experience and knowledge. The sweeping success of hydraulic fracturing in Weste
 ique.� The evolution of the completion technique has reached the point that numerous stimulation stages through multiple perforation clus
                                                                                      OnePetro OnePetro
orporation. This new method placed sliding sleeve valves in the casing string and completed the well with normal cementing operations. The
ng sleeve valves in the casing string and complete the well with normal cementing operations. The sliding sleeves would then be opened on
 r existing programs used with soft rock formations often do not provide satisfactory treatment designs. Difficulties emerge because hydrauli
 ons without the use of polymer additives.�VES fluids do not form polymer filter-cake and thus viscous resistance of the fluid flowing thro
                                                                                      OnePetro
 prove the Olmos production in the Caterina SW field in Texas. The reservoir is characterized by thin streaks of pay with potential water pro
mped using a solids-free liquid CO2 foam-based visco-elastic surfactant (VES) fluid system in Morrow Sand reservoirs located in Southeast N
 uced with six to ten barrels of water. The production of water results in increased operating expenses along with other water related well pro
                                                                                       OnePetro
 gth.� The creation of effective fracture length requires that sufficient fracture conductivity be developed to allow effective fracture fluid clea

mance in this area was not promising. Well Raguba E-97 in this area was not producing even several attempts such as acidizing re-perforati
                                                                                       OnePetro
                                                                                        gas-condensate reservoirs where fracturing considered a
 voted to improve its prediction performance. However the effect of cleanup in tightOnePetro
 ssful implementation of acid fracturing treatment in Marrat field. The acid fracturing treatment is quite challenging due to presence of high pre
 rac and Pack completions exhibit positive skin values and traditional hydraulic fracture completions show discrepancies between the placed
 rac and Pack completions exhibit positive skin values and traditional hydraulic fracture completions show discrepancies between the placed
                                                  OnePetro
mechanisms by invasion of fracturing fluid (FF) into the matrix and fracture and poor cleanup efficiency. In the last four decades fracture face




rac and Pack completions exhibit positive skin values and traditional hydraulic fracture completions show discrepancies between the placed
 eservoirs.� This existing technology is being utilized in new and innovative ways to provide operators a clearer picture of the fracture deve
                                                                                    OnePetro
or this behavior are related to the characteristics of the porous media and are induced as a consequence of the fracturing process. Fracture
rforming accurate borehole deviation surveys for hydraulic fracture monitoring (HFM) and neglecting the effects of the deviating borehole traj
mic and surface tiltmeter fracture mapping was performed on ten wells in two areas of the field and over 100 fracture treatments were mappe

 An engineer can be overwhelmed with the selection of completion fluids perforation strategy and treatment size as well as coordination of f
 acid; without nonuniform dissolution along the fracture face the fracture will close after pumping ceases and little lasting conductivity will be
act the field development strategy. The correct estimation of the fracture dimension is critical to maximize the recovery factor of heterogeneo
nsight about the fracture height (near-wellbore vertical coverage) of proppant-packed fractures. The existing tracer technology has a number
                                                     with a shale
here are two producing horizons of Jurassic age OnePetro barrier in between them and variable oil/water contact (OWC). Each new well of
 ity oil reservoirs there is still no simple practical production forecasting methodology for hydraulically propped fracturing stimulations for th
  sandstone reservoir using a numerical model. The fracture was explicitly modeled as a set of high-conductivity cells. At the gas velocities
 meability formations under downhole reservoir conditions a severe pressure drop occurs at the tip of the fracture and a lag zone develops d
 of acids such as regular in-situ gelled and emulsified acids have been used in order to achieve optimum fracture length and conductivity. A
hematical model used in this work is a practical alternative to estimate the degree of stimulation by means of a Stimulation Index (SD) and fo

n Skinner Ridge (SR) #698-22-1 well Williams Fork Formation (Late Cretaceous) Garfield County western Piceance Basin western Colora
ault. Fracture orientations were identified through a combination of alignment of event locations polarization of the seismic waves and inject
                                                                                       OnePetro
 pletion options are available for potential deployment in new wells especially those in deep water and offshore; however the cost could vary
 problems for well completion. Various models have been developed to predict the onset of proppant flowback but the physics of the phenom
atment is studied by taking into account the production induced stress field surrounding the initial fracture. It is shown that the propagation pr
nt frontal displacement of fluids from subterranean environment. Entrapment of residual fluid by the displacing one lowers down the displace
                                                                                       OnePetro of hydraulically fractured wells using the existin
has been devoted to study their performance under different prevailing conditions. Description OnePetro
xtent. An excessive fracture length may lead to an earlier than desired increase in water cut. Uncertainty in propped fracture dimension is rela
a Joint Industry Project active since the year 2002. It is well documented in the literature that hydraulic fractures although successful often
                                                                                       OnePetro
a Joint Industry Project active since the year 2002. It is well documented in the literature that hydraulic fractures although successful often

                                                                                         OnePetro
ents.� This paper is a look back after five years of operation.� It includes a review of the goals of the project and issues that occurred d
ctors eighteen producers and one gas injector to be completed in more than 4 300 ft of water depth. In order to maintain the oil production t
ast Brazil – Carm�polis and Sirizinho Fields – on the revitalization of the oil production. The purpose of this work is to demonstrate the
 n made to reproduce their effects on fracture growth using numerical hydraulic fracture models. Such offsets have long been recognized as
 The objective of the initiative is to increase the ultimate recovery in their respective chalk assets to 60%. Analyzing the different production t
 years considerable effort has been directed towards understanding of flow around hydraulically fractured wells especially for tight gas reserv
The field is producing principally from a Devonian age carbonate reservoir this limestone formation having an average porosity of 8 to 12% a
  of tight gas sands with large hydraulic fracturing treatments requires cost effective and time saving operations. Traditional large fracturing jo
 technology by describing recent developments for readers who are not specialists in the topics discussed. Written by individuals recognized
onstraints can severely limit oil production and reservoir drive energy. In this paper we will use a coupled reservoir-well model to demonstrat
on to gas lift a well. The gas lift gas is produced downhole and bled into the production tubing via an auto gas lift valve designed for gas oper
six high rate gas fields currently on production with several more in planning stages. All of the wells require sand control and this has resulte
e near wellbore matrix thereby reducing gas (and water) coning or eliminating gas leakage to the surface. Experiments at micro- and macro

 w. The former has been studied extensively recently but the understanding of the latter is limited. High-velocity gas flow in single phase has
 one formations is a questionable procedure. It is necessary to remove not only the filter cake at the well bore face but more importantly th
y applications. As nominally horizontal wells get longer and follow more complicated trajectories wellbore hydrodynamics becomes an impor
 always deliver the required rates to support offtake and achieve voidage replacement. Thus horizontal wells are often selected to provide be
rs being eclipsed with open-hole technology. These completions have allowed multiple zones to be fractured and the benefits of utilizing ope
rs being eclipsed with open-hole technology. These completions have allowed multiple zones to be fractured and the benefits of utilizing ope
hole wells is preferred to maximize reservoir productivity. Some questions that always come up for this type of wells are: will it be necessary
hole wells is preferred to maximize reservoir productivity. Some questions that always come up for this type of wells are: will it be necessary
ons on the North Slope of Alaska and one of the first in the world. The purposes of this paper are to examine why this completion technique
 ion of one smart and two problematic conventional long and tortuous horizontal wells in Brunei. Following a detailed hydraulic analysis of th
 ncern because the existing Anti-Agglomerants Low Dosage Hydrate Inhibitor (AA LDHI) used during extended shutdowns and cold restarts
 hat blockage the gas flow efficiency to the well. Not only is the gas well productivity affected by fluid but also velocity. The conventional theor
                                                                                        wells completed with ESP. As fields age and produced w
 ated with surveillance and interventions in horizontal and TAML level 2 multilateral OnePetro


 need to perform an intervention to collect data. One of the commercial permanent monitoring technologies is the fiber-optic DTS which can

h Sea in May 2004. The completion includes one on/off and three variable downhole chokes for controlling injection rate into each of the four
 ies that allows commingled oil production from multi-laterals wells in Shaybah inside expandable liner.Slim intelligent completions technology
medium-sized oil and gas fields to the world's second deepest permanently moored production facility. Production from 12 subsea wells in w
ns in many reservoir situations. However they are still susceptible to coning toward the heel of the well despite their maximizing of reservoir
water coning towards the heel (water can breakthrough anywhere in the well not only at the heel due to permeability (K) variation and proxim
  control using Interval Control Valves (ICVs) with the installation of flow monitoring devices. The “Added Value for an IW is dependent o
ology has evolved from intervention-less completion for sub-sea wells to new applications where intelligent completions are delivering better w
with installation of appropriate flow monitoring devices to improve well and field performance management. Zonal flow control can maximise


apacity under facility constraints. Agbami field a highly-dipping reservoir with many producing zones and few wells will use an intelligent wel
 tion technologies that allows commingled oil production from quad laterals wells in Abqaiq field. Many intelligent completions wells have bee
 h respect to properly incorporating the impact of reservoir uncertainty. Most optimization methods are model-based and are effective only if
w permeability rock (Colton sandstone) are presented. The focus of this experimental study was to assess the effects of discontinuities on hy
w permeability rock (Colton sandstone) are presented. The focus of this experimental study was to assess the effects of discontinuities on hy
 siderably reduce gas mobility. The nature of the gas and the surfactant may influence foaming behavior and thus the efficiency of the foam.
 on the effect of the core heterogeneity. In the frame of the model presented in a parent paper in the conference we assume that the bubble
bubble population foam model and provide a detailed experimental validation. We present systematic experiments consisting of the co-inject
ate a gas well’s flowing conditions to determine if the well is experiencing liquid loading problems. Literature detailing the critical velocity n

roduction significantly declined with high water-cut. The well was shut down and then brought back to production observing much reduced fl
 ds are no longer carried to surface. The liquids accumulate in the well bore increasing the sand face pressure. This further reduces the inflo
on maximizing gas production from existing wells. In most gas wells water and/or condensate is produced along with gas. In mature gas we
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 reservoir energy is insufficient to transport liquid particles to surface liquid falls back and builds up a hydrostatic column in the wellbore that
tion. Even though virtually all of the world’s gas wells are either at risk of or suffering from liquid loading the modeling of liquid loading b
 nd coal bed methane is that the ultimate recovery is dependent on economic removal of liquids accumulation generally termed “deliquif
pressures are insufficient to lift liquids out of wellbores. Various technologies to artificially lift liquid associated with gas production exist how
ir pressure depletes and gas velocity decreases. Below the critical rate liquids cannot be lifted from the wellbore and instead settle to the bo
 e a combination of the following characteristics: a) they use external energy b) they use consumables and c) they restrict gas production. T

nd casing pressures liquid accumulation liquid fallback and the resistance force to the plunger. The characteristics of the tubing and casing
 in a gas well is responsible for well-productivity decline and left untreated will eventually result in the well loading up and ceasing to produce
ssed with very long horizontal wells (2000 to 20 000 feet of reservoir section.) These wells are often acid stimulated to remove drilling fluid filt

methane reservoirs and “heavy oil from weakly consolidated formations. In the 1990s the technique was applied to conventional wells wh
 PL) measurements with nodal analysis evaluation. This allows the effects of various completion modifications to be quantitatively modeled
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ciently to improve the appraisal process and avoid unnecessary expenditure. At the same time an accurate reservoir characterization is the k
ally coincide with an increase in depletion water cut or changes in the artificial lift mechanism used to produce the hydrocarbon. Sanding is d
 nd shot density while minimizing perforation damage.� However in tight carbonate reservoirs creating deep and clean perforations may s
 pleted thus exposing the formation to potentially damaging kill fluid. To obtain a perforation tunnel with maximum productivity this transition
 in intervening highly deviated and long section of horizontal wells under live condition where slickline and E-line have difficulties. This pape
District. Its main productive zones are the Merecure and San Juan formations which are sandstones characterized by their high permeabilitie
 LEP) technique based on reservoir and well simulation of a typical HVO reservoir e.g. Peace River field and theoretical calculations. The is
pment of the HZ oil and gas fields operating as the CACT Operators Group (CACT) in the South China Sea. The HZ fields are stacked thin
ering software tool to guide and advise them.� It needed to address selecting the optimum perforating system for given well and formation
 onsideration in designing the preceding perforating job. Aligning the perforations along the direction of maximum geological stress known as
 onsideration in designing the preceding perforating job. Aligning the perforations along the direction of maximum geological stress known as
 ing completed with the drilling rig until it is acid�stimulated using a multi purpose barge and put on production. Some wells in�ADMA O


 gentina. El Trapial wells are characterized by stratified shallow- to medium-depth reservoirs with permeabilities of 35md to 85md and poros
  reservoirs are typified by significant porosity and permeability heterogeneities such that large fluid loss zones are commonly encountered wh
  reservoirs are typified by significant porosity and permeability heterogeneities such that large fluid loss zones are commonly encountered wh
enhancement operations. Underbalanced perforating (UBP) which is widely used in well completions induces transient fluid flow that provide
operations. Well trajectory temperatures and fluids can create uncertainties on both depth control and the accuracy of hydrostatic cushion b



 iated wells. However in high angle/horizontal wells it has become a major undertaking due to inability of the gravity-assisted electric line to
so possibly cause excessive damage or swell to its carrier. Comprehensive understanding of the post-perforating conditions of the perforator
on induced permeability impairment commonly referred to as the “near wellbore damaged zone. This connection through the damaged zo
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  liner charges against those created with conventional liner charges. Three of the tests involved shots into an outcrop carbonate rock called
ne of drilling and completion induced permeability impairment commonly referred to as the “near wellbore damaged zone. This connectio
 ent characterising the velocity of chemical reaction and the formation damage coefficient reflecting permeability decrease due to salt precipit
sulphate salt precipitation determined typical values of kinetics reaction coefficient from corefloods and what the impact would be on produ
nd provides an opportunity for a water drive when applied during waterflooding.�The required rate of produced water reinjection can be a
                                                  OnePetro
 acceptance because it provides a method of minimizing formation damage preventing lost circulation risks and increasing penetration rates
maximum reservoir contact (MRC) wells. One of the objectives behind this strategy is to improve the well productivity by maximizing oil produ
 ation consolidation the large percentage of fines present in the reservoir the heavy oil the low frac gradients the low net-to-gross ratio the
d improved productivity throughout a well’s lifecycle. This paper discusses the many challenges encountered during the planning and com
 pproximately 2 650 ft true vertical depth (TVD). An appraisal/early-producer well with a deviated wellbore was drilled through the H1 H2 targ
nks block 783 in the Gulf of Mexico. The wells target multiple zones resulting in complex directional wells with 50�-60� maximum hole-a
nks Block 783 in the Gulf of Mexico. The wells target multiple zones resulting in complex directional wells with 50–60� maximum hole a
viable solutions are available to enhance there production to an economically feasible level. The Hawtah field (see Figure 1) discovered in th
elective completion interventions were successfully implemented in the deepwater Gulf of Mexico Petronius field setting both Gulf of Mexico

and the results have been calibrated with production data. Both maximum allowable drawdown and depletion increase with depth. Additionall
 nd contingency fluid-loss control (FLC) pill formulation to withstand 4 600-psi burst resistance pressure. In maturing deepwater fields such
nd H2 at approximately 2 650 ft true vertical depth (TVD). An appraisal early-producer well was drilled with a deviated wellbore through the
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s block 783 in the Gulf of Mexico. The wells produce primarily from thick fine-grained Pleistocene-age reservoirs. Due to the long lengths o
nks Block 783 in the Gulf of Mexico. The wells produce primarily from thick fine-grained Pleistocene reservoirs. Because of the long lengths
court. The field discovered in 1986 currently has 9 wells completed and 13 drainage points. Well A-4L is one of the completed intervals on t
                                                                                    equipment
 ative is to gain a better understanding of Sand Control Completion (SCC) systemsOnePetro performance and reliability in a variety of app

 eved complete annular packs and zero mechanical skin factors resulting in well productivity indices that are significantly greater than expect

 onment. A Chevron offshore gas reservoir will be developed with high-angle near-horizontal wells with openhole gravel packs completion (O
ed reservoirs in Brazil. Gravel pack placement requirements include the design of pumping pressures inside the operational window formed b
 s in Brazil. Gravel pack placement requirements include the design of pumping pressures inside the operational window formed by the minim
                                                     OnePetro
  Gravel Packing (OHGP).� Though gravel packing is a proven method to stabilize the well bore controlling sand and maximizing productiv
 eved complete annular packs and zero mechanical skin factors resulting in well productivity indices that are significantly greater than expect
                                                     OnePetro
quired sand control. The lower zone was completed with a gravel pack completion and the upper zone was left unperforated. To enable produ
 rilling slanted or sub-horizontal wells through several shale bodies to obtain high gas rate performances during the production and the injecti
ability to deliver high-productivity wells. Currently there are two techniques used for gravel placement one utilizing low-viscosity carrier fluids
one sand control wells. Four field developments are challenging the conventional approach to completing long sand control zones by using ne
  southern region of Argentina. These fields are prolific gas producers and are being developed with a reduced number of wells with departu
  in drilling technology in recent years horizontal wells with lengths ranging from 2 000 to 6 000 ft have become more common. Executing the
e gravel packing is the preferred sand control technique adopted by many operators in this region. It is considered one of the proven method


                                                                                        transport OnePetro
servoirs. Recent experience in extended-reach drilling also indicates that inefficientOnePetro of smaller cuttings is a main factor for excessive
cy remediation on two offshore applications. Results are presented detailing specific placement procedures in-situ treatment design and pro
a cased-hole gravel-pack job depends on the ability to effectively pack perforation tunnels which act as conduits between the reservoir and th
 cased-hole gravel-pack job depends on the ability to effectively pack perforation tunnels which act as conduits between the reservoir and th
ough the S1U S1L and S2U sands at ~9200 ft TVD. After a pre-drill sand prediction the well was cased and perforated without sand contro
e tied back to a floating production facility. Nine horizontal oil producers and four S-shaped gas producers are planned and all will require som

ogress with respect to sand control equipment and implementation. However even properly designed and executed completions are subjec
n in Australasia. This recent technology was simultaneously applied in a production well and a water injection well and served as a demonst

minating the need to have a rig on location. To date six screenless completions have been performed for a major operator in the Gulf of Me
minating the need to have a rig on location. To date six screenless completions have been performed for a major operator in the Gulf of Me
                                                                                 OnePetro
have been proposed in the past including various solutions based on permeable cement but none of them have made a real breakthrough.

he largest onshore steamflood operations in the world. Producing heavy oil (approximately 25�API) from an essentially unconsolidated res
present-day. A large part of these challenges have been caused by reactive shales interbedding the sand bodies. This has had a persistent i
  transported to the surface facilities for different operational scenarios. Sand quantification estimation is still novel in the industry and this pa
 ated sandy turbiditic reservoirs. Today in Girassol which includes also Jasmin reservoir 29 wells have been completed and connected to pro
wever in such a situation it is very important to be able to determine the expected sand rate as well as the amount of sand produced during
                                                      OnePetro
are applied to light oil and gas reservoirs the equations controlling generation of eroded solid mass or sand release rate are vastly simplified
 ent in the specific case of Lunskoye to minimise risk of failure while maximising production reducing cost and safeguarding reserves.�
                                                                                       OnePetro OnePetro
 introduced to the field. The sanding severely impaired the performance of field and consequently led to significant economic loss. AGOCO
 sed on the following approach: (1) carry out detailed evaluation or determination of reservoir formation strength distribution using core testing
na held in Beijing 5-7 December 2006. Abstract Sand production is a major concern for many operators. It can impact production cause er
na held in Beijing 5-7 December 2006. Abstract Sand production is a major concern for many operators. It can impact production cause er
een reported accompanying obstruction of production for majority of production wells since the onset of production indicating possible sandin
een reported accompanying obstruction of production for majority of production wells since the onset of production indicating possible sandin
 er of possible mechanisms have been proposed. This paper presents the results of a series of laboratory perforation-collapse tests aimed at
 er of possible mechanisms have been proposed. This paper presents the results of a series of laboratory perforation-collapse tests aimed at
 rk.� While the conventional sanding models generally consider a single-mechanism for sanding namely the critical depletion resulting in r
 rk.� While the conventional sanding models generally consider a single-mechanism for sanding namely the critical depletion resulting in r

 r permeability and gas content. The compositional variation in produced gas is also not everywhere predictable although in most fields produ
 re imperative to make decisions with regard to the most optimum completion type objectively and based on reliable assessment of the sand
 re imperative to make decisions with regard to the most optimum completion type objectively and based on reliable assessment of the sand
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 field-development team did not opt a priori for gravel packs in every well. While such completions can indeed eliminate sanding risk the team
 extended shut in two subsea and one dry tree in a mature BP operated Gulf of Mexico deepwater field. The three wells involved in this oper
 s it predicts the sanding rate in real time. Experimental data on hollow cylinder samples (HCS) are used to support the validity of the numeric

 s it predicts the sanding rate in real time. Experimental data on hollow cylinder samples (HCS) are used to support the validity of the numeric
ake place during the lifetime of a reservoir but they are unable to predict whether the sand production will be ‘problematic’ (excessive
                                                                                          OnePetro OnePetro
m the reduction in pore pressure. In weak but consolidated sandstones this can lead to shear failure in the rock surrounding the perforation
eld gas development in offshore Peninsular Malaysia. The objectives of the study were 1) to develop strategies to maintain mechanical and t
producing from HP/HT reservoirs.� The Elgin/Franklin Field is located 240 kilometres east of Aberdeen in the Central Graben Area of the
 ern flank of the Viking Graben structure. It comprises a sequence of fault-bounded structural units of varying geological complexity. Within th
  ted vertical wells have been reviewed. The methods have been compared against the experimental data obtained on an electrolytic apparatu
sive skin-factor model for perforated horizontal wells. In this paper we present the mathematical model development and validation by compa
 ed on low-friction and solids-suspension (fracturing and CT-cleanout) characteristics of the fluid. In the last 4 years the application of viscoe
 oir to the wellbore. Depth of penetration of live acid is the critical factor in determining the success of an acid-fracturing treatment. Depth of p
 e laboratory scale in acid fracture conductivity tests that mimic the conditions in an actual acid fracture treatment. We conducted a series of
 oir to the wellbore. Depth of penetration of live acid is the critical factor in determining the success of an acid-fracturing treatment. Depth of p
   carbonates over the last several years. The Khuff formation is a deep gas carbonate reservoir that is ideally suited for acid fracturing. Durin
 f carbonates over the last several years. The Khuff formation is a deep gas carbonate reservoir that is ideally suited for acid fracturing. Durin
 f of Mexico (GOM) in recent years.�� The uses of VES diverters range from remedial matrix-acid or nonacid-cleanup treatments to use
   novel tubing-conveyed fracturing technique. The logistical challenges that were overcome during the completion of the project will also be d


 imulation treatments of carbonate formations in various fields. �The decrease of acid concentration during the spending process viscosif

coelastic diverting acid system to evaluate the effectiveness of this system in achieving diversion and zonal coverage in large limestone res

                                                   OnePetro
novel way of calculating the value that can be added from acid fracturing. A model predicting the effect of acid fracturing in carbonate reservo
eability zones. Various forms of hydrochloric acid (HCL) are used to create deep etched fractures. However regular HCl reacts very fast with
coelastic diverting acid system to evaluate the effectiveness of this system in achieving diversion and zonal coverage in large limestone res
 ne and packstone limestone with a bottomhole static temperature (BHST) of about 150�F. The formation permeability often exceeds one
  the length of the horizontal wells make acid placement and diversion difficult particularly in high-water-cut (WC) wells in which water has br
 s as the oil price remains record high. Matrix stimulation is often preferred as it could generate additional production gain with relatively low
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d iron sulfide precipitation is a major requirement during acidizing treatments. �As the acid spends on the carbonate surfaces and in the p
n 200 m) the stimulation process is much more complex because factors such as reservoir heterogeneity damage to each zone matrix mine
wer. However there are two major drawbacks associated with using concentrated HCl solutions in deep wells. The first is its high reaction ra
 ew wells have been dead for sometimes due to high water cut (60 to 80%). In all cases the target interval was only 5’-10’ at the top o
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 sure stimulation and gravel-pack fluid leakoff under static conditions. This method details step-by-step procedure for making fluids and meas
                                                                                       OnePetro
m 20 mD to as high as one Darcy.� However the production from this formation is often limited due to the low critical flow rate in the matrix
 then. The most prolific reservoir is the Caballos Formation a thick (250 ft avg.) laminated sandstone located at a depth of 6100 to 7500 ft th
  in the entire zone of interest. Successful matrix treatments depend on the uniform distribution of the treating fluid over the entire interval. W
where large-scale fracturing and coiled tubing operations have been on-going for the past six years.� In the mainly brown fields tertiary rec


 dewpoint pressure. The decline in productivity is due to near-well accumulation of condensate in the reservoir rock which is significant even
 e the outcome of acid stimulation treatments which are routinely performed to improve well productivity.� However most previous studies
 lds are offshore carbonate reservoirs. The exploitation of these reserves involves drilling horizontal wells for maximizing reservoir contact an
PM) treatment in the near wellbore region of a mature oil producing well. The study is divided into several parts where various factors which a
 that creates a fracture having higher fracture conductivity and/or penetrating an area of higher pore pressure than the previous fracture. Re

 yoming—due to the low formation permeability and rock properties—and have been proven effective but still not perfect. Limitations on th
ons that are more sensitive to water treatments (high capillary pressure swelling clays etc). In particular the Frontier Formation located in Bi
 yoming—due to the low formation permeability and rock properties—and have been proven effective but still not perfect. Limitations on th
- or reservoir-specific approach to maximize production. Integrated solutions use a performance-based process that integrates petrophysic
oduction wells drops below the dew point of the hydrocarbon fluid. Many of these gas reservoirs also have some water accumulation near th

                                                                                      OnePetro OnePetro
   of the order of 10 md or less). The current practice centers mainly on hydraulic fracturing to improve gas flow. In most cases the frequency
                                                                                      OnePetro
e liquid (water/condensate) is trapped near the wellbore due to strong capillary forces and/or viscous fingering of gas through the liquid. To re
                                                                                      OnePetro
e liquid (water/condensate) is trapped near the wellbore due to strong capillary forces and/or viscous fingering of gas through the liquid. To re
   water from adjacent wells presenting a challenge for the operating company. Greater oil demand coupled with limited surface water handlin
mentation of intelligent (I-)well completions. The benefits from these more expensive completions will be realized through increased reserves
he mid 1990’s. Downhole flow-control (DHFC) as it has become known has since been installed in hundreds of wells. However there h
he mid 1990’s. Downhole flow-control (DHFC) as it has become known has since been installed in hundreds of wells. However there h
production operations but they have considerable impact on injection well performance and longevity. Mismanaged they can result in substa
  than that of a vertical well (VW) due to its greater exposure to the reservoir. However the costs of drilling and completion are more and the
 r wells in a more efficient manner. This paper will review the drilling and data acquisition strategies to successfully deliver a challenging deep
ment evaluation program. The effectiveness of these tools and their evaluations are often challenged and are not regarded as a replacement
ment evaluation program. The effectiveness of these tools and their evaluations are often challenged and are not regarded as a replacement
 m previous ones? Detailed design Detailed well-by-well review for first round candidate selection. Fundamental data collection (well data
 access reserves located in the southernmost compartments of the reservoir Extended Reach Drilling (ERD) was implemented. Six ERD we
s to be reduced to allow wormholes to penetrate deep into the reservoir hence extending the effective wellbore drainage radius. The wormho
 increase production rate from one of the offshore fields while optimizing offshore producing facilities. This offshore field has favourable con
ducing upper zone called the C sand to generate greater drawdown on a less productive lower zone called the A sand. Formation powered je



vron operations there are huge cost implications in the implementation of gas lift on several offshore jackets. New facilities for gas lift opera
 namic changes in well characteristics over the life of a well. This paper presents a case study on artificial lift selection strategy for unloading
ers the production stream downhole via open-ended tubing or nozzles which if not properly sized can result in operational issues such as flu

lved as a result of extensive research and ground work. All the systems have proven their worth by increasing the productivity of the field by
due to the longer completion length the longer drilling time the potentially increased overbalance and the reduced cleanup efficiency caused

 lean gas and later export up to 700 MMscf/D of lean gas to a LNG plant in Darwin. The initial development called for 16 North Sea-style 7 in
  at high rates from the shallow unconsolidated sand stone reservoirs. The main challenge in terms of completion architecture was to maxim


ctivity (permeability-thickness product) and selectively perforating zones or reservoirs to offset the permeability contrast. At the outset a valu
uire sand control and this has resulted in five sandface completion types (Open Hole Gravel Pack Cased Hole Frac Pack Cased Hole Grav
 into production. There emerged a necessity to develop the oil-water zones and marginal areas zones with poor reservoir properties and min
e vertical depth (TVD) of 1 400 m. The original development project for this field did not include sand control for the initially forecasted produ

 cementing operations. The sliding sleeve valves are opened one at a time to fracture layers independently without perforating. Completions
e with large dimensions and low layer inclinations. The main hydrocarbon accumulation is found in the Sarmatian formation (Base Cretaceou
horizontal wells have also gained acceptance as a proven reservoir management and well completion method. Production improvement facto
and improve scale inhibitor squeeze treatments for optimum scale control. Putting various amounts of metal ions in the inhibitor pill adds ano
 important in this work has been the evaluation of the conditions for which the well outflow velocity is less than that which would be required t
 important in this work has been the evaluation of the conditions for which the well outflow velocity is less than that which would be required t

ble in this reservoir.� Thus this reservoir must be exploited using horizontal wells in all areas.� In areas where fractures may not be do
ble in this reservoir.� Thus this reservoir must be exploited using horizontal wells in all areas.� In areas where fractures may not be do

GPC) has been shown to be capable of automatically controlling the area open to flow of multiple ICVs to achieve a specified production rate
he well was drilled and completed as a proof of concept. It was completed as a trilateral and was equipped with a SC that encompasses surfa
controlling fluids/gels and selective perforations have been used to mitigate the disparities in water encroachment over the reservoir interval.
Saudia Arabia. A well was drilled and completed as a proof of concept. It was set up as a trilateral and was equipped with an SC that encom
erivative information. We propose a workflow in which the production engineer relies on measurements to determine the flow rate and pressu

e commonplace to improve the well productivity by providing maximum reservoir contact minimizing operating costs lowering the pressure d
ive permeability and also the higher degree of cleaning and liquid removal obtained in laboratory and field studies are interfacial tension red

½This paper will document the first application of inflow control devices in the UK sector of the North Sea. This application took place on
up to improve the reliability of the pumping system. However DESPs potentially can address a much wider range of reservoir management

 h an open-hole gravel pack. The initial well (CAN01) has produced at 333 MMcf/D. These rates are higher than typically experienced which h
his project was to develop and apply a new concept for well completion involving ESP systems tubing-conveyed perforating (TCP) drillstem
e data and permits lifetime modeling with parameter combinations employing all available data. The analysis explicitly accounts for ESPs tha
ating density (ECD). However the knowledge of rheology and hydraulics of polymer-thickened foams is still limited. This paper summarizes th

 slots and limited open-to-flow areas. Furthermore the compounded effects of formation damage and non-Darcy flow on the fluid flow toward
ed and surfactant-based have been used in an attempt to achieve optimum fracture length and conductivity.� Acids used for these treatme
mpletions were considered the best completion option based on rock mechanics improved profile surveillance and cost. The original Alpine
mpletions were considered the best completion option based on rock mechanics improved profile surveillance and cost. The original Alpine
pleted using 100 tip screenout (TSO) propped-fracture treatments containing 70 million pounds of proppant. The target oil bearing Tor and Ek

 tana and the success there is now accelerating the transfer of technology to the North Dakota side of the Bakken trend and is attracting sev
 ted near a water zone. These hydraulic fracturing difficulties created a niche for technologies that offer fracture-geometry control without sac
 ated by the reaction with the formation results in excessive fluid loss. Controlling fluid loss is one of the key objectives in acid fracturing treat
us after initial campaign of four fracturing treatments. It demonstrated good proppant carrying capabilities and allowed decrease of polymer lo
ted formation where sand control is a part of well management during the production life of the wells. Previous techniques of open hole exte
 tives has grown. This value must be balanced with the cost of the additives which can be significant in slickwater fracturing treatments. The
 is the dominant parameter controlling fracture height growth and that Young’s modulus contrast is less important. However a recent st

shown frac packs have a significant impact in maintaining well productivity in the later production life stages of unconsolidated reservoirs. Th
sts per unit of gas produced. This in turn forced industry to focus on increasing efficiency by refining completion processes and field operatio
er to hydraulically fracture the well as well as complying with stricter governmental regulations. As produced water is recycled and used in fra
(OFD) approach which maximizes well productivity for a given fracture volume was introduced by Prats in 1960 for single-phase Darcy flow
 d stress state.� The application and appropriate modification of basin best practices and the application of technology for reservoir charac
 zuela. This technique combines stimulation and sand production control in a single treatment by placing a short and wide fracture which bypa
 arious techniques to prevent the breakthrough of hydraulic fractures into the underlying water zone but so far without clear success. The pa
 ng the number and size of fractures is still a challenge. Although fundamentally similar to fracturing vertical wells horizontal well fracturing h
 ction rates and better access to reserves. However most of these horizontal wells are completed openhole with little alternatives for stimulat
 imply the stimulation of Middle Mulichinco Formation (primary target) through hydraulic fractures. Mulichinco Formation is 30 to 80 meters th
 d treating fluids would enter preferentially into zones with high water saturations leaving oil zones untreated with a final result of increasing o
 ping reserves under these conditions with conventional vertical wells is in most cases uneconomical. In this setting horizontal wells have co

y successful over the past few years as the majority of the horizontal gas producers have yielded excellent results with open-hole completion


ost gas-well completions in the United States and elsewhere (Palisch et al. 2007; Forchheimer 1901; Milton-Tayler 1993a; Penny and Jin 199



ost gas-well completions in the United States and elsewhere (Palisch et al. 2007; Forchheimer 1901; Milton-Tayler 1993a; Penny and Jin 199
ost gas-well completions in the United States and elsewhere (Palisch et al. 2007; Forchheimer 1901; Milton-Tayler 1993a; Penny and Jin 199
igorous process of candidate selection fracture design and implementation of fit-for-purpose technologies. 10 candidate wells were selecte
The solution for dimensionless productivity index of a finite-conductivity vertically fractured well in a closed rectangularly bounded reservoir a

 cess of hydraulic fracturing in Western Siberia organically expanded to projects in Tymen-Pechora and Volga-Urals basin. Both basins are g

h normal cementing operations. The sliding sleeves were opened one at a time to fracture layers independently without perforating. The valv
ng sleeves would then be opened one at a time to fracture layers independently without perforating. The possibility of high fracture initiation
 Difficulties emerge because hydraulic fracturing in soft rock involves development of a plastic zone near the fracture surface where rocks pa
 us resistance of the fluid flowing through the rock matrix primarily governs fluid loss.�This has historically limited the application to fractu

and reservoirs located in Southeast New Mexico (SENM).� The wells discussed in the paper were completed in various Morrow Sand int
ed to allow effective fracture fluid cleanup. It is also fairly well understood that occasionally conventional cross-linked gel fracture stimulations



 allenging due to presence of high pressure/high temperature and high asphaltene content in the crude oil which renders the situation even m
 w discrepancies between the placed propped length and the effective production fracture length. Ineffective fracture clean-up is often cited a
 w discrepancies between the placed propped length and the effective production fracture length. Ineffective fracture clean-up is often cited a




 w discrepancies between the placed propped length and the effective production fracture length. Ineffective fracture clean-up is often cited a
  a clearer picture of the fracture development.� This information can be combined with other fracture diagnostic techniques and along wit

 effects of the deviating borehole trajectory. For common HFM geometries a 2� deviation uncertainty of the positions of monitoring or trea
 100 fracture treatments were mapped. The fracture mapping study was performed as part of a pilot project to evaluate ten-acre well spacing

ment size as well as coordination of frac crews.� In the end however the primary characteristic of the treatment that provides any econom
s and little lasting conductivity will be created. Despite this critical role of differential etching in the creation of fracture conductivity little is kno
 e the recovery factor of heterogeneous reservoir developed with water flood. Three main uncertainties exist: fracture height half-length and a
 ting tracer technology has a number of safety and environmental issues that must be addressed when using this technology as part of a frac

 ropped fracturing stimulations for the gas and gas-condensate wells in the Western Siberian Arctic sector. The candidate selection proces
nductivity cells. At the gas velocities normally encountered in hydraulic fracture proppant packs non-Darcy pressure drops dominate and t
he fracture and a lag zone develops due to fluid cavitation. Properly taking into account the controlling parameters of tip behavior has resulte
um fracture length and conductivity. Acids used for these treatments were based on 28 wt% HCl. A mixture of 15 wt% HCl and 9 wt% formic
ns of a Stimulation Index (SD) and for evaluating the efficiency of wells with low conductivity hydraulically induced fractures. We utilize the dim

 tern Piceance Basin western Colorado. Production from very low permeability Williams Fork gas sandstones requires fracture stimulation to
 tion of the seismic waves and injection details. Stimulation below the fault indicated a near-horizontal fracture geometry. Above the fault a n

wback but the physics of the phenomenon has still to be understood to predict the amount of proppant flowback during the life of a well. In pa
e. It is shown that the propagation pressure of the orthogonal fracture quickly increases to above the closure stress on the initial fracture due
lacing one lowers down the displacement quality leaving most of residual viscous fluid in porous matrix. The present paper provides the dat

 in propped fracture dimension is related to the distribution of stresses and elastic properties as well as fluid leak off. Those factors have str
 actures although successful often underperform: Frac and Pack completions exhibit positive skin values and traditional hydraulic fracture



  order to maintain the oil production target for this field the water injection rate should double the target oil rate. To achieve this water must b
 se of this work is to demonstrate the benefits of applying an integrated analysis for a hydraulic fracturing evaluation that is performed using a
ffsets have long been recognized as sites of restricted width in the fracture channel potentially leading both to significant pressure drops and
 . Analyzing the different production technology options used in the assets thus far was the next step in better understanding the different rec
 d wells especially for tight gas reservoirs. However there has been no report of a study of flow behaviour within propped fractured porous m
 ng an average porosity of 8 to 12% and permeabilities ranging from 1 to 200 mD. The wells are completed as cased-hole with a 7inch liner
  rations. Traditional large fracturing jobs are usually pumped down 5.5 or 4.5 casing to meet the requirement of high pumping rate (30~55bpm
ed. Written by individuals recognized as experts in the area these articles provide key references to more definitive work and present specific
d reservoir-well model to demonstrate that oil production can be increased by using controlled inflow from a gas cone as a natural lift.� Th
o gas lift valve designed for gas operations. The value of auto gas lift is probably easier to demonstrate than for other types of intelligent well
uire sand control and this has resulted in five sandface completion types (Open Hole Gravel Pack Cased Hole Frac Pack Cased Hole Grav
 e. Experiments at micro- and macro-scale levels were performed to: a) provide a detailed understanding of emulsion flow and blocking mec

 velocity gas flow in single phase has been studied thoroughly by a large number of authors. Despite the fact that high-velocity coefficient in th
 ll bore face but more importantly the low permeability crushed zone created during the drilling operation. To achieve uniform treatment of
 e hydrodynamics becomes an important issue on well performance. In this paper we will discuss a problem in horizontal wells - the elevation
 wells are often selected to provide better sweep efficiency and achieve higher injection rates than conventional vertical injectors. However s
 ured and the benefits of utilizing open-hole horizontal completion technology have been well documented. The efficiencies and benefits of ut
 ured and the benefits of utilizing open-hole horizontal completion technology have been well documented. The efficiencies and benefits of ut
 ype of wells are: will it be necessary to cleanup the mud and filtercake from the openhole section before or while starting production? Will the
 ype of wells are: will it be necessary to cleanup the mud and filtercake from the openhole section before or while starting production? Will the
 mine why this completion technique was selected and identify key parameters that favored its successful application in the Colville River field
wing a detailed hydraulic analysis of these wells a good match with field measurements was obtained. Simulation results show that the proble
  tended shutdowns and cold restarts is effective only up to 50% water cut. Because more time and resources would be required to bring a n
 also velocity. The conventional theory to analyze the phenomena associated at rate dependent is commonly interpreted using Isochronal or f



 ies is the fiber-optic DTS which can record the wellbore temperature profile in real time with decent accuracy and resolution. A key potential

ng injection rate into each of the four zones. The completion also includes three downhole optical flowmeters and three optical pressure and
 im intelligent completions technology has been successfully installed in Shaybah field operated by Saudi Aramco. Included in the description
 roduction from 12 subsea wells in water depths ranging from 5800 to 7000 feet is routed to the production host through three flowline loops
despite their maximizing of reservoir contact. This is due to frictional pressure drop and/or permeability variations along the well. Annular flow
permeability (K) variation and proximity of water traps). Furthermore conventional completions do not handle effectively heterogeneity or per
dded Value for an IW is dependent on the number and location of the ICV controlled zones. Too many valves lead to unnecessary and exce
 nt completions are delivering better wells through improved efficiency productivity and hydrocarbon recovery with fewer wells both offshore
ent. Zonal flow control can maximise produced oil value minimise unwanted fluids or a combination of both objectives. We have previous


d few wells will use an intelligent well systems to manage fluid fronts in a gravity-stable recovery scheme. The reservoir has many producing
ntelligent completions wells have been successfully installed in Abqaiq operated by Saudi Aramco. Included in the description are equipment
model-based and are effective only if the model can be used to predict future reservoir behavior with no uncertainty. Recently developed sche
 ss the effects of discontinuities on hydraulic fracture growth. A high viscosity fluid was used in order to provide fracture growth similar to actu
 ss the effects of discontinuities on hydraulic fracture growth. A high viscosity fluid was used in order to provide fracture growth similar to actu
  and thus the efficiency of the foam. In this paper an experimental study of the behavior of CO2 and N2 foams in granular porous media usin
 ference we assume that the bubble generation kinetics is dependent on layer permeability. We present experiments consisting of co-injectio
  periments consisting of the co-injection of N2 gas and surfactant solution in homogenous sandstone cores varying the liquid and gas injectio
 terature detailing the critical velocity necessary to keep a gas well unloaded suggests using the conditions at the top of the well as an evaluat

 oduction observing much reduced flow rate for three days and eventually stopped flow. During the production depletion shuts-in restarts a
 essure. This further reduces the inflow so that more liquid collects and eventually the flow dies down completely.� This phenomenon is kn

ydrostatic column in the wellbore that balances out with the reservoir pressure killing the well and - if nothing is done - leaving significant rese
ding the modeling of liquid loading behavior is still quite immature and the prediction of the minimum stable gas rate not very reliable. Many w
ulation generally termed “deliquification. This resource is making up an ever-increasing part of the North American gas supply. Since the
 ciated with gas production exist however in offshore fields most of them are not applicable for well completion or legal requirements. In the p
 wellbore and instead settle to the bottom. At this point we apply artificial lift which involves either the better use of the remaining reservoir e
 and c) they restrict gas production. This paper presents a new approach to water unloading that does not restrict or interrupt gas production

 aracteristics of the tubing and casing pressures in plunger-lifted gas well are described quantitatively according to a field test data set. A bett
 ll loading up and ceasing to produce. Submersible pumps offer a viable means of removing water from the well; however gas interference c
  stimulated to remove drilling fluid filter cakes and to overcome formation damage effects or to create acid fractures or deep matrix stimulat

 was applied to conventional wells where massive sand production was allowed with the objective of creating a cavity. The benefits expected

  ate reservoir characterization is the key to successful reservoir development. This is especially true in thinly laminated reservoirs which exhi
  oduce the hydrocarbon. Sanding is detrimental to optimum field development and therefore information about the possible advent and exten
ng deep and clean perforations may still not be enough to generate the desired productivity.� Therefore the wells are often stimulated by a
maximum productivity this transition requires an optimal cleanup and the removal of the perforation damages. A new underbalanced oriente
nd E-line have difficulties. This paper presents case history of coiled tubing perforating and zonal isolation evolution in infill well at Resak field
aracterized by their high permeabilities (100 - 500 md) and low pressures (1200 - 2200 psi). The wells in Anaco District are normally perforat
 ld and theoretical calculations. The issues that are primarily covered in the LEP simulation work address the comparison of horizontal LEP in
Sea. The HZ fields are stacked thin high-permeability sandstone reservoirs interlayered with low-permeability layers. The shallower layers g
g system for given well and formation properties and work at log resolution to eliminate problems experienced with existing packages that us
maximum geological stress known as the preferred fracture plane (PFP) provides significant opportunities to improve the efficiency of the fra
maximum geological stress known as the preferred fracture plane (PFP) provides significant opportunities to improve the efficiency of the fra
 oduction. Some wells in�ADMA OPCO fields that are perforated using conventional perforating techniques�will not produce until stimu


eabilities of 35md to 85md and porosities of 18 to 30%. The wells are completed in oil reservoirs that have been perforated using convention
zones are commonly encountered while drilling the reservoir section.� The drilling strategy for the subsea development wells called for the
zones are commonly encountered while drilling the reservoir section.� The drilling strategy for the subsea development wells called for the
duces transient fluid flow that provides an opportunity for quantifying the formation parameters. However the skin factor can rarely be estima
he accuracy of hydrostatic cushion before firing the guns. The conventional method of correlating the CT on depth involves two CT runs the



f the gravity-assisted electric line to convey perforating guns to angles greater than 65�. With this electric line limitation the options availa
erforating conditions of the perforator or perforator system is required if such damage and potential retrievability risks are to be avoided. In pr

  to an outcrop carbonate rock called Indiana Limestone. Three of the tests involved shots into an outcrop sandstone rock called Berea Sands
 llbore damaged zone. This connection through the damaged zone is usually achieved by perforating and the effectiveness of this connection
meability decrease due to salt precipitation. We derived an analytical model-based method for determination of kinetics and formation damag
   what the impact would be on productivity impairment during sulphate scaling. This paper extends the previous work by modelling the inje
 produced water reinjection can be anticipated using the expected pore volume replacement ratio and water-cut estimated from the producti

 l productivity by maximizing oil production and minimizing water production. The paper will demonstrate the challenges and successes of red
 dients the low net-to-gross ratio the low bottomhole temperatures and the requirement for pressure maintenance. The development of the
ountered during the planning and completion of two wells in the Egret Field in Brunei operated by Brunei Shell Petroleum (BSP) how the ch
 e was drilled through the H1 H2 targets and a completion design consisting of a cased and perforated commingled completion inside 9-5/8-
s with 50�-60� maximum hole-angles. The wells are completed using dry trees from the TLP and are producing primarily from massive
 lls with 50–60� maximum hole angles. The wells are completed using dry trees from the TLP and are produced primarily from massive
h field (see Figure 1) discovered in the late 1980s is located 180 km south of Riyadh the capital of Saudi Arabia (figure 1). Hawtah is one of
  ius field setting both Gulf of Mexico and world records. Success was achieved through careful planning of procedures and specification of e

etion increase with depth. Additionally oriented perforations offer an improvement to perforation stability against sanding: the maximum allow
 In maturing deepwater fields such as Shell Ursa/Princess where depleted reservoir pressures are significantly below the hydrostatic pressu
with a deviated wellbore through the H1/H2 targets and a completion design consisting of a cased perforated and commingled completion i

servoirs. Because of the long lengths of the producing reservoirs and large variations in sand-grain sizes/permeabilities premium screens w
s one of the completed intervals on the S7000E horizon. Production from this interval began in April 1997 and oil recovery averaged 2000 ST


t are significantly greater than expected. The success of the Greater Plutonio OHGP completions has been attributed primarily to the rigorou

penhole gravel packs completion (OHGP) for its first phase development. The ultra high rate for individual well could be up to 320 MMSCFD
side the operational window formed by the minimum pump rate to avoid premature rat hole screen-out and maximum pump rate to avoid form

olling sand and maximizing productivity it entraps the filtercake formed by the reservoir drilling fluid.� This results in low production rate a
t are significantly greater than expected. The success of the Greater Plutonio OHGP completions has been attributed primarily to the rigorou

 during the production and the injection cycles. This challenge has a significant effect in selection of the completion technique in these wells
ne utilizing low-viscosity carrier fluids and low gravel concentration. In this technique the gravel is placed in two waves commonly called Alph
g long sand control zones by using newer technologies. A typical well in the Mahakham Delta has five zones and installing conventional grav
educed number of wells with departures of up to 3.5 km at approximately 1000 m TVD. This paper discusses the issues surrounding the T
 ecome more common. Executing these open-hole gravel-pack jobs (alpha-beta packs) has been a challenge. Although scattered attempts
 onsidered one of the proven methods of sand control from both reliability and productivity standpoints and allows access to larger reserves



ures in-situ treatment design and productivity improvements. Two wells were recently drilled and completed for the Rosa deepwater project
conduits between the reservoir and the wellbore for hydrocarbon production. This project presents a system approach for removal of perfora
 onduits between the reservoir and the wellbore for hydrocarbon production. This project presents a system approach for removal of perfora
d and perforated without sand control but the perforations were oriented in the vertical plane (ie topside and bottomside perfs) to limit sand
rs are planned and all will require some form of sand prevention. Extensive rock mechanical work using Statoil’s finite element modeling

 nd executed completions are subject to mechanical failure with the first indications often being production of solids into a common separatio
ection well and served as a demonstration of its potential benefits in the development of Stag oilfield. Located offshore in the North-West she

or a major operator in the Gulf of Mexico. Each of the six treatments provided significant cost savings as well as excellent return on investm
or a major operator in the Gulf of Mexico. Each of the six treatments provided significant cost savings as well as excellent return on investm


om an essentially unconsolidated reservoir with a depth that ranges from 300 to 700 ft using steam injection at 300 to 400�F poses a uniq
d bodies. This has had a persistent influence on the sandface completion design and in particular on the drilling and completion fluid system
 still novel in the industry and this paper describes its application in completion selection and design facilities design and operation and faci
een completed and connected to production facilities and pressure maintenance is coming from 13 water injectors and 2 gas injectors. The c
the amount of sand produced during the life of the well. To address this problem an oedometric cell specially designed to simulate a radia

and release rate are vastly simplified4-11 necessitating further field observations controlling sand flow rate in order to improve accuracy.�

 significant economic loss. AGOCO recognized that it was facing a major challenge in terms of understanding potential sanding risk for Sarir
trength distribution using core testing log data and drilling data analysis for rock strength estimate and its correlation with core testing results
 s. It can impact production cause erosion in downhole and surface facilities require additional separation and disposal and lead to significa
 s. It can impact production cause erosion in downhole and surface facilities require additional separation and disposal and lead to significa
production indicating possible sanding issues for this field. To investigate this problem relevant data from different sources and different do
production indicating possible sanding issues for this field. To investigate this problem relevant data from different sources and different do
 y perforation-collapse tests aimed at demonstrating and quantifying the water-cut effect on perforation failure and sand production. The labo
 y perforation-collapse tests aimed at demonstrating and quantifying the water-cut effect on perforation failure and sand production. The labo
ely the critical depletion resulting in rock disaggregation the proposed approach considers the interplay of several mechanisms that can lead
ely the critical depletion resulting in rock disaggregation the proposed approach considers the interplay of several mechanisms that can lead

 ictable although in most fields produced gas becomes progressively enriched in CO2 through the production life of a reservoir such as part
d on reliable assessment of the sanding potential and its severity over the life of the well for the intended production target. This paper introd
d on reliable assessment of the sanding potential and its severity over the life of the well for the intended production target. This paper introd

  The three wells involved in this operation had been shut in due to incidences of sand production. The production facility was not designed w
 to support the validity of the numerical model.� Experiments on hollow-cylinder synthetic-sandstone specimens were conducted involvin

 to support the validity of the numerical model.� Experiments on hollow-cylinder synthetic-sandstone specimens were conducted involvin

 the rock surrounding the perforations and the borehole. Sand production in weakly consolidated formations is generally assumed to be a tw
ategies to maintain mechanical and time-dependent stabilities of extended reach wells and 2) to assess sand production risk in the developm
en in the Central Graben Area of the North Sea blocks 22/30b 22/30c and 29/5b. With initial temperatures of 200�C and pressures of 16
rying geological complexity. Within these units the reservoir intervals are of moderate to poor quality and can exhibit strong contrasts in perm
a obtained on an electrolytic apparatus and their accuracy has been investigated. It has been observed that the 3D semianalytical model SP
development and validation by comparison with finite-element simulation results. With the new perforation skin model we then show how to o
 ast 4 years the application of viscoelastic surfactants was extended to acid-based systems for carbonate stimulation. These surfactants hav
 acid-fracturing treatment. Depth of penetration is controlled by the acid reaction rate leakoff and stimulation rate. Acid reaction rate is a fun
reatment. We conducted a series of acid fracture conductivity tests using a protocol that mimics the fluxes in a hydraulic fracture both in the
 acid-fracturing treatment. Depth of penetration is controlled by the acid reaction rate leakoff and stimulation rate. Acid reaction rate is a fun
 eally suited for acid fracturing. During acid fracturing the wormholes created by the reaction results in excessive fluid loss. Controlling fluid
deally suited for acid fracturing. During acid fracturing the wormholes created by the reaction results in excessive fluid loss. Controlling fluid
or nonacid-cleanup treatments to use before gravel- or frac-packing operations to clean up long intervals after perforating. Success or failure
ompletion of the project will also be discussed. This fracturing technique was implemented successfully to perform a large multistage acid tre


during the spending process viscosifies the fluid through the transformation from spherical micelles to an entangled wormlike micellar structu

onal coverage in large limestone reservoirs. The viscoelastic diverting acid system was pumped through coiled tubing in three of these wells


ver regular HCl reacts very fast with limestone and high-temperature dolomite formations and unless retarded will produce a fracture with l
onal coverage in large limestone reservoirs. The viscoelastic diverting acid system was pumped through coiled tubing in three of these wells
ation permeability often exceeds one darcy. The mineralogy is composed of calcite (98 to 99%) with about 1% halite and < 1% quartz; there
 cut (WC) wells in which water has broken through as a result of high-permeability streaks or natural fractures. Furthermore acid penetration
al production gain with relatively low level of investment. In the recent acidizing campaign in Brunei a particular challenge was the flowback o

y damage to each zone matrix mineralogical composition and pressure regimes of each zone need to be taken into consideration. The pre
wells. The first is its high reaction rate with carbonate rocks which limits acid penetration in the formation. The second is its corrosivity to we

 rocedure for making fluids and measuring leakoff under static conditions. Stimulation and gravel-pack fluids are defined for the purpose of th

cated at a depth of 6100 to 7500 ft that has produced (30 to 45 �API crude) for over 35 years with production peaking at 66 000 BOPD. T
 ating fluid over the entire interval. When fluids are pumped into a well they naturally tend to flow into the zone with the highest permeability o
In the mainly brown fields tertiary recovery methods such as water-flooding are implemented to maintain financial viability of the well stock. I


servoir rock which is significant even for wells producing very lean gas with liquid dropout values less than 1%. Many different methods such
� However most previous studies reported in the literature have focused on investigating the effects of injection rate temperature and flu
s for maximizing reservoir contact and hydrocarbon drainage. Many of these wells experience drilling mud damage. One of the challenges in
l parts where various factors which affect the application of RPM technology in a chosen field base case well are studied. These factors inc
ssure than the previous fracture. Refracturing requirements are different in highly permeable formations (high fracture conductivity) as comp

but still not perfect. Limitations on the amount of proppant placed near water zones and formation damage from polymer residuals were the
 the Frontier Formation located in Bighorn Basin Wyoming has seen a variety of stimulation fluids used over the past years with varying deg
but still not perfect. Limitations on the amount of proppant placed near water zones and formation damage from polymer residuals were the
 process that integrates petrophysical and reservoir characterization expertise with production and completion knowledge by developing an
ve some water accumulation near the wells. This adds significantly to the total liquid blocking. Experiments were conducted using both outcr




ed with limited surface water handling facilities increased the importance of stimulating this type of challenging wells due to the drastic perme
 realized through increased reserves generated by increased drainage efficiency and reduction in well numbers and intervention frequency. A
 hundreds of wells. However there has been very little use of these valves to control water injection distribution within the layers of a reservo
 hundreds of wells. However there has been very little use of these valves to control water injection distribution within the layers of a reservo
 smanaged they can result in substantial and perhaps irreparable damage. This paper presents a study on the creation and propagation of w
ng and completion are more and the options for monitoring control and intervention often limited. Gas-condensate reservoirs are increasingly
 ccessfully deliver a challenging deepwater development well. First the well was the longest stepout and highest angle well drilled in the field
 d are not regarded as a replacement for reservoir inter-zonal communication tests performed between producing reservoirs on every well. C
 d are not regarded as a replacement for reservoir inter-zonal communication tests performed between producing reservoirs on every well. C
ndamental data collection (well data pressure formation fluids - water and oil mineralogy data and lab tests…). Data management system
ERD) was implemented. Six ERD wells have been drilled to date with lateral extensions close to 6500 m leading to total depths sometimes in
ellbore drainage radius. The wormholes created by a retarded acid are deep but thin. During production the flux through the thin wormholes
 his offshore field has favourable conditions for ESP application producing from carbonate reservoir with no anticipated fines production low
ed the A sand. Formation powered jet pumps increase oil rate from the A sand while reducing the water rate from the C sand. Gas lift can be



 kets. New facilities for gas lift operation entails the installation of a compressor liquid knock out equipment pipelines manifold configuratio
al lift selection strategy for unloading liquid from gas well in San Juan basin located in Southwestern Colorado and Northwestern New Mexi
sult in operational issues such as fluid / gas slugging and pressure instabilities which negatively impact the overall lift efficiency. In 2006 Co

easing the productivity of the field by many folds. But each of these artificial lift systems has economic and operating limitations that eliminate
he reduced cleanup efficiency caused by the heal-toe effect. Extensive modelling and simulation work has been previously performed analys

ent called for 16 North Sea-style 7 in. monobore wells (11 producers and 5 gas injectors). By May of 2003 it became apparent that the orig
ompletion architecture was to maximize the well head flowing pressure while insuring “long term integrity of wells.� This was addresse


 eability contrast. At the outset a value-of-information exercise suggested probing downhole sensing and completion issues in a stacked-res
 d Hole Frac Pack Cased Hole Gravel Pack Stand Alone Screen and Orientated Perforating). Based on the experience and field performanc
with poor reservoir properties and minor reservoirs in order to maintain the production rates. Application of horizontal drilling allowed achieve
ontrol for the initially forecasted production rates. However the possibility of expanding the gas production rates of each well to more than 1 M

ntly without perforating. Completions using these casing valves are called Treat And Produce (TAP) Completions and have a unique design
Sarmatian formation (Base Cretaceous Paleorelif) at the depth of 1100 to 1150 m. Currently the main productive horizons are sands from the
  ethod. Production improvement factors (compared to conventional wells) of two or higher is not uncommon. To make decisions on the corre
 etal ions in the inhibitor pill adds another degree of freedom in squeeze design especially in controlling return concentrations and squeeze li
 s than that which would be required to continuously transport and unload liquids from the well.� Sub-critical velocities are often encountere
 s than that which would be required to continuously transport and unload liquids from the well.� Sub-critical velocities are often encountere

areas where fractures may not be dominant it is crucial to achieve maximum reservoir contact (MRC) through the well architecture.� To th
areas where fractures may not be dominant it is crucial to achieve maximum reservoir contact (MRC) through the well architecture.� To th

o achieve a specified production rate. A black box model was established using real-time downhole instrument data as a predictive model f
ed with a SC that encompasses surface remotely controlled hydraulic tubing retrievable advanced system coupled with pressure and temper
oachment over the reservoir interval. Recently completion technologies using downhole valves which allow production and injection control
was equipped with an SC that encompassed a surface-remotely-controlled hydraulic-tubing-retrievable advanced system coupled with a pres
 o determine the flow rate and pressure values and on models to determine the derivative information (i.e. the changes in flow rates as a res

erating costs lowering the pressure drawdown and maximizing profitability. This paper presents the results of a numerical study performed to
eld studies are interfacial tension reduction and the miscibility characteristics reached between the treatment fluids and the formation fluids

 ea. This application took place on a 4 288 ft horizontal sidetrack of a well in the West Brae field.�The completion was designed for a ho
 der range of reservoir management challenges. This paper will analyze the performance of a DESP in a range of reservoir scenarios. It will s

her than typically experienced which has raised concerns concerns about the resultant potential for metal erosion. As a result a rigorous eros
onveyed perforating (TCP) drillstem testing (DST) and chemical treatment of the formation by using standard equipment and techniques. T
alysis explicitly accounts for ESPs that are still operational at the time of the study thus removing a historical source of statistical bias. The a
still limited. This paper summarizes the significant effects of polymer on foam rheology and presents a hydraulic model that simulates aqueou

on-Darcy flow on the fluid flow towards slotted-liners must be considered in well completion design process. This paper presents a compreh
vity.� Acids used for these treatments have been typically formulated with 28-wt% HCl and have been used successfully to increase produ
 illance and cost. The original Alpine field development plan did not include hydraulic fracture stimulation based on the reservoir characteriza
 illance and cost. The original Alpine field development plan did not include hydraulic fracture stimulation based on the reservoir characteriza
ant. The target oil bearing Tor and Ekofisk intervals range from 40 to 120 m of combined thickness with a Young’s modulus and permea

he Bakken trend and is attracting several new and existing operators to the area. Different drilling and completion techniques have been tried
racture-geometry control without sacrificing proppant-pack conductivity. The conventional approach is based on net pressure control. This c
key objectives in acid fracturing treatments to be able to create longer and wider fractures and hence maximize well productivity. Alternating
s and allowed decrease of polymer load without increasing risk of premature screenout. Fibers proved to be reliable for successful placemen
revious techniques of open hole external gravel packing and cased hole Internal Gravel Packing (IGP) for controlling formation sand were ch
slickwater fracturing treatments. There is a range of different flowback additives containing water-wetting nonionic to amphoteric microemuls
less important. However a recent study pointed out that modulus contrast can have significant implications on fracture geometry and proppa

 ges of unconsolidated reservoirs. Thus sustaining the ability to pump frac packs in these challenging environments is a priority. With conve
mpletion processes and field operations to make wells commercially viable. Strategies such as multiple-zone commingled completions the se
 ced water is recycled and used in fracturing applications each cycle of re-used water returns with a more complex chemical make up than b
  in 1960 for single-phase Darcy flow systems. This method which was later modified and presented in the form of Unified Fractured Design
 on of technology for reservoir characterization can shorten the learning curve of an operator in the development of a basin.� Numerous c
 a short and wide fracture which bypasses the near-wellbore damage while gravel-packing the zone of interest. This paper describes a nove
 so far without clear success. The paper describes a technique of physical barrier placement and tailoring fracturing fluid systems to control f
 ical wells horizontal well fracturing has unique aspects that require special attention to ensure successful treatment. Differences exist betwe
hole with little alternatives for stimulation water shutoff or workover treatments. A very challenging task to stimulate long openhole sections e
 hinco Formation is 30 to 80 meters thick and has a variable permeability throughout the pay zone. The gas drainage from the best permeabi
 ated with a final result of increasing overall water production. However if the water production mechanism is understood and the appropriat
 this setting horizontal wells have come to mitigate the problem however in most unfavorable conditions where oil and gas are found in tight

ent results with open-hole completions in particular. Consequently most of the planned future wells will be drilled as open-hole horizontal com


 ton-Tayler 1993a; Penny and Jin 1995; Flowers et al. 2003; Miskimins et al. 2005; Handren et al. 2001; Lolon et al. 2004; Vincent 2004; Olso



ton-Tayler 1993a; Penny and Jin 1995; Flowers et al. 2003; Miskimins et al. 2005; Handren et al. 2001; Lolon et al. 2004; Vincent 2004; Olso
ton-Tayler 1993a; Penny and Jin 1995; Flowers et al. 2003; Miskimins et al. 2005; Handren et al. 2001; Lolon et al. 2004; Vincent 2004; Olso
ies. 10 candidate wells were selected and the target zone was the GS-3A reservoir. 10-15ft above the GS-3A was a water bearing sand. Mo
ed rectangularly bounded reservoir and the corresponding pseudosteady state shape factor of this type of well and reservoir completion unde

 Volga-Urals basin. Both basins are geologically lithologically and stratigraphically vastly different from West Siberia. Adding the difference in

ndently without perforating. The valves have a unique design feature which allows an unlimited number of valves to be placed in a single we
e possibility of high fracture initiation pressures is identified as the main risk with this approach. This paper will discuss the theoretical and
  the fracture surface where rocks partly lose their cohesion. This study has developed a more appropriate model for fracture design which t
 ically limited the application to fracturing reservoirs with low permeabilities. A new VES fracturing fluid has been developed for use in high p

ompleted in various Morrow Sand intervals around 10 500 ft with an average Bottom Hole Static Temperature (BHST) of 190oF.� Wellbor
 cross-linked gel fracture stimulations do not create the desired fracture dimensions. The potential reasons for the shorter than desired effect



oil which renders the situation even more difficult because of fluid incompatibility issues. The formation tends to produce oil with asphaltene c
 tive fracture clean-up is often cited as a likely culprit. This paper presents some of the results of an investigation of fracture clean-up mecha
 tive fracture clean-up is often cited as a likely culprit. This paper presents some of the results of an investigation of fracture clean-up mecha




 tive fracture clean-up is often cited as a likely culprit. This paper presents some of the results of an investigation of fracture clean-up mecha
 diagnostic techniques and along with sound engineering practices can have a profound impact on how wells are completed.����

  of the positions of monitoring or treatment well surveys can cause more than a 40o uncertainty of the inverted fracture azimuths. Furthermo
 ect to evaluate ten-acre well spacing. The Jonah Field is located in the Green River Basin in Sublette County WY. Production is primarily fr

e treatment that provides any economic benefit is a conductive fracture that economically increases well production. Although the primary go
on of fracture conductivity little is known about the texture of the fracture surface created during acid fracturing or about the dependence of t
 xist: fracture height half-length and azimuth. Commercial fracture models provide length estimate once a reliable estimate of height is know
using this technology as part of a fracturing treatment. These issues along with regulations concerning the transportation of radioactive mate

ctor. The candidate selection process including production prediction is at an infant development stage and is additionally hampered by th
Darcy pressure drops dominate and the apparent proppant permeability is one or two orders of magnitude lower than the Darcy permeability
arameters of tip behavior has resulted in more accurate and robust fracture propagation models. However the situation is still unclear in high
ure of 15 wt% HCl and 9 wt% formic acid was used in wells completed with super Cr-13 tubulars. A high pH borate gel was pumped in stage
y induced fractures. We utilize the dimensionless productivity index solution (JD) for finite-conductivity vertically fractured wells in closed recta

tones requires fracture stimulation to enhance wellbore-to-reservoir connectivity. The use of surface microseismic monitors without borehole
acture geometry. Above the fault a near-vertical fracture geometry was observed. A change in fault orientation was supported by differences

 owback during the life of a well. In particular determining whether the proppant flowback will stop after a few days of production or will contin
 sure stress on the initial fracture due to the fracture penetrating into the higher stress region which leads to fracture reopening along the initi
  The present paper provides the data on hydraulic fracture simulation accounting for accumulation of damages in elastoviscoplastic medium

 fluid leak off. Those factors have strong implication on proppant distribution especially when larger size proppant are used. Although the lat
ues and traditional hydraulic fracture completions show discrepancies between the placed propped length and the effective production frac



 oil rate. To achieve this water must be injected into the formation at fracturing pressures. The completion campaign started with three wate
  evaluation that is performed using a workflow including time-lapse Sonic Anisotropy and Flexural Waveform Dispersion Analysis (open hole
 oth to significant pressure drops and to proppant bridging as fluid and slurry move through the restrictions. New modeling results are presen
better understanding the different recovery increment options. The initial 4 year productivity from 4 assets was analyzed. This paper presents
ur within propped fractured porous media for these low interfacial tension (IFT) systems. It is now a well established finding both experimenta
 ted as cased-hole with a 7inch liner through the reservoir section. The perforated intervals range from 30 to 80 m in length and the wells we
ment of high pumping rate (30~55bpm). Post-frac snubbing operations are often needed to run tubing and clean out wellbores. Snubbing ope
 e definitive work and present specific details only to illustrate the technology. Purpose: to inform the general readership of recent advances i
m a gas cone as a natural lift.� This model was developed in the knowledge centre Integrated System Approach Petroleum Production (IS
 han for other types of intelligent well because it provides a direct replacement for conventional gas lift equipment compressors and pipeline
d Hole Frac Pack Cased Hole Gravel Pack Stand Alone Screen and Orientated Perforating). Based on the experience and field performanc
g of emulsion flow and blocking mechanism b) set criteria for controlling an emulsion penetration depth before it breaks down and seals a po

  fact that high-velocity coefficient in the presence of an immobile and a mobile liquid phase is much higher than that in single phase only a h
on. To achieve uniform treatment of the entire openhole section with hydrochloric acid is difficult: the rapid reaction of the acid in downhole
blem in horizontal wells - the elevation change in well trajectory and its effect on well performance. In general a horizontal wellbore is never p
entional vertical injectors. However studies from Prudhoe Bay mature waterflood field indicate that these additional benefits can decline with
 d. The efficiencies and benefits of utilizing open-hole completion with mechanical isolation has lead to the operational benefits of multiple fra
 d. The efficiencies and benefits of utilizing open-hole completion with mechanical isolation has lead to the operational benefits of multiple fra
  or while starting production? Will the filtercake disperse and get removed while producing the well and applying drawdown to the formation?
  or while starting production? Will the filtercake disperse and get removed while producing the well and applying drawdown to the formation?
ul application in the Colville River field. The optimal completion technique for a candidate well is determined by reservoir properties geologic
 imulation results show that the problems in the conventional wells were not as severe as those interpreted from the measurements of distrib
 urces would be required to bring a new AA LDHI more detailed analysis were performed to evaluate the possibility of managing hydrate risk
 only interpreted using Isochronal or flow-after-flow tests. After this test the negative impact of inertia on gas deliverability can be very well an



 uracy and resolution. A key potential application for DTS data is to profile injection or production for wells which is the primary motivation an

eters and three optical pressure and temperature gauges. Measurement of surface injection rate and the rate from each of the three flowmet
i Aramco. Included in the description are equipment selection design and development details installation procedures and “lessons lea
ion host through three flowline loops and one separate flowline. The project has been an economic and technological success. The applicati
 ariations along the well. Annular flow leading to severe erosion hot-spots" and plugging of screens is another challenge. Inflow Control Devi
andle effectively heterogeneity or permeability contrasts exposed along the sand face. The ICD controls and interrogates more optimally both
valves lead to unnecessary and excessive cost as well as the potential for reduced reliability. Too few valves will not provide sufficient flexib
overy with fewer wells both offshore and on land. Intelligent completions have proven their value in managing production from multilateral we
both objectives. We have previously shown[1] that a minimum degree of un-evenness of an invading fluid front is needed for effective ICV


e. The reservoir has many producing zones with high-quality rock properties. Intelligent well systems which consist of interval control valves
 ded in the description are equipment selection design and development details installation procedures and “lessons learned after insta
uncertainty. Recently developed schemes which update models with data acquired during the optimization process are computationally very
 rovide fracture growth similar to actual field conditions. Fracture growth and its internal fluid pressure were monitored by fixed probes placed
 rovide fracture growth similar to actual field conditions. Fracture growth and its internal fluid pressure were monitored by fixed probes placed
 foams in granular porous media using X-ray Computed Tomography is reported. In the experiments gas is forced through natural porous me
  experiments consisting of co-injection of N2 gas and surfactant solution in layered cores with layering parallel and to the flow directions. Th
 res varying the liquid and gas injection rates. During the experiments X-ray computed tomography (CT) scans were used to map locally the
ns at the top of the well as an evaluation point. �This is convenient for personnel conducting the evaluation as wellhead pressure and temp

duction depletion shuts-in restarts and finally stop flowing periods the gas well experienced liquid load-up involving unstable operation cond
 mpletely.� This phenomenon is known as liquid loading. Velocity strings are a commonly applied remedy to liquid loading in gas wells. By

hing is done - leaving significant reserves behind. This is in North Sea gas fields a relatively new problem and is being addressed by Gas
 ble gas rate not very reliable. Many wells start liquid loading at gas rates well above the values predicted by classic steady state prediction m
orth American gas supply. Since there is no one “perfect solution and the problem affects thousands of wells the opportunity involves n
pletion or legal requirements. In the past soap sticks have been tried to foam up liquids however these may never have reached the area wh
etter use of the remaining reservoir energy or the addition of external energy. The objective of this study is to understand the appropriate ap
ot restrict or interrupt gas production can operate without external energy and uses no consumables. Physical and software simulators have

 cording to a field test data set. A better liquid accumulation mechanism is proposed. The effect of liquid falling back and liquid transfer from t
 the well; however gas interference can significantly degrade pump performance and even result in pump failure. An effective means of mitig
  cid fractures or deep matrix stimulation to enhance productivity. Good acid coverage with a relatively small acid volume is required to econo

 ating a cavity. The benefits expected from a cavity completion are four-fold: 1) increase in PI by reducing skin 2) increase in effective wellbo

hinly laminated reservoirs which exhibit vertical heterogeneity and a wide range of flow properties. Therefore it is critical to combine high reso
n about the possible advent and extent of sanding will be helpful in planning for completions and facilities. The study presented in this paper
 re the wells are often stimulated by a matrix acidizing treatment after the perforating.� A prevalent mind set in the industry is that acid diss
mages. A new underbalanced oriented perforating technique has been successfully implemented in Algeria. It combines the use of a formatio
on evolution in infill well at Resak field one of the gas field operated by Malaysia National E&P Company Petronas Carigali Sdn Bhd. Since
n Anaco District are normally perforated using conventional static underbalanced techniques. The productivity of these wells was evaluated u
s the comparison of horizontal LEP injector with conventionally perforated liner for a generic reservoir; the role of the sand-screen in LEP des
eability layers. The shallower layers generally have better permeability and were developed first while the deeper lower-permeability reservoi
 enced with existing packages that use input values averaged across the reservoir. After consultation with staff engineers the tool was creat
 es to improve the efficiency of the fracture job maximizing ultimate production from the well. Wells are frequently completed with multiple tu
 es to improve the efficiency of the fracture job maximizing ultimate production from the well. Wells are frequently completed with multiple tu
niques�will not produce until stimulated with acid.�A new perforating technique has been deployed that creates clean low skin perforati


ve been perforated using conventional methods fracture stimulated to increase production and later completed with electro-submersible pu
bsea development wells called for the use of a solid drill-in liner as a contingency should major losses be encountered while drilling the reserv
bsea development wells called for the use of a solid drill-in liner as a contingency should major losses be encountered while drilling the reserv
r the skin factor can rarely be estimated reliably from pressure data acquired in the current UBP operations if without flowing on surface in s
T on depth involves two CT runs the first to run a memory gamma ray (GR) and casing collar locator (CCL) and the second run for the actua



 ctric line limitation the options available for deploying the guns are limited to wireline tractor and e-coiled tubing since most through tubing p
evability risks are to be avoided. In practice the perforating design engineers do not have a well-established analytical tool to help them unde

p sandstone rock called Berea Sandstone. Four different charge types were tested including one standard (conventional) charge and three d
d the effectiveness of this connection is the result of the perforating system selection the well environment in which the perforating job is exe
 tion of kinetics and formation damage coefficients from production well data consisting of barium concentrations in the produced water and o
   previous work by modelling the injectivity impairment during simultaneous injection of incompatible waters i.e. cation-rich produced water
water-cut estimated from the production forecast. Fracturing is likely to occur during produced water reinjection at voidage replacement rate

  the challenges and successes of reducing produced water by using smart completions and how multiphase flow meters (MPFM) helped in g
  intenance. The development of the Albacora Leste Field in the ultra deep water Campos Basin was a key component of Brazil’s drive to
  i Shell Petroleum (BSP) how the challenges were addressed and the best practices identified for future operations. Sand-control technique
 commingled completion inside 9-5/8-in. casing was implemented. The sand-face completion design consisted of a large-OD expandable san
are producing primarily from massive fine-grained Pleistocene-aged reservoirs. These reservoirs require sand-control to prevent sand prod
 re produced primarily from massive fine-grained Pleistocene reservoirs. These reservoirs require sand control to prevent sand production
 i Arabia (figure 1). Hawtah is one of several small fields located along the Hawtah Trend (others are Ghinah Hazmiyah Nisalah and Umm J
   of procedures and specification of equipment. This paper describes the planning for these challenging extended-reach completion and inter

  against sanding: the maximum allowable drawdowns and depletions are increased for all sands. Finally an analysis is presented on the eco
nificantly below the hydrostatic pressure of a seawater column a modified screen design was required since screen products currently availa
orated and commingled completion inside 95/8-in. casing was implemented. The sandface-completion design consisted of a large-outside-d

s/permeabilities premium screens with shunt tubes in conjunction with cased-hole frac packs have been used to complete the wells. The th
 7 and oil recovery averaged 2000 STB/D. Sand production was anticipated under normal drawdown from production onset and as such the


een attributed primarily to the rigorous design and field application of the fluid systems used at all stages of the well from drilling the reservoi

ual well could be up to 320 MMSCFD and the non-Darcy effect is too significant to overlook. The objective of this investigation is to build an a
 nd maximum pump rate to avoid formation fracture. Some special projects require additional equipment to provide selective completion –

 This results in low production rate and consequently leads to the requirement of high drawdown pressure. �Hence it is imperative that the
een attributed primarily to the rigorous design and field application of the fluid systems used at all stages of the well from drilling the reservoi

completion technique in these wells which require an effective and reliable sand control for long term and open-hole and large tubular size t
 in two waves commonly called Alpha/Beta packing. The second method utilizes a viscous carrier fluid and high concentrations of gravel in c
ones and installing conventional gravel pack completions would consume up to 30 rig days. This represents a significant capital cost. To redu
 cusses the issues surrounding the TOTAL AUSTRAL Carina field development project and the innovative processes that were used to add
lenge. Although scattered attempts have been made to separately understand different parts of the gravel-pack process the industry still lac
 and allows access to larger reserves through fewer wells. Since most of these reservoirs contain reactive shale streaks they require synth



 eted for the Rosa deepwater project Block 17 offshore Angola using a Non-Aromatic Oil-Based Mud (NAOBM) weighted with sized calcium
stem approach for removal of perforation damage effective gravel placement and packing of the perforation tunnels. It was found that surgin
tem approach for removal of perforation damage effective gravel placement and packing of the perforation tunnels. It was found that surgin
 e and bottomside perfs) to limit sand production. Perforations were shot at 4 spf and 180� phasing with ~1 000 psi underbalance.�Th
 Statoil’s finite element modeling method suggests that oriented perforations can prevent sand production in the horizontal wells. This wa

on of solids into a common separation facility. In many offshore completions particularly sub-sea or multi-zone completions it is often difficu
cated offshore in the North-West shelf of Australia Stag field is a shallow and unconsolidated glauconitic sandstone reservoir with a top and

s well as excellent return on investment for the operator. Screenless completions are an integrated solution that involve many field-proven te
s well as excellent return on investment for the operator. Screenless completions are an integrated solution that involve many field-proven te


 tion at 300 to 400�F poses a unique challenge in designing an effective yet economic completion. One of the biggest problems associat
he drilling and completion fluid systems. The completion design has evolved from stacked cased hole gravel pack to open hole gravel pack d
cilities design and operation and facilities risk evaluation with reference to a high rate gas field development. The estimation of sand produc
er injectors and 2 gas injectors. The completion strategies employed have included mainly stand alone screens in open hole and cased hole
pecially designed to simulate a radial flow towards a well has been developed at IFP. Tests performed under CT-scan on cohesionless san

 te in order to improve accuracy.� Sand flow is catastrophic when formation is soft. However if certain conditions are satisfied the sand ra

anding potential sanding risk for Sarir and that it was necessary to design and implement a sandface completion and sand management stra
ts correlation with core testing results; (2) conduct a series of triaxial tests on selected reservoir core samples in the low to intermediate stren
on and disposal and lead to significant economic loss. On the other hand precautionary but unnecessary sand prevention will mean unwarra
on and disposal and lead to significant economic loss. On the other hand precautionary but unnecessary sand prevention will mean unwarra
om different sources and different domains (i.e. wireline logs laboratory test data drilling data well data and field data) were integrated to g
om different sources and different domains (i.e. wireline logs laboratory test data drilling data well data and field data) were integrated to g
ailure and sand production. The laboratory perforation-collapse tests were conducted on weak sandstones obtained from downhole and out
ailure and sand production. The laboratory perforation-collapse tests were conducted on weak sandstones obtained from downhole and out
 of several mechanisms that can lead to the rock breakup and sand transport.� One important difference is that rock disaggregation is not
 of several mechanisms that can lead to the rock breakup and sand transport.� One important difference is that rock disaggregation is not

uction life of a reservoir such as parts of the San Juan basin. In contrast it is generally observed that the ratio of CO2:CH4 declines with tim
d production target. This paper introduces a predictive tool that forecasts not only the initiation of sanding but also its rate and severity in real
d production target. This paper introduces a predictive tool that forecasts not only the initiation of sanding but also its rate and severity in real

 roduction facility was not designed with any sand management capability such as hydrocyclones sand jets etc. Thus historically any incide
 specimens were conducted involving real-time sand-production measurement under various conditions. A numerical approach was used fo

 specimens were conducted involving real-time sand-production measurement under various conditions. A numerical approach was used fo

 tions is generally assumed to be a two-step process with the shear failure being the first step and the transport of the sand out of the perfo
  sand production risk in the development wells and eliminate unnecessary downhole sand control. The data required for the study include: 1
 ures of 200�C and pressures of 16 000psi this is one of the highest pressure and temperature developments ever undertaken. The fields
d can exhibit strong contrasts in permeability and formation water composition. Reservoir support is provided by combined injection of gas an
 that the 3D semianalytical model SPAN 6.0 software and the simple hybrid model described in this paper replicate the experimental results
on skin model we then show how to optimize horizontal well perforating to maximize well productivity. A cased perforated well may have low
 e stimulation. These surfactants have the ability to significantly increase the apparent viscosity and elastic properties of the treating fluids. Th
 ation rate. Acid reaction rate is a function of several factors the most important of which is the reservoir temperature. Yet another concern i
 es in a hydraulic fracture both in the main flow direction along the fracture and in the fluid loss direction. In our tests the injection rate into th
 ation rate. Acid reaction rate is a function of several factors the most important of which is the reservoir temperature. Yet another concern i
excessive fluid loss. Controlling fluid loss is key to optimize acid fracturing treatments by creating longer and wider fractures. Diesel emulsifie
 excessive fluid loss. Controlling fluid loss is key to optimize acid fracturing treatments by creating longer and wider fractures. Diesel emulsifie
  after perforating. Success or failure of these treatments is often related to the efficiency of diverting agents especially for acid treatments o
 o perform a large multistage acid treatment from a semisubmersible rig. Historically wells in this field have been treated using dedicated stim


n entangled wormlike micellar structure while penetrating the carbonate rock. The highly viscous fluid acts as a temporary barrier and diverts

h coiled tubing in three of these wells and bullheaded in five other wells for comparison between both methods of placement. Pre- and post-


etarded will produce a fracture with low conductivity. In addition concentrated HCl-based acids are very corrosive to well tubulars especially
 h coiled tubing in three of these wells and bullheaded in five other wells for comparison between both methods of placement. Pre- and post-
 out 1% halite and < 1% quartz; therefore the formation is a potential candidate for acid stimulation. This limestone is atypical because of its
 tures. Furthermore acid penetration is limited by the large surface area of the horizontal wellbore and this is exacerbated by the relatively s
articular challenge was the flowback of tubing pickling and spent acids and neutralization of the spent acid on the surface. A series of effectiv

 be taken into consideration. The presence of natural fractures makes the entire treatment more complex. Acid placement and diversion nee
on. The second is its corrosivity to well tubulars. Hence organic acids become viable material for matrix acidizing to alleviate these two proble

 uids are defined for the purpose of this technical standard as fluids used to enhance production from oil and gas wells by fracturing or acidiz

oduction peaking at 66 000 BOPD. The permeability varies from 20 to 200 mD with streaks exceeding one Darcy. At different times in the pa
e zone with the highest permeability or least damage. Field experiences showed that there is no assurance of complete zone coverage witho
n financial viability of the well stock. In many areas however production wells do not benefit enough from the water flood or the injection sch


an 1%. Many different methods such as hydraulic fracturing dry gas injection and solvent injection have been proposed and implemented to
of injection rate temperature and fluid properties and few have focused on the influence of rock properties on stimulation treatments.� Th
ud damage. One of the challenges in stimulating long horizontal wells with open-hole completion is the placement of stimulation fluids for effe
e well are studied. These factors include the effects of instantaneous vs. kinetic adsorption for the treatment and the further influence of trea
 (high fracture conductivity) as compared to low permeable ones (moderate fracture conductivity). Understanding these basic differences is

age from polymer residuals were the main drawbacks. A never ending quest for efficiency and higher production rates called for different opti
d over the past years with varying degrees of success. When dealing with water sensitive formations a common practice has been to use oil
age from polymer residuals were the main drawbacks. A never ending quest for efficiency and higher production rates called for different opti
mpletion knowledge by developing and refining more complete interpretation and completion models based on comprehensive data. This pro
ents were conducted using both outcrop sandstone and reservoir cores to measure the effect of liquid blocking on gas relative permeability. A




enging wells due to the drastic permeability contrast across the pay zones. Typically the treating fluid in a matrix treatment flows into high pe
umbers and intervention frequency. A more rigorous exploitation of the real time production data is necessary to fully achieve this objective.
ribution within the layers of a reservoir interval at high rates (>25 000 BWPD) in a continuous proportional operating mode. This paper will re
ribution within the layers of a reservoir interval at high rates (>25 000 BWPD) in a continuous proportional operating mode. This paper will re
 on the creation and propagation of water hammer due to rapid shut-in of water injectors. Water hammer1-4 or pressure surge is a pressure
ondensate reservoirs are increasingly considered as suitable candidates for drilling SWs or HWs. These reservoirs pose special challenges
  highest angle well drilled in the field to date. Second the well targeted a fault block in a portion of the field that was poorly constrained due t
producing reservoirs on every well. Consequently the value of continuing to run these tools was raised by management. In response the relia
producing reservoirs on every well. Consequently the value of continuing to run these tools was raised by management. In response the relia
 ests…). Data management system allowing for quick access to well production history data. A design tool (Stim2001) for detailed candidat
  leading to total depths sometimes in excess of 8600m. In addition to the challenges pertaining to the drilling itself the completion also carrie
   the flux through the thin wormholes can be so high that high pressure gradient occurs. Therefore the optimized wormhole geometry should
h no anticipated fines production low GOR low temperature low bubble point pressure and high API gravity. All new installations were carrie
 rate from the C sand. Gas lift can be used in formation powered jet pump wells to further enhance drawdown on a well while jet pumping. M



ment pipelines manifold configuration and associated piping etc. In many cases gas lift sourcing might require completely fresh construction
  orado and Northwestern New Mexico. Various modeling techniques were applied to evaluate the lowest bottom hole flowing pressure for va
 the overall lift efficiency. In 2006 ConocoPhillips conducted a study to design a gas lift system for the Surmont SAGD development that wou

nd operating limitations that eliminate it from consideration under certain operating condition. However all the conventional artificial lift system
as been previously performed analysing the impact of formation damage and well cleanup in horizontal wells. This paper extends that work t

003 it became apparent that the original well design would not achieve the 1.1 Bcf/D production target because of well construction problem
grity of wells.� This was addressed through implementation of limited - or even not - proven technologies. Introduction TOTAL AUSTRAL


d completion issues in a stacked-reservoir situation. The ultimate objective of this study was to ascertain economic completion strategy so th
n the experience and field performance open-hole gravel packing has become the preferred option. The techniques used in completing these
 of horizontal drilling allowed achievement of the above tasks.� Horizontal completions resulted in not only enhancement of individual well
on rates of each well to more than 1 MMm3/D �increased the associated sand production risk and led to the need for evaluating� the be

mpletions and have a unique design feature in the valves that allows a theoretically unlimited number of valves to be placed in a single well w
oductive horizons are sands from the lower Sarmatian (Basal Sarmatian). The facies variation can be seen both vertically and horizontally on
mon. To make decisions on the correct completion type to select it is important to be aware of the many sand control issues and the relative
 return concentrations and squeeze life. Phosphonate reactions during squeeze treatments involve a series of self-regulating reactions with c
 ritical velocities are often encountered in low productivity gas wells that produce liquids whether the wellbore liquids are produced directly fro
 ritical velocities are often encountered in low productivity gas wells that produce liquids whether the wellbore liquids are produced directly fro

 rough the well architecture.� To this end a tri-lateral MRC well with a mother bore and two laterals has been recently drilled in this reservo
 rough the well architecture.� To this end a tri-lateral MRC well with a mother bore and two laterals has been recently drilled in this reservo

strument data as a predictive model for the controller. The model parameters were updated in real-time using the Decay Recursive Least Squ
 m coupled with pressure and temperature monitoring system. The SC provides isolation and down hole control of commingled production fr
allow production and injection control over multiple zones have become available. The central idea is that downhole control may be used to a
 dvanced system coupled with a pressure- and temperature-monitoring system. SC provides isolation and downhole control of commingled p
e. the changes in flow rates as a result of a change in an ICV setting). Such a model typically would be a steady-state wellbore simulator inc

ults of a numerical study performed to determine the production performance of dual opposed laterals compared to horizontal wells. With a to
 tment fluids and the formation fluids. This paper presents the results for compatibility and displacement tests carried out among reservoir

 he completion was designed for a homogeneous permeability but the as-drilled permeability as shown by logging-while-drilling data had v
 range of reservoir scenarios. It will show how DESP performance can be modeled by use of commercially available coupled well-performa

 l erosion. As a result a rigorous erosion study was initiated. The objective was to quantitatively evaluate erosion at various rates over the life
andard equipment and techniques. The concept was developed after identifying the opportunity to optimize operations in wells where the abo
 rical source of statistical bias. The analysis uses Kaplan-Meier (KM) (Kaplan and Meier 1958) and Cox proportional hazards (CPHs) (Cox 19
 ydraulic model that simulates aqueous and polymer-based foam flow in directional and horizontal wellbores. Experimental studies on the rhe

ess. This paper presents a comprehensive semi-analytical model for estimating the productivity of horizontal wells completed with slotted lin
n used successfully to increase production from the Khuff carbonates. Although acid fracture treatments create significant conductivity enha
 based on the reservoir characterization. Well performance had proven to be economic in this Jurassic marine sandstone without hydraulic
 based on the reservoir characterization. Well performance had proven to be economic in this Jurassic marine sandstone without hydraulic
 a Young’s modulus and permeability that can vary from less than 0.5 to over 2.5 million psi and 0.1 to 4 m respectively along the horiz

ompletion techniques have been tried since the start of the play with different degrees of success. In June of 2005 a new technique was intro
based on net pressure control. This can be achieved using low-viscosity fluids such as viscoelastic systems oil-based systems or reduced p
 aximize well productivity. Alternating stages of polymer pad with diesel emulsified acid for deeper penetration and in-situ gelled acid a polym
o be reliable for successful placement of 10/14-mesh size Intermediate Strength Proppants (ISP) at concentration up to 1000 kgPA and high
or controlling formation sand were challenged by reduced flow efficiency of the wells. The recent development of Expandable Sand Screen (E
g nonionic to amphoteric microemulsion and oil-wetting components. Determining the best additive for a specific reservoir is not a simple m
ons on fracture geometry and proppant placement (Smith et al. 2001). To expand on this topic we consider the combined effects of modulus

nvironments is a priority. With conventional frac pack fluids these greater depths and higher bottomhole pressures often would result in the
 one commingled completions the selection of fluids and additives to maximize hydraulic fracture effective length and conductivity and fluid
 e complex chemical make up than before. Therefore the usable lifetime of the recycled water is shortened or requires expensive cleaning o
 he form of Unified Fractured Design (UFD) charts by other investigators is widely used in the petroleum industry even for gas condensate s
 lopment of a basin.� Numerous completion strategies (Limited Entry high rate limited entry and various Pin-point Stimulation Technique
 nterest. This paper describes a novel and economical frac-and-pack technique which consists of pumping a sand plug with the downhole to
  g fracturing fluid systems to control fracture net pressure development that combined is used to mitigate fracture height growth. The method
 ul treatment. Differences exist between horizontal and vertical wells in the areas of rock mechanics reservoir engineering and operations. T
 o stimulate long openhole sections effectively due to poor acid distribution especially in reservoirs with high permeability streaks that require
gas drainage from the best permeability zones causes a differential depletion in reservoir pore pressure affecting by consequence the mecha
sm is understood and the appropriate fluids are selected then stimulating producer wells with high water cuts can be a rewarding operation.
s where oil and gas are found in tight formations fracture stimulation needs to be added to the equation. Conventional multistage fracturing t

 be drilled as open-hole horizontal completions. Nonetheless due to the highly complex nature of the Khuff carbonate reservoir some wells h


 Lolon et al. 2004; Vincent 2004; Olson et al. 2004). Although the importance in gas wells is evident the authors pose the question of whethe



Lolon et al. 2004; Vincent 2004; Olson et al. 2004). Although the importance in gas wells is evident the authors pose the question of whethe
Lolon et al. 2004; Vincent 2004; Olson et al. 2004). Although the importance in gas wells is evident the authors pose the question of whethe
GS-3A was a water bearing sand. Most of the candidate wells were primarily in an area of the reservoir that had experienced poor recovery p
of well and reservoir completion under boundary-dominated flow conditions has been developed and utilized in this study. The mathematical

West Siberia. Adding the difference in the maturity of the fields with significantly depleted reservoirs high asphaltene and paraffin oil content

 of valves to be placed in a single well without incremental reductions to the ID thus allowing normal cementing operations. A control line is c
 aper will discuss the theoretical and experimental study that was conducted to assess the viability of the cemented sliding sleeve concept b
ate model for fracture design which takes into account processes in the plastic zone for the special case of soft rock that is a cohesionless g
has been developed for use in high permeability reservoirs and successfully pumped in the Gulf of Mexico.�The fluid exhibits enhanced f

 ature (BHST) of 190oF.� Wellbore completion constraints combined with reservoir parameters inclusive of low-pressured water sensitive
ns for the shorter than desired effective fracture lengths are numerous with the most likely being excessive fracture height growth and poor fr



ends to produce oil with asphaltene content when the flowing bottomhole pressure is drawn below the Asphalting Onset Pressure (AOP). An
estigation of fracture clean-up mechanisms. This investigation was undertaken under a Joint Industry Project (JIP) active since the year 2002
estigation of fracture clean-up mechanisms. This investigation was undertaken under a Joint Industry Project (JIP) active since the year 2002




estigation of fracture clean-up mechanisms. This investigation was undertaken under a Joint Industry Project (JIP) active since the year 2002
w wells are completed.������ This paper discusses the completion design methodology execution and results from two off

nverted fracture azimuths. Furthermore if the positions of the injection point and the receiver array are not known accurately and the velocity
 ounty WY. Production is primarily from over-pressured and tight sandstones of the Lance Formation. The Lance in Jonah consists of many

production. Although the primary goal of a hydraulic fracture is to create a highly conductive flowpath it is often the most poorly understood
cturing or about the dependence of this texture on the acidizing conditions. To study this important aspect of the acid-fracturing process we
 a reliable estimate of height is known. This is evident for 2D model which requires a direct knowledge of the height but also for p3D model w
he transportation of radioactive materials have impacted the application of this technology in international markets. This paper will describe

 e and is additionally hampered by the lack of or ambiguity in the reservoir and production data. This is particularly true for the Yamburgsk
 de lower than the Darcy permeability measured at single phase low-rate conditions. This is particularly true if a liquid phase is also flowing.
 er the situation is still unclear in high permeability formations because the formation fluid can invade the tip zone where the pressure drops
  pH borate gel was pumped in stages to reduce leak-off and maintain the bottomhole pressure at values greater than the fracturing pressure
ertically fractured wells in closed rectangular bounded reservoirs and their corresponding pseudo-steady state shape factors under boundary

 roseismic monitors without borehole equipment in downhole configurations represents a relatively new and untested technology for hydraulic
 ntation was supported by differences in the microseismic-signal characteristics and the treatment-injection data. This difference in fracture g

a few days of production or will continue at a given rate during the well's life is a key issue when selecting an appropriate completion method.
 s to fracture reopening along the initial fracture plane (called in-plane frac hereafter). A dual-frac PKN model is developed to predict the grow
amages in elastoviscoplastic medium as well as the effect of inhomogenity of porous media properties on fracture propagation. After hydrau

 proppant are used. Although the latter could lead to more conductive fractures they could also bridge at the wellbore impeding both lateral
gth and the effective production fracture length. Ineffective fracture clean-up is often cited as a likely culprit. The main results presented in



 on campaign started with three water injector wells. The initial results were not as expected i.e. after pumping 1000 bbls of treated seawater
 eform Dispersion Analysis (open hole and cased hole) which main objectives consisted on the generation of a horizontal stress map for the s
 ns. New modeling results are presented that quantify these and other effects of offsets by using a coupled 2D hydraulic fracture model. Offse
 s was analyzed. This paper presents the results of a study focused on increasing the understanding of productivity drivers using a database
 established finding both experimentally and theoretically that the flow of gas-condensate fluid systems in porous media is affected by both co
30 to 80 m in length and the wells were traditionally matrix-acid stimulated following perforation. The wells produced initially unassisted then l
nd clean out wellbores. Snubbing operations can be costly in terms of investment and time. Annular fracs have been applied in the industry a
 eral readership of recent advances in various areas of petroleum engineering. Introduction Predicting and assuring well deliverability often
  Approach Petroleum Production (ISAPP) of TNO TU Delft and Shell and is based on a commercially available dynamic multiphase well sim
quipment compressors and pipelines and the ancillary equipment they require. An estimated 60 auto gas lift systems have been installed a
n the experience and field performance open-hole gravel packing has become the preferred option. The techniques used in completing these
 before it breaks down and seals a porous medium. In these experiments well-characterized oil-in-water emulsions were injected into etche

 er than that in single phase only a handful of studies have been made on the subject. In this work we have measured the high-velocity coef
pid reaction of the acid in downhole conditions often creates a localized loss zone through which most of the treating fluid is lost so that trea
neral a horizontal wellbore is never perfectly horizontal. The inclination angle could be a result of drilling control or sometimes could be desi
e additional benefits can decline with time. A clearer understanding of the injection mechanism and an integrated solution was required to im
he operational benefits of multiple fracturing operations being pumped in one continuous operation equating to time savings more efficient f
he operational benefits of multiple fracturing operations being pumped in one continuous operation equating to time savings more efficient f
applying drawdown to the formation? Will the remaining filtercake impair well productivity? The paper presents the case of a gas producing h
applying drawdown to the formation? Will the remaining filtercake impair well productivity? The paper presents the case of a gas producing h
ned by reservoir properties geologic setting rock mechanics development plan and completion design. In this paper we will review the uniq
ed from the measurements of distributed temperature sensing systems (DTSs). It is also demonstrated that the compartmentalized completi
e possibility of managing hydrate risks through operating procedures. It was found that during extended shutdown the wellbore fluid can be p
 gas deliverability can be very well analyzed using special graphics. However the actual effect related to capillary number and its dependenc



 s which is the primary motivation and focus of this project. In the present paper a thermal model recently developed for single-phase- and

e rate from each of the three flowmeters provides real-time measurement of injection rate into each zone regardless of choke positions. The
 on procedures and “lessons learned after installation of the fully hydraulic tubing-retrievable advance completion system with digital perm
 technological success. The application of intelligent well technology has enabled co-owners Shell and BP to successfully develop Na Kika w
nother challenge. Inflow Control Devices (ICDs) were proposed as a solution to these difficulties in the early ‘90s. ICDs have recently gaine
  and interrogates more optimally both rock and fluid properties in the reservoir hence delaying early water breakthrough. This early water bre
 alves will not provide sufficient flexibility for efficient control. We previously showed[1] that a minimum degree of un-even fluid-front progre
naging production from multilateral wells horizontal wells with multiple zones and wells with heterogeneous reservoirs using a single wellbor
 fluid front is needed for effective ICV control. This work studies scenarios to identify when “Proactive rather than “Reactive ICV chok


hich consist of interval control valves (ICVs) and many sensors will be used to monitor analyze and control (MAC) injection and production
  and “lessons learned after installation of the fully hydraulic tubing-retrievable advanced completion system with digital permanent down
on process are computationally very expensive. We suggest that simple reactive control techniques triggered by permanently installed dow
ere monitored by fixed probes placed normal to the expected plane of propagation. Fracture tip arrivals were captured by the fixed pressure p
ere monitored by fixed probes placed normal to the expected plane of propagation. Fracture tip arrivals were captured by the fixed pressure p
s is forced through natural porous media initially saturated with a surfactant solution a process known as SurfactantAlternatingGas (SAG). Th
parallel and to the flow directions. The cores are obtained by combining two porous media chosen from Benteimer and Berea sandstone and
 scans were used to map locally the fluid saturations with high spatial and temporal resolution. Introduction Foam is an excellent acid divers
 ation as wellhead pressure and temperature data are readily available. �A number of situations exist where the use of the wellhead as the

up involving unstable operation conditions and changing reservoir deliverability. The conventional steady-state based liquid load-up predictio
medy to liquid loading in gas wells. By installing a small diameter string inside the tubing the flow area is reduced which increases the velocit

 em and is being addressed by Gas Well Deliquification which aims to produce the liquids artificially in order to help the gas to flow unobstru
d by classic steady state prediction models such as Turner. The loading point is strongly dependent on inclination angle flow regime transitio
ds of wells the opportunity involves not only technology development but also knowledge management and building resource capability. This
may never have reached the area where liquid had accumulated due to wellbore deviation. It was therefore decided to try liquid batch injectio
 y is to understand the appropriate application of external energy to maximize economic recovery. Our research was conducted in two stages
hysical and software simulators have been developed to demonstrate the feasibility of the new approach and to configure the approach for v

 falling back and liquid transfer from the tubing into the annulus during shutting-in period is specially considered for liquid accumulation and s
 p failure. An effective means of mitigating this problem is to place the pump below the producing interval effectively allowing gravity to separ
mall acid volume is required to economically obtain the desired broad reservoir access. We have developed a model to predict the placemen

g skin 2) increase in effective wellbore radius 3) creation of an enhanced permeability (dilatant) zone near the wellbore and 4) decrease in p

 fore it is critical to combine high resolution formation evaluation logs and formation tests to predict the well performance prior to the product
s. The study presented in this paper characterizes the geomechanic behavior of a field in which sanding problems are expected after depleti
nd set in the industry is that acid dissolves the perforation debris and creates wormholes that bypass the perforating and other near wellbore
eria. It combines the use of a formation isolation valve (FIV) to keep damaging completion fluid off the formation immediately after perforation
y Petronas Carigali Sdn Bhd. Since the beginning of Resak Field production coiled tubing has been used to perforate numbers of infill wells
ctivity of these wells was evaluated using nodal analysis techniques coupled with perforating performance simulations. The quality and amou
 e role of the sand-screen in LEP design during HVO production and the analysis of the pressure drops through the LEP hardware. Modelling
   deeper lower-permeability reservoirs have been developed more recently. The lower-permeability reservoirs are generally of lower porosity
 th staff engineers the tool was created in Excel to test functionality and later transformed into a desktop application.� It includes a perfora
 frequently completed with multiple tubing strings (up to four in some cases) sensor lines control lines or other hardware that can be damag
 frequently completed with multiple tubing strings (up to four in some cases) sensor lines control lines or other hardware that can be damag
  that creates clean low skin perforations�and allows the well to be produced at commercial rates while waiting for the multipurpose barge


ompleted with electro-submersible pumps (ESPs). To effectively meet the operator’s needs for a method that would help optimize well p
  encountered while drilling the reservoir section. This strategy stands opposed to using a pre-drilled liner.� The use of a drill-in liner howe
  encountered while drilling the reservoir section. This strategy stands opposed to using a pre-drilled liner.� The use of a drill-in liner howe
 ons if without flowing on surface in sufficient time. The reasons are that (a) the flow rate after an UBP continuously varies during the surge; (
CL) and the second run for the actual perforation. The underbalanced condition calculated based on wellbore fluid displacement is often deem



d tubing since most through tubing perforation are done in real time. Apart from space constraint at the wellsite and cumbersome logistics th
hed analytical tool to help them understand post-perforating behavior of perforators. They have to rely on their own experiences and previous

ard (conventional) charge and three different designs of reactive liner charges. Among all charges the only difference of note was the design
ent in which the perforating job is executed and what happens to the perforations after shooting and before they are used for production or in
ntrations in the produced water and of well productivity decline. We analyse production data for five scaled-up producers from giant offshore
aters i.e. cation-rich produced water (PWRI) and seawater with sulphate anions. An analytical model with explicit expressions for deposited
njection at voidage replacement rates.�The extent (size) of the induced fracture(s) will significantly impact the waste disposal process.�

 ase flow meters (MPFM) helped in getting better results to allow faster decision making. In one of the challenging areas in Ghawar field whe
 ey component of Brazil’s drive to achieve petroleum self sufficiency by 2006. Because of the challenges presented by the heavy oil and
e operations. Sand-control techniques such as an extension packing and hydraulic fracturing were evaluated to help minimize the risk of fine
 sisted of a large-OD expandable sand screen with 150 micron weave across the 2 zones. Upon completion the reservoirs were cleaned up
re sand-control to prevent sand production at the expected drawdowns planned during the life of the wells. To help ensure high rate long life
d control to prevent sand production at the expected drawdowns planned during the life of the wells. To help ensure high-rate long-life comp
 inah Hazmiyah Nisalah and Umm Jurf). The Trend runs approximately 30 km east to west and 50 km north to south. Production in Hawtah
extended-reach completion and intervention operations along with the lessons learned while implementing these case-history jobs. Introduc

y an analysis is presented on the economics and trade-offs of vertically-oriented perforating (with possibly managed sand production) versus
 nce screen products currently available were limited to <3 500 psi. FLC pill formulations also required modification because they were only v
design consisted of a large-outside-diameter (OD) expandable sand screen with a 150-�-weave opening across the two zones. Upon com

n used to complete the wells. The third well A1ST1BP1 was completed using the same techniques as were used successfully on the first tw
m production onset and as such the well was completed with sand-control measures in place. After about ten years of production a significa


s of the well from drilling the reservoir through to the gravel pack itself and subsequent completion. An integrated approach was adopted for

 e of this investigation is to build an accurate model to validate and quantify the non-Darcy mechanical skins for the high-angle OHGP gas w
 to provide selective completion – External casing packers (ECP) installed at different positions along the production screen aim the isolati

re. �Hence it is imperative that the filter cake be removed uniformly to ensure lower drawdown pressure and even flow distribution throug
s of the well from drilling the reservoir through to the gravel pack itself and subsequent completion. An integrated approach was adopted for

 nd open-hole and large tubular size to minimize friction losses. Until now standard open-hole gravel packing was the common completion in
and high concentrations of gravel in conjunction with alternative path screens which mitigate problems caused by unpredicted downhole even
ents a significant capital cost. To reduce costs the Operator has completed 19 wells with Single Trip Multi-zone (STMZ) technology. Two diff
 ive processes that were used to address these situations.�Through careful planning the processes selected to facilitate the completions
vel-pack process the industry still lacks a tool that accurately models the complete process and aids in successfully designing these jobs. Th
 ve shale streaks they require synthetic/oil-based drilling fluids (S/OB). Considering that the openhole gravel packing in the industry deals p



NAOBM) weighted with sized calcium carbonate. After installing the Stand-Alone-Screens (SAS) across the production intervals and allowing
ation tunnels. It was found that surging the perforations greatly increased the ability to pack the perforation tunnels and improved the connec
ation tunnels. It was found that surging the perforations greatly increased the ability to pack the perforation tunnels and improved the connect
with ~1 000 psi underbalance.�The X-1 well produced up to ~150 MMCFD and was taken to depletion without any sand being produced
 uction in the horizontal wells. This was offered as an alternative to mechanical sand control in the long horizontal wells due to traverse sever

 ti-zone completions it is often difficult and expensive to determine which well or specific completion interval has failed most times requiring
 c sandstone reservoir with a top and bottom sealing shale. The reservoir pressure is low and it contains heavy and viscous oil of 19� API

ution that involve many field-proven technologies such as reservoir characterization perforating coiled-tubing intervention matrix acidizing r
ution that involve many field-proven technologies such as reservoir characterization perforating coiled-tubing intervention matrix acidizing r


One of the biggest problems associated with the production of the crude oil in this environment is the production of massive amounts of solids
 ravel pack to open hole gravel pack designs. Non-gravel pack open hole designs are also being considered for the future to meet the challen
ment. The estimation of sand production volumes for openhole and cased and perforated completions is presented for the high rate gas wel
 creens in open hole and cased hole frac-packs. A review of the design for both producers and injectors along with the criteria related to the
under CT-scan on cohesionless sand samples allow to monitor in real time the initiation of the sand production and to follow the developme

n conditions are satisfied the sand rate is reasonably stable. This paper clarifies nine forms of post-failure stabilization. Subsequently field m

 mpletion and sand management strategy for more than 400 wells in the field. It was decided to apply a particular systematical approach term
mples in the low to intermediate strength range for defining the stress-strain relationship (or material laws) rock failure and yield criteria and
ry sand prevention will mean unwarranted reduction in productivity. Reliable sanding prediction analysis thus provides a basis for designs tha
ry sand prevention will mean unwarranted reduction in productivity. Reliable sanding prediction analysis thus provides a basis for designs tha
a and field data) were integrated to generate a Mechanical Earth Model (MEM). This model provided the descriptions of the rock strengths an
a and field data) were integrated to generate a Mechanical Earth Model (MEM). This model provided the descriptions of the rock strengths an
nes obtained from downhole and outcrop. The tests were performed under simulated in-situ effective stresses and drawdown conditions. Wa
nes obtained from downhole and outcrop. The tests were performed under simulated in-situ effective stresses and drawdown conditions. Wa
nce is that rock disaggregation is not seen to represent the onset of sanding because the sand mass can offer significant resistance from fri
nce is that rock disaggregation is not seen to represent the onset of sanding because the sand mass can offer significant resistance from fri

e ratio of CO2:CH4 declines with time during field and laboratory desorption testing of coal cores. In this study we investigate numerically the
g but also its rate and severity in real time. A series of well-documented experiments on a large-size horizontal wellbore was simulated usin
g but also its rate and severity in real time. A series of well-documented experiments on a large-size horizontal wellbore was simulated usin

 ets etc. Thus historically any incidence of sand production led to a well shut in. The objective of this intervention was to evaluate integrity o
 . A numerical approach was used for simulating the experimental results. The material behavior was simulated using an elastoplastic stress

 . A numerical approach was used for simulating the experimental results. The material behavior was simulated using an elastoplastic stress

ransport of the sand out of the perforations and up to the surface being the second step. Existing sand production prediction models have f
data required for the study include: 1) in-situ stresses including magnitude and orientation and formation pressure 2) mechanical and petro
opments ever undertaken. The fields began production in Q1 2001.�Preliminary scaling studies identified a risk for calcium carbonate sc
vided by combined injection of gas and Utsira aquifer water. The wells are a combination of platform and subsea and comprise extended rea
per replicate the experimental results very well. On the other hand the results estimated from the McLeod method and the Karakas-Tariq me
  cased perforated well may have lower productivity (as characterized by a positive skin factor) relative to the equivalent openhole completion
tic properties of the treating fluids. This is because of the ability of surfactant monomers to associate and form rod-shaped micellar structure
  temperature. Yet another concern in acid fracturing in long carbonate intervals is attaining the necessary diversion to ensure that multiple s
 . In our tests the injection rate into the fracture is much higher than in many previous tests and the fluid loss flux is controlled to match field
  temperature. Yet another concern in acid fracturing in long carbonate intervals is attaining the necessary diversion to ensure that multiple s
 and wider fractures. Diesel emulsified acid for deeper penetration and in-situ gelled acid a polymer-based system are used to control exces
  and wider fractures. Diesel emulsified acid for deeper penetration and in-situ gelled acid a polymer-based system are used to control exce
ents especially for acid treatments on wells with long heterogeneous intervals or multiple-zone completions. A VES diverting agent is of part
ave been treated using dedicated stimulation vessels. Acid-fracture treatments have typically been pumped at high rates (50+ bbl/min) treati


 ts as a temporary barrier and diverts the fluid into the remaining lower-permeability treating zones. After treatment the SDVA barrier breaks

methods of placement. Pre- and post-job production logs acquired in five wells provided analysis of changes in the production profiles. In one


  corrosive to well tubulars especially at high temperatures. To address problems associated with concentrated acids various retarded acids
methods of placement. Pre- and post-job production logs acquired in five wells provided analysis of changes in the production profiles. In one
 s limestone is atypical because of its texture—a granular aggregation of carbonate particles poor cementation and a moderate-to-low roc
 his is exacerbated by the relatively small injection rate imposed by the use of coiled tubing (CT). To make matters worse formation damage
 id on the surface. A series of effective methodologies for the stimulation of offshore multi�layer sandstone oil reservoirs was implemented

 x. Acid placement and diversion need to be carefully designed and optimized to effectively stimulate the wells by reducing the skin factor to
acidizing to alleviate these two problems. Though organic acids provide the benefit of retardation and low corrosivity their low dissolving capa

 and gas wells by fracturing or acidizing and fluids used to place filtration media to control formation sand production from oil and gas wells r

 ne Darcy. At different times in the past attempts were made to hydraulically fracture one or more of the sands using a variety of different (w
 ce of complete zone coverage without proper diversion. Therefore diversion is recommended in all treatments especially in extended reach
 m the water flood or the injection scheme is not optimized.� A consequence of reservoir pressure depletion is the increase in filtrate leak


  been proposed and implemented to stimulate such wells. However all of these methods offer short-lived stimulation and are sometimes not
 ies on stimulation treatments.� This study primarily explores the influence of pore scale heterogeneities on stimulation treatments.� So
 lacement of stimulation fluids for effective zonal coverage and generating wormholes to pass the damaged zone. Placing gelled acid throug
ment and the further influence of treatment properties reservoir fluid properties and the reservoir formation. From the sensitivity study we ca
rstanding these basic differences is essential to a successful restimulation. In the past candidate selection methodology has focused on un

oduction rates called for different options. One of those options was the recently developed CO2 viscoelastic surfactant (VES) fluid system. It
common practice has been to use oil-based fluids. However fluids of this nature can have detrimental effects on gas zones with low reservoi
oduction rates called for different options. One of those options was the recently developed CO2 viscoelastic surfactant (VES) fluid system. It
sed on comprehensive data. This process includes the current service standard of design execution and evaluation but goes far beyond b
ocking on gas relative permeability. A chemical treatment was developed to reduce the damage caused by condensate and water blocking. T




 a matrix treatment flows into high permeability sections and/ or high water saturation thief zones" resulting in higher water cut due to the ove
 ssary to fully achieve this objective. We previously showed that water influx time and source could be detected in horizontal wells in real tim
al operating mode. This paper will review BP’s efforts to team with manufacturers to deliver new technologies that can reliably provide th
al operating mode. This paper will review BP’s efforts to team with manufacturers to deliver new technologies that can reliably provide th
er1-4 or pressure surge is a pressure transient phenomenon which has long been known to occur as a result of a sudden change in fluid flow
  reservoirs pose special challenges selecting one type or the other due to the complex nature of fluid flow in porous media exhibited by these
eld that was poorly constrained due to limited offset well control and poor-quality seismic data. Third the final hole section 6 000 ft of 12�
y management. In response the reliability of these tools and their interpretations for determining the existence of poor behind casing cement
y management. In response the reliability of these tools and their interpretations for determining the existence of poor behind casing cement
  tool (Stim2001) for detailed candidate selection damage diagnosis fluid system selection and job design. QA/QC and compatibility tests a
 illing itself the completion also carried its own ones as the formation would require effective acid-stimulation (not only an acid wash) to reach
 ptimized wormhole geometry should be functions of reservoir properties such as permeability and pressure as well as fluid types such as oil
avity. All new installations were carried out without interrupting the ongoing production target. The project has completed a four-years operat
wdown on a well while jet pumping. Many formation powered jet pumps are being used in Kuparuk wells with gas lift to increase the drawdow



require completely fresh construction of entire facilities which will involve project development management costs infrastructure cost and s
st bottom hole flowing pressure for various Artificial Lift system types and wellbore geometry. Real life data acquired at the field trials was use
urmont SAGD development that would allow better control of lift gas into the production string and in late 2007 the wells completed with gas

l the conventional artificial lift systems have a common feature. The energy added to the lift the fluid from the wellbore is lost in the process a
wells. This paper extends that work to advanced completions employing Interval Control Valves (ICVs) and Inflow Control Devices (ICDs). It

ecause of well construction problems. Three wells on the remotely located wellhead platform were abandoned because of wellbore instabilit
gies. Introduction TOTAL AUSTRAL operates the Carina and Aries fields located in offshore Tierra del Fuego in the most southern region


n economic completion strategy so that depletion of reservoirs occurs evenly at the project’s termination. Single-well compositional simu
  techniques used in completing these high rate gas wells as open-hole gravel packs have included both water-packs and shunt-packs. The e
 only enhancement of individual well production rates but also significantly improved the oil recovery. This goal was achieved through optimi
  to the need for evaluating� the best sand-control solution while considering the cost/benefit ratio. This paper explains why an openhole g

valves to be placed in a single well without incremental reductions to the internal diameter (ID). This near full bore feature allows normal cem
en both vertically and horizontally on a well-to-well basis even though the wells are very closely spaced. Sands have different oil retainer cap
  sand control issues and the relative strengths/weaknesses of the systems available. Production hotspots arising from partially plugged scree
ries of self-regulating reactions with calcite and other minerals. However excess calcite does not improve the retention of phosphonate due
 lbore liquids are produced directly from the formation and/or condensed from the gas in the wellbore.� The produced liquids considered in
 lbore liquids are produced directly from the formation and/or condensed from the gas in the wellbore.� The produced liquids considered in

as been recently drilled in this reservoir achieving about 5 000 ft of reservoir contact.� This paper details the process followed to achieve th
as been recently drilled in this reservoir achieving about 5 000 ft of reservoir contact.� This paper details the process followed to achieve th

using the Decay Recursive Least Squares (DRLS) method. A case study in which a multi-zone horizontal intelligent well was located in comp
 control of commingled production from the laterals. Using the variable positions flow control valve the well was managed to improve and su
at downhole control may be used to adjust flow distributions along the wellbore to correct undesired fluid-front movement. In this paper we a
nd downhole control of commingled production from the laterals. The well was managed to improve and sustain oil production by eliminating
a steady-state wellbore simulator including choke models to represent the ICVs and inflow models to represent the near-well reservoir flow in

ompared to horizontal wells. With a total section exposed to the reservoir equal in both types an experimental model has been built for the pu
 nt tests carried out among reservoir fluids alcohol and inhibited diesel based treatments and formation cores from main Cupiagua field. Th

 by logging-while-drilling data had very high permeability regions in the heel of the horizontal and lower permeability in the toe.�If conven
ally available coupled well-performance and reservoir-simulation tools. Four DESP applications were analyzed. Where possible the robust

e erosion at various rates over the life cycle of the well to appropriately design the completion and select the appropriate materials. The eros
 ze operations in wells where the above equipment and operations are required. This paper summarizes practical experience gained during
 proportional hazards (CPHs) (Cox 1972) modeling to determine statistical significance of explanatory variables (EVs). Methods developed to
ores. Experimental studies on the rheology of polymer-enhanced foam were conducted using a specially designed flow-through rotational vis

ontal wells completed with slotted liners. The semi-analytical model is obtained by coupling the reservoir flow and wellbore flow equations. Th
s create significant conductivity enhancement in treated wells their etched fracture length is typically short because of the high speed at whic
 marine sandstone without hydraulic fracturing until drilling the CD2-37 well in 2003. The poor reservoir quality found in the southwestern edg
 marine sandstone without hydraulic fracturing until drilling the CD2-37 well in 2003. The poor reservoir quality found in the southwestern edg
 to 4 m respectively along the horizontal section. The wide variations in reservoir and rock properties present significant fracture design and

ne of 2005 a new technique was introduced utilizing chopped fibers within the fracturing gel slurry to help suspend proppant in the slurry both
ems oil-based systems or reduced polymer systems. The fluid systems can then further be pumped as linear gel pad stages with cross-linke
ration and in-situ gelled acid a polymer-based system have been extensively used in most fracture treatments in an attempt to control exce
centration up to 1000 kgPA and higher with only 3.0 kg/m3 (25lb/1000gal) guar polymer loading a feat previously only achievable with 3.6-4.
pment of Expandable Sand Screen (ESS) combined with fracturing treatment could not control produced sand due to failure in perforation te
a specific reservoir is not a simple matter for the end user and the existing literature is full of conflicting claims as to which one may be most
 der the combined effects of modulus contrast and in situ stress contrast on fracture geometry. A pseudo 3D (P3D) hydraulic fracture simulat

e pressures often would result in the need for surface treating pressures that exceed the limits of current surface equipment and tubulars. Su
ve length and conductivity and fluid recycling/handling are but a few strategies employed. Additionally operating companies have been seek
ned or requires expensive cleaning or dilution with fresh water to make it a viable solvent base for fracturing fluids. This paper describes the
  industry even for gas condensate systems. Recently some methodologies have been proposed to modify UFD considering the two-phase r
 ous Pin-point Stimulation Techniques) were implemented with an appropriate data collection strategy to evaluate and compare well performa
 ng a sand plug with the downhole tool set for circulation to isolate a bottom set of perforations followed by conventional frac-and-pack. Whe
 e fracture height growth. The method consists of pumping a predetermined mixture of specialty solid materials. The case study clearly demo
 ervoir engineering and operations. These aspects affect the optimization process for successful placement of treatments and optimum asse
 igh permeability streaks that require effective diversion techniques. The efficiency of chemical diverting agents in terms of flow distribution an
  affecting by consequence the mechanical properties of the rock in its whole thickness. This petrophysical and mechanical behavior of the re
 r cuts can be a rewarding operation. The treatment can be carried out while providing favorable economics to the entire operation. The ke
  Conventional multistage fracturing techniques including perforating fracture stimulating and isolating stages with a composite bridge plug h

 uff carbonate reservoir some wells have experienced complications during the drilling phase and encountered unexpected reservoir challeng


authors pose the question of whether non-Darcy and multiphase flow effects are of concern in typical oil wells in Russia. For the analysis th



authors pose the question of whether non-Darcy and multiphase flow effects are of concern in typical oil wells in Russia. For the analysis th
authors pose the question of whether non-Darcy and multiphase flow effects are of concern in typical oil wells in Russia. For the analysis th
hat had experienced poor recovery primarily because of poor permeability. There were unique challenges posed by the Gandhar candidate
ized in this study. The mathematical model described in this paper has been used to develop predictive and analysis graphical design charts

h asphaltene and paraffin oil content varying the hydrocarbon properties it is understandable that the extensive knowledge gained in Wester

menting operations. A control line is connected to sequential valves. When the bottom valve opens the control line becomes pressurized and
e cemented sliding sleeve concept by attempting to minimize and predict fracture initiation pressures. Finite Element Analysis (FEA) was c
e of soft rock that is a cohesionless granular impermeable medium. The real problem of hydraulic fracturing in an elastoplastic medium has
ico.�The fluid exhibits enhanced fluid efficiency while still maintaining the high proppant pack conductivity associated with the lack of poly

 ive of low-pressured water sensitive formations high rock Youngs’ Modulus and unpredictable occurrence of water-bearing zones lead
ive fracture height growth and poor fracture fluid cleanup. In the context of the Cotton Valley Formation bounding beds necessary to contain



sphalting Onset Pressure (AOP). An engineering solution was urgently needed to enhance the productivity of wells and to mitigate the asphe
oject (JIP) active since the year 2002. The data discussed builds on the initial results published in early 2006 which indicated that the polyme
oject (JIP) active since the year 2002. The data discussed builds on the initial results published in early 2006 which indicated that the polyme




oject (JIP) active since the year 2002. The data discussed builds on the initial results published in early 2006 which indicated that the polyme
y execution and results from two offset wells.� The first well was completed with a two stage hydraulic fracture treatment while the succes

ot known accurately and the velocity model is artificially adjusted to locate perforations on assumed positions several milliseconds discrepan
he Lance in Jonah consists of many stacked low permeability sandstones. Due to the low permeability stimulation is required for economica

 is often the most poorly understood parameter in the treatment with pressure transient and rate transient testing frequently indicating disap
ct of the acid-fracturing process we developed a new surface profilometer to measure the surface profile of a rock sample accurately and ra
f the height but also for p3D model where the height is indirectly obtained from coupling stress profile and fluid flow. Fracture azimuth is trad
al markets. This paper will describe a new patent-pending technology that can generate valuable data on propped fracture height as well as

 s particularly true for the Yamburgskoe gas condensate field where the wells are completed in a series of medium- and low-permeability re
 true if a liquid phase is also flowing. The apparent permeability of the proppant is a function of: Gas velocity (hence: rate and flowing pre
 e tip zone where the pressure drops below the far-field pore pressure. Moreover the assumptions of the Carter leak-off model do not apply i
s greater than the fracturing pressure of the formation. A new generation of viscoelastic surfactant-based acid was implemented in the field.
 state shape factors under boundary-dominated flow conditions.� Designing the optimum stimulation fracture treatment in this case is mor

and untested technology for hydraulic fracture diagnostics. Analysis of the surface microseismic data was carried out for five (5) hydraulic fra
on data. This difference in fracture geometry was attributed to rotations in the direction of minimum principal stress which is consistent with

g an appropriate completion method. The development of a model allowing a quantitative prediction of this process is therefore a very vital ta
 odel is developed to predict the growth of the two intersecting fractures in a variable stress field and the associated pressure response in ord
on fracture propagation. After hydraulic fracture formation terminated the cleanup procedure begins. Fracturing fluid is evacuated from the we

at the wellbore impeding both lateral and vertical extent. Differential cased hole sonic anisotropy (DCHSA) combines the use of cross-dipole
 lprit. The main results presented in this paper were obtained using a modified conductivity cell to allow polymer concentration via leakoff a



mping 1000 bbls of treated seawater at rates from 7 to 14.5 bpm surface pressures were still within the pressure limit of 3000 psi given by t
 n of a horizontal stress map for the studied area and an accurate measurement of the hydraulic fracture heights on the borehole wells togeth
ed 2D hydraulic fracture model. Offsets are geometrically characterized by their angle with respect to the main fracture direction and by their
productivity drivers using a database on well productivity related to different completions stimulations and production options. The database
n porous media is affected by both coupling (the increase of relative permeability (kr) as velocity increases and/or IFT decreases) and inertia
 s produced initially unassisted then later on a work-over campaign was launched in order to equip the well with electrical submersible pump
s have been applied in the industry as an alternative completion strategy. However previously documented annular jobs have been small siz
  and assuring well deliverability often are important concerns when developing gas-condensate reservoirs. Many gas-condensate projects ar
available dynamic multiphase well simulation tool (OLGA) and a dynamic multi-phase reservoir simulator (MoReS). In order to give a proof o
gas lift systems have been installed at the time of writing of this paper most of them in the Scandinavian sector of the North Sea. Several pap
  techniques used in completing these high rate gas wells as open-hole gravel packs have included both water-packs and shunt-packs. The e
 r emulsions were injected into etched-glass micro-models and micro-models packed with glass beads. The effect of droplet-to-pore size rati

have measured the high-velocity coefficient β in steady-state two-phase gas/liquid flow. The results are presented as a function of liquid rela
  of the treating fluid is lost so that treatment of the entire section is inefficient. Traditional completion practice on Al Khalij field (Qatar) involv
  control or sometimes could be designed on purpose for an extremely anisotropic formation. When vertical permeability is much smaller tha
ntegrated solution was required to improve field injection performance. This paper presents field data on an injectivity study of several Prudh
ating to time savings more efficient fractures faster cleanup and less safety hazards. Conventional methods of cementing a liner in place pe
ating to time savings more efficient fractures faster cleanup and less safety hazards. Conventional methods of cementing a liner in place pe
  esents the case of a gas producing horizontal well in Indonesia completed with a perforated liner. The target reservoir is a clean sandstone r
  esents the case of a gas producing horizontal well in Indonesia completed with a perforated liner. The target reservoir is a clean sandstone r
 . In this paper we will review the unique advantages and disadvantages of horizontal openhole completions in the Colville River field. Three
 that the compartmentalized completion with inflow control valves (ICVs) in the smart well has added value because the well would not be pr
 shutdown the wellbore fluid can be pushed down below the mudline using the dry gas from the glycol contact tower followed by diesel or me
   capillary number and its dependency with velocity called Positive coupling is not yet analyzed in transient tests. As it has been mentioned i



ntly developed for single-phase- and multiphase-fluid flow along a vertical deviated or horizontal well will first be briefly described. The mode

e regardless of choke positions. The well is on a WAG cycle in which one zone is primarily intended for gas injection and the other three zon
ce completion system with digital permanent down hole monitoring system. Intelligent completions allows individual lateral testing allocation o
BP to successfully develop Na Kika with a minimum number of wells and continues to help provide world-class reservoir surveillance data a
arly ‘90s. ICDs have recently gained popularity and are being increasingly applied to a wider range of field types. Their efficacy to control th
 er breakthrough. This early water breakthrough causes reduction in potential hydrocarbon recovery; the operation of the ICD is minimizing re
 degree of un-even fluid-front progression needs to be induced in order for effective ICV control to be observed to “Add sufficient “V
ous reservoirs using a single wellbore. Their capability to restrict water or gas production and improve ultimate recovery has helped optimiz
 e rather than “Reactive ICV choking policy can add greater value. Reservoir scenarios were created in which inter-zone connection per


ntrol (MAC) injection and production at the zonal level. Analysis of sensor data will allow operations to estimate well capacity and calculate m
system with digital permanent down hole monitoring system. Intelligent completions will allow individual lateral testing and allocation of prod
 ggered by permanently installed downhole sensors can enhance production and mitigate reservoir uncertainty across a range of production
were captured by the fixed pressure probes and showed a distinct fluid lag region (i.e. a lower fluid pressure region close to the fracture tip).
were captured by the fixed pressure probes and showed a distinct fluid lag region (i.e. a lower fluid pressure region close to the fracture tip).
s SurfactantAlternatingGas (SAG). The CO2 was either under sub- or super-critical conditions whereas N2 remained under subcritical condit
Benteimer and Berea sandstone and sintered glass with large permeability contrast. X-ray computed tomography (CT) scans are used to vis
 ion Foam is an excellent acid diversion agent for matrix acidizing operations. It is inherently non-damaging and often low cost allowing easil
 where the use of the wellhead as the evaluation point can lead to erroneous conclusions. The most obvious situation occurs with a change i

y-state based liquid load-up prediction approach and nodal analysis are insufficient to answer what happens when the well shuts in restarts a
 reduced which increases the velocity and restores liquid transport to surface. The disadvantage of the velocity string is the increase in frictio

order to help the gas to flow unobstructed again. The major challenge however is to find a suitable artificial lifting technology as most artifici
nclination angle flow regime transitions and the interaction between tubing outflow behavior and the reservoir IPR. In the paper the behavior
and building resource capability. This paper outlines the scope of impact and opportunity in North America followed by the industry’s app
ore decided to try liquid batch injection in several North Sea gas wells. The paper speaks about candidate selection chemical screening lab
esearch was conducted in two stages. First we modeled a simple synthetic gas well and simulated the liquid loading behavior. We observed
h and to configure the approach for various well characteristics. Background Water enters most gas wells. At the early stages of production

sidered for liquid accumulation and slug height modeling. The new method improves the prediction precision compared to the conventional m
 l effectively allowing gravity to separate the gas and water. The rule of thumb (in this instance) is to limit the downward liquid velocity to valu
ped a model to predict the placement of injected acid in a long horizontal well and to predict the subsequent effect of the acid in creating wo

 ar the wellbore and 4) decrease in pressure drop near the wellbore to values below the critical threshold for sanding. Even though there are

well performance prior to the production test. We present an integrated and structured approach for calculating the productivity of a laminate
  problems are expected after depletion increase in water cut and installation of ESPs to optimize production. To accomplish this task a 3D
e perforating and other near wellbore damage therefore perforating design is not important as long as it serves the purpose of puncturing thr
 rmation immediately after perforation and a perforating technique that utilizes the dynamic underbalanced method which cleans perforations
 ed to perforate numbers of infill wells with low success ratio. The reservoir characteristics with high formation pressure and BHT followed by
ce simulations. The quality and amount of data was recognized to be limited. However a qualitative diagnosis of these results indicated that t
 hrough the LEP hardware. Modelling of the injection scenario with LEP’s has shown that in high permeability contrast reservoirs at critic
ervoirs are generally of lower porosity and higher compressive strength. Drilling-mud-filtrate invasion also tends to be deeper. Deep-penetrat
  application.� It includes a perforating system database built from published API data.� This is not ideal since API Section I data are an
or other hardware that can be damaged during perforation. The traditional approach of hiring a workover rig to remove the completion prior to
or other hardware that can be damaged during perforation. The traditional approach of hiring a workover rig to remove the completion prior to
 e waiting for the multipurpose barge and in some cases eliminate the need for stimulation. This new perforating technique utilizes a unique


ethod that would help optimize well productivity and at the same time be cost effective without compromising the results of the operation an
r.� The use of a drill-in liner however necessitates perforating.� Typically completions in such reservoirs are acid stimulated to maxim
r.� The use of a drill-in liner however necessitates perforating.� Typically completions in such reservoirs are acid stimulated to maxim
ontinuously varies during the surge; (b) the skin factor may decrease substantially during the flow period because the mud cake invaded filtra
lbore fluid displacement is often deemed insufficient to create effective cleanup of the perforations. This paper outlines a solution to these ch



wellsite and cumbersome logistics the main set back with the e-coil is its unavailability while the tractor has high operational cost. This pape
n their own experiences and previous perforating histories to roughly estimate the swell or damage conditions of similar perforators. In this p

 nly difference of note was the design and composition of the liner. All other charge design parameters were kept constant. For both rock typ
ore they are used for production or injection. In the depleted oil field under study a typical completion is perforated using large diameter high
 led-up producers from giant offshore field A submitted to seawater flooding (Campos Basin Brazil) in order to predict productivity index and
 ith explicit expressions for deposited concentration and injectivity decline was developed. The location of scale deposition and the resulting
  pact the waste disposal process.�It is therefore necessary for well injectivity planning and fracture sizing to have an accurate estimate o

hallenging areas in Ghawar field where the water will reach the wellbore much faster via the reservoir's fractures. Using the smart completion
 nges presented by the heavy oil and the large geographical extension of the reservoir the decision was made to develop the field with horizo
uated to help minimize the risk of fines plugging because of the high fines content (10 to 15%). To minimize well interventions while maximizi
tion the reservoirs were cleaned up through a temporary well clean-up and test facility to test productivity and evaluate integrity of the downh
 ls. To help ensure high rate long life completions the producing zones are frac-packed. The average perforated interval during the initial co
help ensure high-rate long-life completions the producing zones are frac packed. The average perforated interval during the initial completio
north to south. Production in Hawtah comes from the Unayzah sandstone and consists of Arabian super light (50� API) sweet crude oil. H
 ing these case-history jobs. Introduction Chevron and Marathon each have a 50% working interest in the Petronius project which is operat

 ly managed sand production) versus frac-packing. Sand onset prediction agrees fairly well with the observed drawdown/depletion for horizon
 odification because they were only validated to 1 000 psi in the current laboratory test apparatus. A series of burst tests were conducted on
ing across the two zones. Upon completion the reservoirs were cleaned up through a temporary well-cleanup and test-facility to test product

were used successfully on the first two wells. The A1ST1BP1 completion failed during initial unloading allowing unacceptable rates of sand p
ut ten years of production a significant amount of sand was observed during routine sampling of the well. This condition resulted in the closu


ntegrated approach was adopted for the design of the fluid systems involving extensive formation damage and fluid compatibility testing. To t

skins for the high-angle OHGP gas wells and finally to develop a recommendation for the optimized design. A comprehensive semi-analytic
the production screen aim the isolation of certain reservoir zones. In these cases gravel pack placement present an additional constraint â€

ure and even flow distribution throughout the producing interval of the well.� A review of the completion methodology in poorly sorted unc
ntegrated approach was adopted for the design of the fluid systems involving extensive formation damage and fluid compatibility testing. To t

 cking was the common completion in a single sand body however in presence of shales open-hole expandable screens with annular barrier
aused by unpredicted downhole events. In this paper we present a new approach for gravel packing long high angle openhole intervals witho
 lti-zone (STMZ) technology. Two different STMZ techniques have been applied because of differing well characteristics and objectives. To d
selected to facilitate the completions were successful in achieving the project goals of the operator.�These goals included not only the pr
successfully designing these jobs. This paper presents a pseudo-3D modeling tool which models the complete gravel-pack process and acc
gravel packing in the industry deals primarily with water based fluid environments new challenges for gravel packing of the associated wells



the production intervals and allowing the wells to cleanup the Productivity Index (PI) measured on each well was very disappointing. A diagn
on tunnels and improved the connectivity to the reservoir. Guidelines to surging the formation and executing the perforation packing job are
on tunnels and improved the connectivity to the reservoir. Guidelines to surging the formation and executing the perforation packing job are p
on without any sand being produced. A production log showed that all three payzones were open. The well did not produce any water. A mo
 orizontal wells due to traverse several shale and sand bodies of varying quality. Perforation tunnels with optimal “structural stability for th

 rval has failed most times requiring production to be shut in for diagnosis. Not until that point can a remedy be evaluated. One GOM produc
 heavy and viscous oil of 19� API - 9 cP. This causes sand production high water cut wormhole development and requirement for artificia

ubing intervention matrix acidizing resin consolidation optimized fracturing with proppant flowback control and fines migration prevention. T
ubing intervention matrix acidizing resin consolidation optimized fracturing with proppant flowback control and fines migration prevention. T


 duction of massive amounts of solids. In addition to the cost of the recompletions problems associated with disposing of this amount of sand
ered for the future to meet the challenges of drilling and completion at higher well angle. The field requires a mix of all these techniques to me
s presented for the high rate gas wells along with the workflow used for the selection and optimisation of the completion design based on th
  along with the criteria related to the sand characteristics and off-shore implementation of the completions will be described. Production str
 duction and to follow the development of the sand producing zone. In parallel a numerical approach is proposed to simulate the dominant

re stabilization. Subsequently field methods to deal with sand problems with uncertain sand rate predictions are proposed. Introduction Per

particular systematical approach termed as Sand Management Solution (SMS) to properly address the sanding issues it was facing which
 s) rock failure and yield criteria and other non-linear rock parameters required for numerical modeling analysis; (3) perform a series of form
 thus provides a basis for designs that achieve appropriate sand management strategies and maximization of economic production and ove
 thus provides a basis for designs that achieve appropriate sand management strategies and maximization of economic production and ove
  descriptions of the rock strengths and in-situ stresses in the reservoir formation. Somewhat surprisingly the model backed up by the core la
  descriptions of the rock strengths and in-situ stresses in the reservoir formation. Somewhat surprisingly the model backed up by the core la
esses and drawdown conditions. Water was introduced into the flowing stream of either oil or gas at various stages of the tests to simulate w
esses and drawdown conditions. Water was introduced into the flowing stream of either oil or gas at various stages of the tests to simulate w
an offer significant resistance from frictional properties interlocking of sand grains and arching.� The approach presented here can be us
an offer significant resistance from frictional properties interlocking of sand grains and arching.� The approach presented here can be us

 study we investigate numerically the importance of coal fabric namely cleat spacing and aperture width on the performance of coalbed gas
orizontal wellbore was simulated using a finite difference numerical model. The model accounts for the interaction between fluid flow and me
orizontal wellbore was simulated using a finite difference numerical model. The model accounts for the interaction between fluid flow and me

tervention was to evaluate integrity of the completions and the remaining production potential of each of the wells. As deepwater and subsea
mulated using an elastoplastic stress-strain relationship. The model simulated the interaction between fluid flow and mechanical deformation

mulated using an elastoplastic stress-strain relationship. The model simulated the interaction between fluid flow and mechanical deformation

  production prediction models have focused on predicting the onset of sanding by predicting the drawdown at which failure of the formation
 n pressure 2) mechanical and petrophysical properties of the formations transected by the wellbore and 3) properties of drilling fluid and its
 ified a risk for calcium carbonate scaling with an increased scaling risk as the wells mature.� In May 2002 the first obstruction occurred a
d subsea and comprise extended reach horizontals with complex geometry and lesser numbers of vertical wells. Detailed scale predictions h
od method and the Karakas-Tariq method substantially deviate from the experimental data; hence these models/methods should be used w
o the equivalent openhole completion because of two factors: the convergence of the flow to the perforations and the blockage of the flow by
 d form rod-shaped micellar structures under certain conditions. Viscoelastic surfactant-based acid systems have been used in Saudi Arabia
ary diversion to ensure that multiple sets of perforations are adequately stimulated. Because of their high solubility and highly fractured/vugu
d loss flux is controlled to match field fluid loss rates. We studied three commonly used acid fracturing fluids—an acid viscosified with polym
ary diversion to ensure that multiple sets of perforations are adequately stimulated. Because of their high solubility and highly fractured/vugu
 ed system are used to control excessive leak-off at different stages of the treatment along with the alternating stages of polymer pad. Thes
sed system are used to control excessive leak-off at different stages of the treatment along with the alternating stages of polymer pad. Thes
 ons. A VES diverting agent is of particular interest to remedial treatments of frac-/gravel-packed wells because damage to the near-wellbore
ped at high rates (50+ bbl/min) treating multiple intervals simultaneously using various methods for fluid diversion including ball-sealer techn


 treatment the SDVA barrier breaks when contacted either by formation hydrocarbons or pre- and postflush fluids. Quantifying diversion flui

 ges in the production profiles. In one of the wells the formation was stimulated first with 15% HCl through coiled tubing and then with the v


ntrated acids various retarded acids were introduced. Organic acids were used also in some cases. These organic acid systems were used
 ges in the production profiles. In one of the wells the formation was stimulated first with 15% HCl through coiled tubing and then with the v
 entation and a moderate-to-low rock strength. Core analysis and rock mechanics assessment revealed that much of the rock is weak and
ke matters worse formation damage in horizontal wells is usually very deep as a result of long exposure times. This paper discusses the ap
stone oil reservoirs was implemented. The chemistry and art of four different acidizing methods involving Tubing Pickling Bullheading Diver

e wells by reducing the skin factor to the lowest possible value in each zone. At the same time the selected optimum acid system placemen
w corrosivity their low dissolving capacity may still limit the wormhole penetration leading to insufficient stimulation of the formation. Therefor

d production from oil and gas wells respectively. The procedure considers filter paper medium natural core and synthetic core as the three

 sands using a variety of different (water- and oil-based) fluids. However many of the wells indicated positive skin factors following the fractu
 tments especially in extended reach and multi-lateral wells. Diversion techniques can be classified as mechanical or chemical.� Mechan
epletion is the increase in filtrate leak-off of drilling completion as well as stimulation fluids. The sensitivity of the formation to wellbore fluids


 d stimulation and are sometimes not profitable. New experimental core flooding data using chemical treatments show that the steady-state g
es on stimulation treatments.� Some results on the influence of core scale heterogeneities are also presented. Core samples from eight
ged zone. Placing gelled acid through coiled tubing has been the standard practice to clean up the wellbore. Due to the low pumping rate st
ion. From the sensitivity study we can conclude that the most influential factors in the treatment response i.e. the water cut reduction are th
 tion methodology has focused on underperforming wells. This simplistic approach has yielded disappointing results and has led to a commo

astic surfactant (VES) fluid system. It has recently been employed to eliminate the disadvantages of the traditional polymer-based fluid. This
 fects on gas zones with low reservoir pressure and this might be the reason for erratic well performance of previously treated Frontier comp
astic surfactant (VES) fluid system. It has recently been employed to eliminate the disadvantages of the traditional polymer-based fluid. This
nd evaluation but goes far beyond basic well stimulation which has historically used limited data. Another important feature of the integrate
 by condensate and water blocking. The treatment is composed of a fluorinated material delivered in a unique and optimized glycol-alcohol s




 ng in higher water cut due to the over stimulation of the water zones instead of the oil bearing zones. The objective of the present field case
 etected in horizontal wells in real time1. Extension of this technique will be shown to allow confident detection of water influx in vertical or dev
 hnologies that can reliably provide this functionality. By 2010 a significant portion of BP’s production will come from complex water flood
 hnologies that can reliably provide this functionality. By 2010 a significant portion of BP’s production will come from complex water flood
 esult of a sudden change in fluid flow velocity. In water injectors rapid shut-in creates a water hammer. Over time injectors that undergo rep
 w in porous media exhibited by these low interfacial tension systems which are different from those of conventional gas-oil systems. In this
e final hole section 6 000 ft of 12�-in. hole inclined at 48� was to be drilled through two pressure ramps one unstable slump zone and
stence of poor behind casing cement quality and possibly hydraulically communicating layers was critically and systematically examined by a
stence of poor behind casing cement quality and possibly hydraulically communicating layers was critically and systematically examined by a
gn. QA/QC and compatibility tests aiming to obtain high success rate. In Brunei Shell a self-raising rig (BIMA) with a coil-tubing unit on boa
ation (not only an acid wash) to reach the desired levels of productivity. Stimulation of long intervals and how to ensure full coverage of treat
ure as well as fluid types such as oil or gas. To generate wormholes of various diameters and penetration depths different acid types and vo
ct has completed a four-years operating cycle while continuously maintaining the field production rate with an acceptable ESP failure and run
with gas lift to increase the drawdown applied to the A sand. An overview of formation powered jet pumps used at Kuparuk Field is presente



ment costs infrastructure cost and space limitation especially in the case of offshore locations. In the Southern Offshore Area of Chevron op
ata acquired at the field trials was used to validate model results. The selection strategy resulted in the creation of a robust artificial lift selecti
e 2007 the wells completed with gas lift were placed on production. This paper will cover the data collection effort and analysis completed to

 m the wellbore is lost in the process and cannot be utilized for some other operation. This paper describes a new technique of artificial lift wh
 nd Inflow Control Devices (ICDs). It reports a comparative study that illustrates the greater cleanup efficiency of advanced long horizontal w

ndoned because of wellbore instability. Without the production contribution from these wells the first year’s production target would not b
 l Fuego in the most southern region of Argentina (Figure 1).� These fields are prolific gas fields and are being developed with a reduced n


tion. Single-well compositional simulations formed the backbone for our evaluation of three completion options. Each reservoir was characte
 water-packs and shunt-packs. The experiences gained from these operations have now become part of BP’s open-hole gravel pack be
his goal was achieved through optimization of the development system and improved development of oil-water zone reserves and the reserv
 is paper explains why an openhole gravel-pack completion was the best option in spite of some challenges such as large vertical net pays a

ar full bore feature allows normal cementing operations to be preformed with a special cement wiper plug. A control line is connected betwee
  Sands have different oil retainer capacity and flow from clean to dirtier sands. The lower most units comprise of unconsolidated sands that a
 ts arising from partially plugged screens are often a problem giving rise to the challenge of installing rugged sand face completions which a
ve the retention of phosphonate due to the surface poisoning effect of Ca2+. The squeeze can be designed so that maximum squeeze life is
½ The produced liquids considered in the analysis can be water and/or liquid hydrocarbons. This paper presents an optimization technique f
½ The produced liquids considered in the analysis can be water and/or liquid hydrocarbons. This paper presents an optimization technique f

ails the process followed to achieve this milestone for the first time in Kuwait. A multi-disciplinary team consisting of Geology Petrophysics G
ails the process followed to achieve this milestone for the first time in Kuwait. A multi-disciplinary team consisting of Geology Petrophysics G

al intelligent well was located in complex reservoir showed that the GPC operation is highly effective. The robustness of the technique was illu
well was managed to improve and sustain oil production by eliminating water production. Monitoring the rate and the flowing pressure in real
 -front movement. In this paper we address several technical issues related to downhole controls. We consider a single system comprising t
  sustain oil production by eliminating water production by use of the variable-positions flow-control valve. Monitoring the rate and the flowing
present the near-well reservoir flow in the various zones. The parameters of the model need to be updated regularly using real-time measure

mental model has been built for the purpose of studying the production performance of the abovementioned well configurations. Production pe
 cores from main Cupiagua field. These tests are focused about the behavior of these treatments when they are applied in core flooding tes

 r permeability in the toe.�If conventional completion methods (i.e. stand-alone screens gravel packs or expandable screens) were used
 nalyzed. Where possible the robustness of the numerical-modeling results will be compared with analytical predictions. DESPs gave improv

 the appropriate materials. The erosion nodes within the completion - changes in flow direction (e.g. a tee such as in the wellhead) and/or flo
s practical experience gained during the development and deployment of this system. Introduction During the completion process of a well
 riables (EVs). Methods developed to facilitate EV factor collapsing are also discussed (the partitioning of levels of each factor into nonempty
y designed flow-through rotational viscometer and pipe viscometers with different concentrations of hydroxyethylcellulose (HEC) polymer. Co

   flow and wellbore flow equations. The model includes the additional pressure drops due to mechanical skin and non-Darcy effect. Additiona
  rt because of the high speed at which acid spends upon contact with the high temperature reservoir. The quest to increase the effective half
 quality found in the southwestern edge of the field required stimulation to produce at economic rates. A hydraulic fracture treatment was perf
 quality found in the southwestern edge of the field required stimulation to produce at economic rates. A hydraulic fracture treatment was perf
 resent significant fracture design and execution challenges. Results indicate that propped-fracture treatments become increasingly more dif

p suspend proppant in the slurry both during the fracture pumping and also during fracture closure. The primary goal was to be able to create
 linear gel pad stages with cross-linked proppant stages with or without the use of materials for fracture height-growth control (HGC). The Yar
atments in an attempt to control excessive leak-off during the treatment. The vertical well treatments target several reservoir sub-layers with
previously only achievable with 3.6-4.2 kg/m3 (30-35lb/1000gal) gel loading in similar geological conditions.� In addition to reducing dama
d sand due to failure in perforation techniques. An improved idea of perforating only the lower side of deviated wells using minimum viscosity
  claims as to which one may be most appropriate. This paper compares four different flowback aids: microemulsion two water-wetting flowb
o 3D (P3D) hydraulic fracture simulator with a rigorous layered modulus formulation is used in this study. The fracture height calculated base

  surface equipment and tubulars. Surface treating pressure can be calculated using the equation: Ps = BHTP + Pfric – Phyd …………â
operating companies have been seeking other cost-control measures including reducing the number of additives in fracture fluids and minim
 ring fluids. This paper describes the process to properly design fracturing fluids using flowback and produced water. The importance of flow
dify UFD considering the two-phase region around the fracture as a damage zone with reduced permeability. These methods are generally o
  evaluate and compare well performance. Micro seismic data tracer logs and pump-in data were used to calibrate and constrain appropriate
  by conventional frac-and-pack. When this procedure is followed the fracture is forced to propagate along the upper intervals. This novel tec
aterials. The case study clearly demonstrates the challenges encountered in the attempt to increase the fracture half-length in order to impro
ment of treatments and optimum asset performance. In this paper we discuss the various factors crucial to successful completion of a fractur
 agents in terms of flow distribution and uniform coverage is limited when it comes to treat such complex wells with long openhole intervals (s
 al and mechanical behavior of the reservoir added to the possibility of finding free water in the lowest part makes it difficult to reach the bes
mics to the entire operation. The key fluid for treating high water cut wells is a Viscoelastic fluid that provides self-diversion from water to oi
  ages with a composite bridge plug have been applied in some cases with limited success. The time consumed in the completion operations

 ntered unexpected reservoir challenges which has kept them from achieving their production targets. These wells require stimulation to rega


 wells in Russia. For the analysis the authors evaluate three primary categories of Russian production wells: gas wells oil wells producing a



 wells in Russia. For the analysis the authors evaluate three primary categories of Russian production wells: gas wells oil wells producing a
 wells in Russia. For the analysis the authors evaluate three primary categories of Russian production wells: gas wells oil wells producing a
 es posed by the Gandhar candidate wells. Earlier attempts to fracture wells had been unsuccessful. In addition the water bearing sand posed
  and analysis graphical design charts of the dimensionless productivity index and pseudosteady state shape factors for use in improved hydr

 tensive knowledge gained in Western Siberia can not be translated to the less frequent but well engineered and planned stimulation campaig

 control line becomes pressurized and transfers this pressure to a piston in the valve immediately above. This piston squeezes a C-ring and m
  Finite Element Analysis (FEA) was conducted to estimate the stresses in the cement and formation near the wellbore with sliding sleeve. FE
 ring in an elastoplastic medium has been represented in the model as brittle hydraulic fracture growth in a quasielastic medium. The medium
  tivity associated with the lack of polymer damage.� In this paper laboratory test results for the new fluid are presented along with three

urrence of water-bearing zones lead to the selection of foamed VES fluids.� This technology was successfully applied in the Morrow Sand
bounding beds necessary to contain a large hydraulic fracture are non-existent except for the Taylor sand. Studies have been conducted of f



 ity of wells and to mitigate the aspheltene deposition issue by allowing the wells to produce above the AOP. The option of acid fracturing was
2006 which indicated that the polymer concentrates only in the filter cake and that flow along the fracture encounters significant yield stress w
2006 which indicated that the polymer concentrates only in the filter cake and that flow along the fracture encounters significant yield stress w




2006 which indicated that the polymer concentrates only in the filter cake and that flow along the fracture encounters significant yield stress w
 c fracture treatment while the successive offset was completed via a single-stage fracture treatment.� The evaluation tools utilized to dete

itions several milliseconds discrepancies between measured and modelled SH-P-wave traveltime differences may appear along the receive
stimulation is required for economical production rates. Gross pay intervals vary from 2 800 ft to 3 600 ft and wells are stimulated in multiple

  nt testing frequently indicating disappointingly short fractures of limited conductivity.� In order to design an optimized fracture treatment it
 le of a rock sample accurately and rapidly and used the instrument to characterize fracture surfaces after acidizing. The profilometer measu
nd fluid flow. Fracture azimuth is traditionally provided by the horizontal stress anisotropy from open hole sonic logging. Unfortunately in Wes
on propped fracture height as well as insight into propped fracture width. In this new technology a non-radioactive tagging additive is incorpo

s of medium- and low-permeability reservoirs. Some wells cannot maintain stable production rates and have either been shut-in or are on in
 velocity (hence: rate and flowing pressure) Ratio of free liquid rate to gas rate Stress on the proppant Type of proppant Thus appa
e Carter leak-off model do not apply in this zone. This work presents a fundamental study of fracture tip behavior in high permeability formati
 d acid was implemented in the field. A short term production evaluation based on the initial production (post flowback) from these wells could
 fracture treatment in this case is more heavily weighted on the achievable Stimulation Index (SD) for a given set of reservoir parameters and

s carried out for five (5) hydraulic fracture stages to: (1) determine the applicability of the surface microseismic approach in the absence of a
cipal stress which is consistent with observed differences in the injection pressures. Introduction The effectiveness of hydraulic-fracture stim

his process is therefore a very vital task. In this paper we present a quantitative model to predict proppant flowback. The model is based on tr
 associated pressure response in order to obtain an insight into the refracture process. The modeling results show that a refracture treatmen
cturing fluid is evacuated from the well and fracture being displaced by the oil and gas flow under the influence of pressure differential. The q

SA) combines the use of cross-dipole shear sonic analysis carried out before and after hydraulic fracturing and adequately supported by othe
w polymer concentration via leakoff and measurements of flow initiation gradients. The paper will discuss the experimental set-up and som



 pressure limit of 3000 psi given by the Floating Production Storage and Offloading (FPSO) facilities. However the injection rate was decrea
e heights on the borehole wells together with a representative Mechanical Earth Model (MEM). In these mature fields an accurate evaluation
e main fracture direction and by their length. Quantitative comparisons on fracture length width and injection pressure are made for several o
nd production options. The database contains 56 wells from 4 different assets and 750 acid and proppant treatments in 663 perforated interv
 es and/or IFT decreases) and inertial (i.e. the reduction of kr as velocity increases) effects. However the interaction of capillary viscous and
well with electrical submersible pumps (ESP). Work-over operations were taken as an opportunity to re-stimulate lower-performing wells of t
ted annular jobs have been small size ranging from 40k to 200k lbs of proppant pumped at relatively low injection rates of 15-25 BPM. This
 rs. Many gas-condensate projects are in deep hot low-permeability reservoirs for which well costs are a significant part of the project econo
r (MoReS). In order to give a proof of principle we have implemented a PID feedback controller which controls the gas fraction in a well by c
 sector of the North Sea. Several papers have discussed this technology but so far none has presented a rigorous analysis or solution of the
 water-packs and shunt-packs. The experiences gained from these operations have now become part of BP’s open-hole gravel pack be
The effect of droplet-to-pore size ratio droplet stability oil and surfactant type and concentration were studied through visualization experime

presented as a function of liquid relative permeability and liquid saturation. In our measurements the wetting state is varied by the treatment
  actice on Al Khalij field (Qatar) involved cemented casing perforations and subsequent stimulation of the limestone with retarded emulsifie
 ical permeability is much smaller than horizontal permeability an undulating wellbore may be favorable to overcome the low vertical permeab
n an injectivity study of several Prudhoe Bay injectors. Step rate tests results indicated no significant difference in injectivity between horizont
hods of cementing a liner in place perforating fracturing and repeating the process for the number of stages required can be very time cons
hods of cementing a liner in place perforating fracturing and repeating the process for the number of stages required can be very time cons
arget reservoir is a clean sandstone reservoir. The horizontal drain is 1155 feet (ft) long. The reservoir permeability is ranging between 0.1 an
arget reservoir is a clean sandstone reservoir. The horizontal drain is 1155 feet (ft) long. The reservoir permeability is ranging between 0.1 an
 ons in the Colville River field. Three key parameters were critical to the success of horizontal openhole completions and could be applied br
ue because the well would not be producing from over half of the reservoir section without the smart completion. Introduction Brunei Shell P
ontact tower followed by diesel or methanol. Thus it eliminates the hydrate risk during extended shutdowns. Confirmed by the actual data th
ent tests. As it has been mentioned in literature the effect of coupling over gas condensate wells improves the pair of krg and krc and minim



 l first be briefly described. The model can be applied for both wellbore temperature prediction (forward modeling) and for flow profiling using

  gas injection and the other three zones are primarily intended for water injection. Therefore equipment that can control and measure water
 s individual lateral testing allocation of production rates to optimize each lateral contribution and the overall commingled well rate. Along with
 d-class reservoir surveillance data and ensure high standards of reservoir management. The fields are in a complex deepwater turbidite en
 field types. Their efficacy to control the well inflow profile has been confirmed by a variety of field monitoring techniques. An ICD is a choking
  operation of the ICD is minimizing reserves left behind. If water breaks through in a well without ICD these hydrocarbons are lost and canno
bserved to “Add sufficient “Value to justify the costs and risks involved in installing this relatively new technology. ICV(s) can balance
 ultimate recovery has helped optimize overall drilling completion and production costs. Electric Submersible Pumps play a key role in produ
d in which inter-zone connection permeability contrast between zones zonal length and other reservoir parameters were systematically var


stimate well capacity and calculate measure actual flow rates. Decisions for operational control will be made based on the data analysis the
 lateral testing and allocation of production rates to optimize each lateral contribution and the overall commingled well rate. Along with real tim
ertainty across a range of production scenarios. We assess the implementation of an intelligent horizontal well in a thin oil rim reservoir in the
sure region close to the fracture tip). The controlled laboratory experiments showed planar fracture propagation trends as expected from thre
sure region close to the fracture tip). The controlled laboratory experiments showed planar fracture propagation trends as expected from thre
N2 remained under subcritical conditions in all experiments. Alpha Olefin Sulfonate (AOS) surfactant was used as foaming agent. We found
mography (CT) scans are used to visualize and quantify local fluid distributions and differentiate foam propagation in the different layers. Fro
ing and often low cost allowing easily recursive treatments in case of an unsuccessful operation. Foam is resistant to strong and rapid defor
ious situation occurs with a change in geometry downhole when a tapered tubing string is run in a well or when the tubing is set above the pe

 ens when the well shuts in restarts and eventually dies. To address the intrinsically transient multi-phase flow problems a combined study o
velocity string is the increase in frictional pressure drop constraining production. Hence an optimal velocity string has to be selected such tha

cial lifting technology as most artificial lifting technologies work well with liquid but cannot handle free gas. A further challenge is to make the
ervoir IPR. In the paper the behavior of different natural gas wells and of an air-water test setup are analyzed. Simulations were performed u
ca followed by the industry’s approach and progress in the arena. The North American industry is working a variety of deliquification tec
te selection chemical screening laboratory testing operational considerations and the results of the offshore field trials. The results from th
quid loading behavior. We observed the natural ability of the reservoir energy to carry the produced fluids to the surface and then eventually
 lls. At the early stages of production the gas pressure is sufficiently large to lift the water that enters the wellbore. Gas and water mist flow to

 sion compared to the conventional methods that assume the constant tubing pressure for the entire process. The resistance coefficients of t
 t the downward liquid velocity to values less than 0.5 ft/sec to ensure gas/water separation. High steel prices dictate smaller casing strings b
 uent effect of the acid in creating wormholes overcoming damage effects and stimulating productivity. The model tracks the interface betwe

 d for sanding. Even though there are analytical tools available for predicting the initiation of sanding for simple well configurations there are

culating the productivity of a laminated clastic reservoir and we illustrate the method with a field example from Malaysia. A single well predicti
uction. To accomplish this task a 3D full field model was created. First several 1D Mechanical Earth Models (MEMs) were developed. These
 serves the purpose of puncturing through the casing.� This paper presents recent research that looks into the impact of perforating on m
ed method which cleans perforations with more efficiency than conventional static underbalanced perforating method. In addition a passive
  ation pressure and BHT followed by high CO2 H2S production and improper well clean up contributed in the increase of operational risks an
 nosis of these results indicated that the static underbalanced condition and the shaped charges used were not enough to effectively clean th
 rmeability contrast reservoirs at critical flow conditions perforations located in zones with permeability variation between 10 000 and 1 000 m
 o tends to be deeper. Deep-penetration perforating charges are required to perforate past the damaged zone. Experience indicates that und
 ideal since API Section I data are an unreliable predictor of performance into stressed rock but this is the only published data allowing direc
  rig to remove the completion prior to perforating is in many cases not cost effective leading to foregone opportunities to extend production
  rig to remove the completion prior to perforating is in many cases not cost effective leading to foregone opportunities to extend production
 rforating technique utilizes a unique job design process and specific�equipment to ensure the guns are detonated in the correct environm


mising the results of the operation an improvement over traditional tubing-conveyed perforating (TCP) was required. A propellant-assisted (P
servoirs are acid stimulated to maximise productivity.� Complete stimulation of the reservoir section is very difficult to achieve using acid d
servoirs are acid stimulated to maximise productivity.� Complete stimulation of the reservoir section is very difficult to achieve using acid d
 because the mud cake invaded filtrates and particulate pore plugging are progressively removed at the vicinity of the sandface region; (c) t
s paper outlines a solution to these challenges. For a CT perforation campaign in the South China Sea a CT string equipped with fiber optic



 has high operational cost. This paper outlines the successful perforation of horizontal wells in the Niger Delta while addressing the operation
 itions of similar perforators. In this paper we analyze the failure modes of continuously phased perforators for both gas well and oilwell appli

 ere kept constant. For both rock types the reactive liner charges produced perforations with lower productivity than the baseline convention
perforated using large diameter high shot density tubing conveyed (TCP) guns with deep penetrating charges shot underbalanced using the
rder to predict productivity index and to plan the well stimulation program. The wells are completed by gravel packs. Complete mixing of sea
 of scale deposition and the resulting injectivity impairment are calculated for a range of sensitivities including reaction kinetics (ranging fro
sizing to have an accurate estimate of pore pressure the rock's mechanical properties and the minimum in-situ stress in the injection horiz

 ractures. Using the smart completion with the conventional rate testing (the plant's testing facility) required longer time to reach the best poss
  made to develop the field with horizontal openhole gravel packs for both producers and injectors. Fifteen production wells and eleven injecto
mize well interventions while maximizing data gathering an intelligent-well completion using surface-controlled sub-surface variable chokes fo
  y and evaluate integrity of the downhole sand-exclusion installation. Fines production possibly due to a failure of the expandable screens co
 erforated interval during the initial completion program was 310 ft with a maximum perforated interval of 571 ft. The typical production casing
 ed interval during the initial completion program was 310 ft with a maximum perforated interval of 571 ft. The typical production-casing strin
  light (50� API) sweet crude oil. Hawtah field is a mature and depleted reservoir and in order to maintain economical levels of production
 he Petronius project which is operated by Chevron. The field is located in the Gulf of Mexico 150 miles south of Mobile Alabama. The proje

erved drawdown/depletion for horizontal perforations. This benchmarking appears to support the validity of the shear-failure model. This is im
 es of burst tests were conducted on a wire-wrap screen design direct wrapped to 4-in. base pipe. The objective was to determine if the scree
eanup and test-facility to test productivity and evaluate the integrity of the downhole sand-exclusion installation. Fines production possibly ca

allowing unacceptable rates of sand production. The well was worked over and the tubing with eight control lines and a premium-sand-contro
 ll. This condition resulted in the closure of the well for high sand production. To restore production from the well current economic realities f


ge and fluid compatibility testing. To translate the robust design into a fluid system which can be applied effectively in the field a thorough fit

sign. A comprehensive semi-analytical model was developed based on modification of the horizontal well model. The additional pressure dro
nt present an additional constraint – operational pump rates should be high enough to avoid alpha wave sedimentation around the packers

 ion methodology in poorly sorted unconsolidated sands with high fines content in Brunei also indicates that the situation is not much different
ge and fluid compatibility testing. To translate the robust design into a fluid system which can be applied effectively in the field a thorough fit

 andable screens with annular barriers and blanks between each section of sand is the only completion option except in fine sand environme
 g high angle openhole intervals without the need for alternative flow path screens but retaining the advantages of high gravel concentration s
 l characteristics and objectives. To date 14 wells have been equipped with Dual Sting - STMZ completions and five wells have the new Sing
 These goals included not only the production of gas at relatively high rates from the shallow unconsolidated sand-stone reservoir at approx
omplete gravel-pack process and accounts for fluid flow and gravel settling in different flow paths. The presented simulator tracks the fluid flo
 avel packing of the associated wells are thus introduced. A significant level of progress has been made in recent years towards overcoming



  well was very disappointing. A diagnosis study concluded that the severe productivity impairment on these wells was related to either screen
uting the perforation packing job are presented. This study also discusses the current practices commonly employed in cased-hole gravel pa
 ting the perforation packing job are presented. This study also discusses the current practices commonly employed in cased-hole gravel pac
well did not produce any water. A more thorough analysis has been made of the onset of sanding in the X-1 well to understand the benefits
h optimal “structural stability for the given inherent material strength of the formation rock can be achieved by targeting perforations in the

edy be evaluated. One GOM producer engaged the services of a proppant supplier to determine whether a suite of proppants/gravel could
elopment and requirement for artificial lift increase drainage area and improve sweep efficiency. In the early stage of field development a re

 rol and fines migration prevention. The proper candidate selection treatment design treatment execution production management and co-
 rol and fines migration prevention. The proper candidate selection treatment design treatment execution production management and co-


 with disposing of this amount of sand--and the effect the produced solids have on the facilities such as stabilization of emulsions--are a larg
es a mix of all these techniques to meet well objectives. Introduction The South Tapti gas field is located 160 km north north-west of Mumba
 f the completion design based on these estimates. The optimum completion aims to delay the onset of sand to surface for the first 18 years
 ons will be described. Production strategy recommendations to minimize the sand risk during well start-up and ramp-up and also well steady
s proposed to simulate the dominant sanding mechanism. The theoretical model is based on the resolution of the equations of equilibrium a

 ions are proposed. Introduction Perforation cavities are enlarged with sand production. The cavities become contiguous and form larger ca

 sanding issues it was facing which involved prediction prevention monitoring and if required remediation activities. The first step in the S
analysis; (3) perform a series of formation failure and sanding potential analysis for a variety of possible well completion design scenarios us
 on of economic production and overestimates or underestimates of sanding risk increase the chances of serious economical loss. This rais
 on of economic production and overestimates or underestimates of sanding risk increase the chances of serious economical loss. This rais
  the model backed up by the core laboratory test data observations from core inspection and thin section analyses revealed the rocks to b
  the model backed up by the core laboratory test data observations from core inspection and thin section analyses revealed the rocks to b
ious stages of the tests to simulate water cut. The failure and sand-production processes were observed and recorded using a borescope in
ious stages of the tests to simulate water cut. The failure and sand-production processes were observed and recorded using a borescope in
 approach presented here can be used to explain why sanding in the field tends to be episodic and how depletion which is a major factor in
 approach presented here can be used to explain why sanding in the field tends to be episodic and how depletion which is a major factor in

h on the performance of coalbed gas wells and gas compositional shifts during production. Because of the cubic relationship between fractu
nteraction between fluid flow and mechanical deformation of the medium capturing various mechanisms of failure. The model allows capturi
nteraction between fluid flow and mechanical deformation of the medium capturing various mechanisms of failure. The model allows capturi

 the wells. As deepwater and subsea fields mature intervention and surveillance options on subsea wells have to be explored and develope
uid flow and mechanical deformation of the medium in predicting sand production. The model simulated strain softening of the material accom

uid flow and mechanical deformation of the medium in predicting sand production. The model simulated strain softening of the material accom

own at which failure of the formation will start. A further development are models which try to predict the total volume which can be expecte
 d 3) properties of drilling fluid and its interaction with shale formations. The likelihood of wellbore instability and sand production for the deve
 2002 the first obstruction occurred and was identified as CaCO3 resulting in a programme of remediation and treatment as discussed previ
 al wells. Detailed scale predictions have been performed to identify the scaling risk for each producer. From these it was identified that the
e models/methods should be used with caution. The literature hosts many equations to predict the total skin factor in partially perforated vert
 tions and the blockage of the flow by the wellbore itself. Because of the orientation of a horizontal well relative to the anisotropic permeability
ems have been used in Saudi Arabian fields in matrix acid stimulation and in leakoff control acids during acid-fracturing treatments. These s
  h solubility and highly fractured/vugular nature carbonate reservoirs in the Permian Basin show excellent response to acid fracturing treatme
uids—an acid viscosified with polymer an emulsified acid system and an acid viscosified with surfactants—at elevated temperatures of 20
  h solubility and highly fractured/vugular nature carbonate reservoirs in the Permian Basin show excellent response to acid fracturing treatme
  nating stages of polymer pad. These treatments in the vertical wells target several reservoir sub-layers with varying degrees of porosity and
 rnating stages of polymer pad. These treatments in the vertical wells target several reservoir sub-layers with varying degrees of porosity and
because damage to the near-wellbore area and completion should be minimized for optimum production. Laboratory studies and field applica
  diversion including ball-sealer technology and limited-entry perforating to ensure every target zone is contacted and adequately stimulated


lush fluids. Quantifying diversion fluid efficiency and cleanup are important factors for successful candidate selection and job design. Labor

ugh coiled tubing and then with the viscoelastic diverting acid system bullheaded down the production tubing; production logs were acquired


ese organic acid systems were used successfully to acid fracture several wells in a deep gas reservoir in Saudi Arabia. Field data however
ugh coiled tubing and then with the viscoelastic diverting acid system bullheaded down the production tubing; production logs were acquired
 d that much of the rock is weak and potentially prone to deconsolidation after acid stimulation. Weakening of the rock matrix often leads to
 times. This paper discusses the application of a new viscoelastic-surfactant (VES)-based self-diverting acid system for stimulation of more
g Tubing Pickling Bullheading Diversion and Coiled Tubing placement were used. Stimulation of over forty wells utilizing different acid syste

ted optimum acid system placement and diversion techniques need to be applicable in the field in a simple manner without impacting the o
timulation of the formation. Therefore opportunity exists to mix HCl with an organic acid to achieve productivity enhancement by optimizing

core and synthetic core as the three filtering options. The paper also includes step-by-step example calculations of viscosity controlled leakof

sitive skin factors following the fracture treatments irrespective of the fluid system used. In at least one case a well stopped producing after
mechanical or chemical.� Mechanical control of treating fluid placement can be accomplished by coiled tubing with an inflatable packer or
ty of the formation to wellbore fluids the impact of the wettability changes and near wellbore damage is not fully evaluated on all formations a


 atments show that the steady-state gas and condensate relative permeability in both outcrop and reservoir sandstones can be increased by
 resented. Core samples from eight different carbonate rocks were selected for the study. Samples were characterized for mineralogy textu
bore. Due to the low pumping rate stimulation results have been limited. A change was initiated aiming to have the acid pass the damaged z
se i.e. the water cut reduction are the combination of polymer adsorption type (kinetic or equilibrium) with method of application of the resist
nting results and has led to a common misconception that restimulations “don’t work. Production statistics of a well alone may not off

 traditional polymer-based fluid. This VES-CO2 fluid system combines the benefits of viscoelastic surfactant-based fluid—such as low forma
e of previously treated Frontier completions. It has also been determined that oil-based fluids can alter the reservoir wettability and hence cau
 traditional polymer-based fluid. This VES-CO2 fluid system combines the benefits of viscoelastic surfactant-based fluid—such as low forma
her important feature of the integrated solutions is a proper risk assessment based on available data. Often especially in old fields informa
 nique and optimized glycol-alcohol solvent mixture. The chemical treatment alters the wettability of water-wet sandstone to neutral wet and in




 e objective of the present field case study was to place the stimulation fluid equally throughout all intervals of the oil bearing layers while tem
ection of water influx in vertical or deviated multi-zone and/or multi-lateral I-well completions. The source of water influx into the well and the
n will come from complex water flooded reservoirs in an environment of rising operating costs. The injection wells in these fields need to acc
n will come from complex water flooded reservoirs in an environment of rising operating costs. The injection wells in these fields need to acc
 Over time injectors that undergo repeated rapid shut-ins often have significantly reduced injectivity and show evidence of sanding and even
conventional gas-oil systems. In this study we have investigated the performances of SW HW and VW in both single-layer homogenous and
amps one unstable slump zone and one pressure regression on its way to the targeted reservoirs. The evaluation program for the well was
lly and systematically examined by a dedicated team of ZADCO and Schlumberger technical professionals. The criteria used to judge the us
lly and systematically examined by a dedicated team of ZADCO and Schlumberger technical professionals. The criteria used to judge the us
  (BIMA) with a coil-tubing unit on board is used to overcome the limitations due to weather. A combined pumping procedure (coiled tubing a
  how to ensure full coverage of treatments is a recurrent topic of debate several approaches have been discussed in the literature. In the pa
on depths different acid types and volumes have to be used. Acidizing for optimized productivity requires first determining what is desired wo
 h an acceptable ESP failure and run life. So far 41% of the originally installed ESP systems are operating more than 4 years and 20% are o
 ps used at Kuparuk Field is presented. Formation powered jet pumps could be beneficial in other multi-zone oil fields around the world to inc



 outhern Offshore Area of Chevron operations several wells have quit and require some kind of support to flow to surface. Artificial lift (gas lif
 reation of a robust artificial lift selection matrix and charts for various well configurations as well as production rates for optimum well perform
 ion effort and analysis completed to determine the efficiency of the two types of gas lift nozzles used in the completions the methodology for

bes a new technique of artificial lift which uses the concept of venturi to lift the fluid to the surface. A high velocity power fluid is used to create
 iency of advanced long horizontal well completions over that achieved by the equivalent conventional openhole completion. The highest c

 r’s production target would not be met. To meet the production targets a complete well redesign was undertaken. First the tubing was u
are being developed with a reduced number of wells with departures of up to 4 Km @ 1500 m TVD/RKB. The drilling scenario for Carina/Ari


 options. Each reservoir was characterized by history matching drillstem tests (DSTs). Experimental design (ED) reduced the large number o
 f BP’s open-hole gravel pack best practices. The paper details the completion evolution in BP’s offshore Trinidad and Tobago high
 -water zone reserves and the reserves contained in the zones with poor reservoir properties. The use of the horizontal completion allows dev
 ges such as large vertical net pays and high hydrostatic pressures of the sodium formate-based reservoir drill-in fluid and the sodium-potas

g. A control line is connected between sequential valves. When the bottom valve opens the control line becomes pressurized and transfers t
mprise of unconsolidated sands that are thinly distributed. These unconsolidated sands are normally completed using cased hole gravel pack
gged sand face completions which again could also compromise production. When it comes to selecting a sand face completion strategy s
ned so that maximum squeeze life is achieved by forming a low solubility phase in the formation. Addition of Ca2+ Mg2+ and Fe2+ in the pil
 presents an optimization technique for determining the most efficient production tubing string setting depth design that will keep the wellbore
 presents an optimization technique for determining the most efficient production tubing string setting depth design that will keep the wellbore

 onsisting of Geology Petrophysics Geophysics Drilling and Service Company was instrumental in utilizing state-of-the-art 3D seismic inter
 onsisting of Geology Petrophysics Geophysics Drilling and Service Company was instrumental in utilizing state-of-the-art 3D seismic inter

e robustness of the technique was illustrated by its ability to operate effectively in the complex reservoir environment when the signal is pertu
rate and the flowing pressure in real time allowed producing the well optimally. The appraisal and acceptance loop of the completion has be
 onsider a single system comprising the reservoir the completion the measurement and the feedback algorithm that adjusts flow-control de
. Monitoring the rate and the flowing pressure in real time allowed for optimal well production. The appraisal and acceptance portions of the
ed regularly using real-time measurements and production tests and we discuss the impact of different smart-well instrumentation levels on

ned well configurations. Production performance in both systems has been compared using numerical and physical model. Results have pr
 they are applied in core flooding tests to reduce liquid saturation and also to increase the gas effective saturation in a porous media. The o

   or expandable screens) were used the result would likely have been early water breakthrough and well abandonment.�The authors wi
 ical predictions. DESPs gave improved oil production and recovery in reservoirs with strong aquifer support and became progressively more

ee such as in the wellhead) and/or flow constrictions - were identified as: the tree; a landing nipple profile near the surface; and a formation is
ng the completion process of a well certain operations are performed to enable the well to produce by creating an unobstructed flow path for
f levels of each factor into nonempty subsets of statistically similar response) so that an acceptable degree of parsimony is achieved. Essen
oxyethylcellulose (HEC) polymer. Correlations have been developed for rheological parameters of aqueous- and polymer-based drilling foam

skin and non-Darcy effect. Additionally the model could handle non-uniform flux non-uniform skin distribution and selective completion with
e quest to increase the effective half-length of the fracture and enhance production led to the search for novel effective technologies capable
hydraulic fracture treatment was performed resulting in a 200% production increase. Over the past three years a stimulation program has ev
hydraulic fracture treatment was performed resulting in a 200% production increase. Over the past three years a stimulation program has ev
ments become increasingly more difficult to place as porosity decreases and this problem is primarily attributed to higher natural fracture/fis

primary goal was to be able to create a more even distribution of proppant in the created fracture while reducing the polymer requirement for
height-growth control (HGC). The Yaraynerskoe oilfield case study documents the fiber assisted fracturing fluid technology used with HGC m
get several reservoir sub-layers with varying degrees of porosity and permeability contrast. These layers are often divided by lithological strea
ns.� In addition to reducing damage with lower polymer concentrations other advantages of degradable fiber usage were anticipated to b
 viated wells using minimum viscosity fluids and minimum amount of pad with limited proppant sand concentration resulted in low net pressu
croemulsion two water-wetting flowback additives and an oil-wetting additive. Careful laboratory testing was done to look at surface tension
 . The fracture height calculated based on uniform modulus versus layered modulus under the same in situ stress contrast conditions is com

 BHTP + Pfric – Phyd …………………….. (1) Ps = surface pressure BHTP = bottomhole treating pressure Pfrict = friction pressure P
additives in fracture fluids and minimizing disposal costs of produced waters by recycling and by using them as the base for completion and
duced water. The importance of flowback water analysis is highlighted for optimizing fluid performance downhole. Recent developments in p
bility. These methods are generally oversimplified as they neglect the phase change and variation of relative permeability with interfacial tens
to calibrate and constrain appropriate fracture evaluation models (P3D and 3D).� Rate-transient production analysis techniques together
ng the upper intervals. This novel technique is particularly useful for wells with water-producing zones near the bottom of the target zone bec
 fracture half-length in order to improve the fracture treatment and the increasingly difficult task of simultaneously controlling fracture height g
 to successful completion of a fractured horizontal well. We discuss these factors in relation to both longitudinal and transverse fracture appli
  wells with long openhole intervals (see Fig. 1). This paper illustrates a case history where an innovative technique was used on stimulating
art makes it difficult to reach the best results by means of a unique fracture. Within the optimization process that is followed in the developm
ovides self-diversion from water to oil bearing formations. At the same time this same fluid can be used on long intervals to divert matrix st
 sumed in the completion operations extends over weeks making wells uneconomical. In addition the prolonged time over which the frac flui

hese wells require stimulation to regain their productivity but the available choices to achieve effective stimulation in horizontal open hole com


wells: gas wells oil wells producing above the bubblepoint and oil wells producing below the bubblepoint. For each category the authors des



wells: gas wells oil wells producing above the bubblepoint and oil wells producing below the bubblepoint. For each category the authors des
wells: gas wells oil wells producing above the bubblepoint and oil wells producing below the bubblepoint. For each category the authors des
 ddition the water bearing sand posed a risk to successful execution; the fracture had to be contained within the zone of interest. High Pressu
hape factors for use in improved hydraulic fracture stimulation design and evaluation.� Example applications of the dimensionless product

 red and planned stimulation campaigns in the Volga-Urals basin. This paper presents a summary of the knowledge gained in Samara fields

  This piston squeezes a C-ring and makes the ID smaller. At the end of the fracture treatment to the lower valve a dart is dropped during the
 ar the wellbore with sliding sleeve. FEA was used to adjust valve parameters that increased tensile stress in the cement and formation. Uns
n a quasielastic medium. The medium resistance to fracture development is determined by variable apparent fracture toughness which is a f
  fluid are presented along with three high-permeability case histories.�The estimated reservoir permeabilities were as high as 167 mD an

cessfully applied in the Morrow Sands in Eddy County of SENM.� Fracture geometry analysis using surface treating pressures radio-activ
 d. Studies have been conducted of fracture fluid clean-up which indicate that fluid clean-up or more importantly the lack of fluid clean-up is a



OP. The option of acid fracturing was evaluated and found to be feasible to alleviate the problems. The paper details an optimization workflo
e encounters significant yield stress when the filter cake cumulative thickness dominates the width of the fracture. The new results presente
e encounters significant yield stress when the filter cake cumulative thickness dominates the width of the fracture. The new results presente




e encounters significant yield stress when the filter cake cumulative thickness dominates the width of the fracture. The new results presente
½ The evaluation tools utilized to determine the resultant fracture attributes include microseismic hydraulic fracture monitoring hydraulic fract

ences may appear along the receiver array. These traveltime discrepancies may then be misinterpreted as an effect of TI anisotropy and us
 and wells are stimulated in multiple fracture stages. Each fracture stage may target three to six sands with eight to twelve total stages for ea

gn an optimized fracture treatment it is imperative that numerous factors be understood including proppant embedment formation spalling
er acidizing. The profilometer measures the distance to the rock surface with a laser device that measures distance with an accuracy of 0.00
 sonic logging. Unfortunately in West Siberia at depth of 2500-3000 meters there is negligible tectonic and open hole sonic dipole did not pr
 adioactive tagging additive is incorporated into the resin coating of the proppant. This non-hazardous environmentally safe coated proppan

have either been shut-in or are on intermittent production. Factors may include low reservoir quality reservoir pressure and specific produc
ant Type of proppant Thus apparent proppant permeability will vary with distance from the wellbore increasing towards the tip of the fra
 behavior in high permeability formations. We consider a steadily propagating fracture taking into account the flow within the fracture filtrate
post flowback) from these wells could not clearly distinguish between the benefits obtained from the viscoelastic diverting acid versus the in-s
given set of reservoir parameters and job sizes and on optimization of the flow rate and cumulative production. We discuss the reasons for a

 eismic approach in the absence of an offset observation well; and (2) characterize fracture height azimuth length and symmetry with respe
effectiveness of hydraulic-fracture stimulations is critical for optimal economic production of tight gas. Deformation associated with fracturing

nt flowback. The model is based on treating both the proppant pack and the reservoir as poroelastoplastic media. It allows for solid productio
sults show that a refracture treatment can undergo three distinct periods of fracture growth: ����Period I: Dominant orthogonal fr
 luence of pressure differential. The quality of fracture cleanup determines in the long run the effectiveness of oil recovery measures. Fracturi

ng and adequately supported by other logs (ultra-sonic cement evaluation) to infer the change in anisotropy; the latter anisotropy includes the
ss the experimental set-up and some of the artifacts that had to be removed prior to ensuring more reliable data.�The results highlight th



owever the injection rate was decreased with increase in pressure and skin factor was found to be increased. Another observation was that
mature fields an accurate evaluation of the hydraulic fracturing operations is vital to enhance the effectiveness of the fracturing treatments a
ction pressure are made for several offset angles and lengths. Large increases in net pressure and associated increases in overall fracture v
nt treatments in 663 perforated intervals. It was found that the absolute total production per interval is similar for all assets; however the draw
 e interaction of capillary viscous and inertial forces within highly conductive propped fractures is yet unknown. In this work we report a serie
 stimulate lower-performing wells of the field. Several options were considered for this purpose from mechanically-diverted acid squeeze to p
w injection rates of 15-25 BPM. This paper describes the practices of massive annular fracturing treatments down the 5-1/2 by 2-3/8 annulus
a significant part of the project economics. It is well known that the deliverability of gas-condensate wells can be impaired by the formation of
controls the gas fraction in a well by changing its wellhead choke or inflow control valve (ICV) settings on a realistic test case. We introduce
  a rigorous analysis or solution of the wells’ production from a gas lift perspective. This paper presents the basic theory behind auto ga
 f BP’s open-hole gravel pack best practices. The paper details the completion evolution in BP’s offshore Trinidad and Tobago high
 udied through visualization experiments. It was observed that blockage happened because of size exclusion. Also the blockage was accele

etting state is varied by the treatment with a fluorochemical compound. Then the effect of wettability on the high-velocity coefficient in two-ph
 he limestone with retarded emulsified hydrochloric acid and ball sealers. This paper describes a new and different approach which involves
 o overcome the low vertical permeability. Undulation in wellbore trajectory will change the inflow distribution along the wellbore and therefor
erence in injectivity between horizontal and conventional vertical injectors with time. It was concluded that the key to operating horizontal well
ages required can be very time consuming with added expense of removing the frac plugs with coiled tubing after the operations have been
ages required can be very time consuming with added expense of removing the frac plugs with coiled tubing after the operations have been
ermeability is ranging between 0.1 and 5 millidarcies (mD) An engineered oil-based mud was used as drill-in fluid to prevent any damage to
ermeability is ranging between 0.1 and 5 millidarcies (mD) An engineered oil-based mud was used as drill-in fluid to prevent any damage to
 completions and could be applied broadly in other situations. Using these three criteria other major North Slope reservoirs were evaluated to
mpletion. Introduction Brunei Shell Petroleum (BSP) is a keen implementer of wells with sophisticated trajectories for achieving maximum re
wns. Confirmed by the actual data the cold restart simulations found the warm-up time in the wellbore to be less than an hour. The actual da
ves the pair of krg and krc and minimized the effect of skin rate dependent. Flow-after-flow tests of 6DD+1BU have done in gas condensate



modeling) and for flow profiling using a measured temperature profile (inverse problem). The model has successfully been applied for invest

 that can control and measure water flow and gas flow with no changes in hardware was critical for the success of this installation. The comb
rall commingled well rate. Along with real time monitoring sustainability of well rate will be extended by timely reacting to any changes to res
 in a complex deepwater turbidite environment. Many of the reservoirs are highly faulted and compartmentalized due to salt movement and
ring techniques. An ICD is a choking device installed as part of the sandface completion hardware. It aims to balance the horizontal well’
ese hydrocarbons are lost and cannot be drained subsequently. This paper covers the design and application of new open hole sand face c
  new technology. ICV(s) can balance the fluid-front provided they are placed correctly. A typical example would be their installation across z
rsible Pumps play a key role in producing from oil wells that are incapable of producing naturally at commercially viable rates. ESPs are com
  parameters were systematically varied. The interaction between the aquifer and reservoir was observed when producing these reservoirs w


 ade based on the data analysis the results of which will be used to optimize overall field performance and maximize financial returns. In this
mmingled well rate. Along with real time monitoring sustainability of well rate will be extended by timely reacting to any changes to reservoir a
al well in a thin oil rim reservoir in the presence of reservoir uncertainty and evaluate the benefit of using two completions in conjunction with
agation trends as expected from three-dimensional modeling. Introduction Since the inception of the hydraulic fracturing technique as a me
agation trends as expected from three-dimensional modeling. Introduction Since the inception of the hydraulic fracturing technique as a me
 s used as foaming agent. We found that injection of gas following a slug of surfactant can considerably reduce gas mobility and promote hig
 opagation in the different layers. From both the model and the experiments we conclude that foam is primarily generated in the high-permea
 is resistant to strong and rapid deformations encountered in porous media and in some cases to the contact with hydrocarbons.1 Foam is a
 r when the tubing is set above the perforations. In these instances a more robust evaluation results from using conditions at the bottom of th

 e flow problems a combined study of completion inflow analysis and wellbore dynamic simulation was performed. The analysis indicates th
 ity string has to be selected such that liquid loading is delayed over a long period with a minimal impact on production. This requires accurate

 as. A further challenge is to make the existing onshore technologies fit for use in environments that require the use of a SSSV (offshore). Th
alyzed. Simulations were performed using both commercially available software and dedicated dynamic models. The onset of liquid loading a
working a variety of deliquification technologies for “challenging gas with developments ranging from adapting existing oil-field technologi
shore field trials. The results from the first trials were above expectations. One cycling well was able to be kept online five times longer than
 s to the surface and then eventually declining production with increasing liquid accumulation. Second we performed a sensitivity analysis o
wellbore. Gas and water mist flow to the surface where the water content is easily separated from gas using separation equipment. As the p

cess. The resistance coefficients of the plunge motion in four different phases are determined by combining the dynamic model with field tes
rices dictate smaller casing strings be used where possible to enhance project economics in operations such as coalbed methane. However
The model tracks the interface between the acid and the completion fluid in the wellbore models transient flow in the reservoir during acid in

simple well configurations there are very few models that are capable of predicting cavity stability or cavity growth for general field applicatio

  from Malaysia. A single well predictive model incorporates logs rock and PVT data and formation tests to build a flow simulation model at t
 dels (MEMs) were developed. These 1D MEMs were calibrated using drilling data laboratory measurements well tests and other field meas
 s into the impact of perforating on matrix acid stimulation.� Large scaled single-shot perforating tests were conducted using real shaped c
 ating method. In addition a passive gun-orienting system was used to optimize the perforating process and enhance the well’s performa
 n the increase of operational risks and challenges. Several failures reported in the past was carefully analyzed to determine the actual root c
ere not enough to effectively clean the perforation tunnel and surpass the near wellbore damaged zone. Dynamic underbalanced perforating
ariation between 10 000 and 1 000 mD have the same maximum injection rate. If the wells from Peace River perform similar to the Imperial
 zone. Experience indicates that underbalance perforation provides better productivity compared to overbalance perforation. Although conve
he only published data allowing direct comparison between systems. The tool calculates depth of fluid invasion stress-corrected penetration
ne opportunities to extend production by perforating new intervals or reperforating existing producing zones. With casingless completions ev
ne opportunities to extend production by perforating new intervals or reperforating existing producing zones. With casingless completions ev
re detonated in the correct environment to create�a dynamic underbalance immediately after perforating. Laboratory tests show how this


 as required. A propellant-assisted (PA) perforating method that could optimize well productivity while maintaining stringent health safety and
s very difficult to achieve using acid diversion techniques in a karstic environment due to the large variability in the permeability. �Propellan
s very difficult to achieve using acid diversion techniques in a karstic environment due to the large variability in the permeability. �Propellan
e vicinity of the sandface region; (c) the crashed layer of the perforation tunnels is cleaned up. The existing pressure transient analysis metho
a CT string equipped with fiber optic cable inside was used coupled with a bottomhole assembly capable of measuring both bottomhole tem



Delta while addressing the operational issues encountered. The first case history is Addax ORW-11H a horizontal well planned to have the
ors for both gas well and oilwell applications. Important factors concerning carrier serviceability are discussed. A method based on energy co

ductivity than the baseline conventional charge. The reduction in the normalized Productivity Ratio (PRn) ranged from 29% to 66%. Furtherm
 arges shot underbalanced using the classic “shoot and pull technique. After shooting before the guns are pulled the well is killed. Perfo
ravel packs. Complete mixing of sea- and formation waters in production well neighbourhoods in the reservoir under consideration was assu
cluding reaction kinetics (ranging from minimum to maximum values as obtained from coreflood and field data) fraction of produced water
m in-situ stress in the injection horizon.�This collective information can be used to estimate the required injection pressure and the numb

ed longer time to reach the best possible setting for the downhole flow control valves to achieve the optimum flow rate. Using the combinatio
 n production wells and eleven injector wells were drilled and completed in the field. As a result of the perceived technical complexity of the d
rolled sub-surface variable chokes for internal gas-lift and surface controlled sub-surface fixed chokes was proposed. Another design challe
 failure of the expandable screens commenced almost immediately upon well bean-up and steadily increased to the extent that the well was
 571 ft. The typical production casing string for the wells consists of 10-3/4 in. casing with an 8-1/16 in. production liner. Drift diameter throug
 . The typical production-casing string for the wells consists of 10 3/4-in. casing with an 8 1/16-in. production liner. Drift diameter through the
ntain economical levels of production a combination of several technologies is being applied. Due to the poor natural production from the ver
 south of Mobile Alabama. The project was sanctioned in August of 1996 after both compliant-tower and subsea-development options were

of the shear-failure model. This is important because the model while fairly simple has many different inputs including depth profiles for un
bjective was to determine if the screen could withstand at least 4 600 psi without damage. The wire-wrap design selected to improve the pre
 llation. Fines production possibly caused by a failure of the expandable screens steadily increased to the extent that the well was deemed u

 trol lines and a premium-sand-control screen with shunt tubes were retrieved/fished from the well with minimal problems. The retrieved scre
  the well current economic realities favored through tubing intervention. Two major types of through tubing remedial sand control solutions w


effectively in the field a thorough fit for purpose QA/QC system for all drilling and completion fluids was developed requiring extensive fluid

ell model. The additional pressure drop is added to consider the mechanical skin and non-Darcy flow in the near-wellbore zones of drilling da
ve sedimentation around the packers to assure sealing after the packer inflation process. Traditionally design criteria consider a minimum cr

hat the situation is not much different from above demanding to lower production drawdowns while delivering production quotas.� The low
effectively in the field a thorough fit for purpose QA/QC system for all drilling and completion fluids was developed requiring extensive fluid

option except in fine sand environment. In this paper we present experimental data of shale stabilizer treated-brine and three open-hole gra
ntages of high gravel concentration slurries. This is supported by 2 field case histories from a field in India where two gas wells were drilled
ons and five wells have the new Single String-STMZ technology. These 19 wells embody 77 frac packs / gravel packs. The average comple
 ated sand-stone reservoir at approximately 1000 m TVD but also minimization of impact to the environment. To minimize cost and still acc
 resented simulator tracks the fluid flow and gravel concentration from the wellhead down through the workstring crossover ports open-hole
  in recent years towards overcoming the challenges through new developments in fluids application tools and techniques. These developm



ese wells was related to either screen plugging by mud particles while running the screens to bottom in the NAOBM and/or the plugging induc
 ly employed in cased-hole gravel packing to pack perforation tunnels and the potential limitations of these practices. Incomplete packing of
 y employed in cased-hole gravel packing to pack perforation tunnels and the potential limitations of these practices. Incomplete packing of p
  X-1 well to understand the benefits of oriented perforations and to benchmark the sand prediction against field observation. The method e
 ieved by targeting perforations in the most stable direction with respect to the in-situ stress field. For high angle wells this normally equates t

er a suite of proppants/gravel could be developed that could be uniquely identified and placed in each completion interval. In the event of pro
early stage of field development a reservoir failure was observed. A documented investigation indicated that the failure mode appeared to be

on production management and co-ordination of all services are essential to the success of the screenless completion. In this paper the co
on production management and co-ordination of all services are essential to the success of the screenless completion. In this paper the co


stabilization of emulsions--are a large cost to operations. A program was initiated in 2002 to evaluate the effectiveness of the completions in
d 160 km north north-west of Mumbai in the Arabian Sea off the west coast of India. The field is operated by a joint venture between BG Exp
sand to surface for the first 18 years of production whilst maintaining high gas productivity (>300mmscf/d/well). The selection of contingency
up and ramp-up and also well steady-state production will be given. This paper will provide an overview of the behavior of both sand control
tion of the equations of equilibrium at the interface between the intact zone and the slurry made of eroded sand and oil. An algorithm in 2-D

come contiguous and form larger cavities around a cased hole. Finally they form irregular cavities as shown in Fig.1. � Fig.1 Cavity grow

ation activities. The first step in the SMS was to obtain a clear understanding of the cause and the mechanism for the sand production. This k
 well completion design scenarios using 3-D finite element technique for rock structure coupled with well production and fluid flow simulation.
of serious economical loss. This raises the question of how accurate and reliable sanding predictions might be achieved without overcomplic
of serious economical loss. This raises the question of how accurate and reliable sanding predictions might be achieved without overcomplic
ion analyses revealed the rocks to be extremely hard and strong and therefore highly unlikely to sand. These findings contradicted with initi
ion analyses revealed the rocks to be extremely hard and strong and therefore highly unlikely to sand. These findings contradicted with initi
d and recorded using a borescope in real time. The results showed that the effect of water cut on perforation strength and sand production d
d and recorded using a borescope in real time. The results showed that the effect of water cut on perforation strength and sand production d
 depletion which is a major factor in rock breakup can be highly effective in holding broken-up sand grains together and in fact become a s
 depletion which is a major factor in rock breakup can be highly effective in holding broken-up sand grains together and in fact become a s

the cubic relationship between fracture permeability and fracture aperture width (and thus fracture porosity) for a given cleat permeability the
s of failure. The model allows capturing the episodic nature of sanding and the resulting changes in the geometry and formation consistency
s of failure. The model allows capturing the episodic nature of sanding and the resulting changes in the geometry and formation consistency

ls have to be explored and developed. Several operational challenges were faced during the planning and execution of this operation due to
strain softening of the material accompanied with shear-bands formation as well as tensile failure. In the post-disaggregation phase addition

 strain softening of the material accompanied with shear-bands formation as well as tensile failure. In the post-disaggregation phase addition

e total volume which can be expected to be produced by assessing the geometrical extend of the failed zone. These volumetric estimates
 ity and sand production for the development wells was assessed using in-house developed wellbore stability and sand production prediction
on and treatment as discussed previously in SPE 94865.�In late 2004 however zinc and lead sulphide scale deposits were also identified
From these it was identified that the major risk to well performance and integrity was CaCO3 precipitation in the upper tubing with potential fa
 skin factor in partially perforated vertical wells. Some of the available models have been tested against the results from the 3D semianalytica
 elative to the anisotropic permeability field perforation skin models for vertical wells that consider these effects notably the Karakas and Tar
g acid-fracturing treatments. These surfactants were used to provide diversion during acidizing of vertical long horizontal and multilateral we
nt response to acid fracturing treatments. However inadequate diversion can leave substantial portions of the reservoir untreated. Different a
nts—at elevated temperatures of 200�F and 275�F. The acid fracture conductivity apparatus is similar to a standard API fracture cond
nt response to acid fracturing treatments. However inadequate diversion can leave substantial portions of the reservoir untreated. Different a
  with varying degrees of porosity and permeability contrast. These layers are often divided by anhydrite or dolomitic streaks that make vertica
s with varying degrees of porosity and permeability contrast. These layers are often divided by anhydrite or dolomitic streaks that make vertic
 . Laboratory studies and field applications have demonstrated the nondamaging properties of a VES fluid. This paper reviews the properties
 ontacted and adequately stimulated (Alastair et al. 1999). At present the demand for stimulation vessels is extremely high because of the le


date selection and job design. Laboratory tests defining these key factors are presented in this paper. This paper demonstrates the diverting

ubing; production logs were acquired after each treatment.       The results from comparison of pre- and post-job production logs clearly show


n Saudi Arabia. Field data however indicated that there is a need to create deeper and more-conductive fractures. To achieve this goal it w
ubing; production logs were acquired after each treatment. The results from comparison of pre- and post-job production logs clearly show
 ing of the rock matrix often leads to borehole instability and loss of wellbore integrity at the anticipated drawdown required to meet completi
g acid system for stimulation of more than 20 horizontal openhole wells in carbonate reservoirs in Kuwait. The application also deployed a ne
orty wells utilizing different acid systems and procedures resulted in noticeably different production gains. The short and long term results are

mple manner without impacting the overall treatment logistics. The use of a hydrochloric acid system containing a viscoelastic surfactant sys
ductivity enhancement by optimizing the wormhole penetration and profile. Organic acids that are utilized in stimulating carbonate formations

ulations of viscosity controlled leakoff coefficient and wall building coefficient. Introduction Filtration control of stimulation and gravel pack flu

 case a well stopped producing after being treated. A core study revealed that despite the relatively low clay content in the formation the crit
ed tubing with an inflatable packer or with conventional straddle packers or ball sealers.� Although mechanical techniques are very effecti
not fully evaluated on all formations and fields. It is though evident that the volumes of wellbore fluids lost to the reservoir impact final produc


oir sandstones can be increased by a factor of 2 to 3 over a wide range of temperature (145 to 275��F). Spectroscopic data show that
e characterized for mineralogy texture fabric porosity and density distribution using Nuclear Magnetic Resonance (NMR) Computed Tomo
o have the acid pass the damaged zone and generate wormholes through effective diversions. This paper describes the application of acid/
 th method of application of the resistance factors (threshold or variable) resistance factor ratio reservoir fluid properties and reservoir layou
  statistics of a well alone may not offer an effective restimulation candidate selection methodology. Other parameters such as high BHP (rem

tant-based fluid—such as low formation damage superior proppant transport and low friction pressures—with carbon dioxide advantages
he reservoir wettability and hence cause formation damage. With this in mind and considering the environmental and economical benefits of
tant-based fluid—such as low formation damage superior proppant transport and low friction pressures—with carbon dioxide advantages
 ften especially in old fields information is out of date limited or unavailable. Combining together available pieces of information through th
 r-wet sandstone to neutral wet and increases the gas relative permeability. The increase in gas relative permeability was quantified by comp




als of the oil bearing layers while temporary protect the zones suspected to be mainly contributing with water from the stimulation fluid using
e of water influx into the well and the zonal fluid contribution will be quantified allowing this unwanted fluid's production to be reduced. Knowl
ction wells in these fields need to accept in some cases up to 65 000 barrels water per day. The use of DHFC reduces the number of injecti
ction wells in these fields need to accept in some cases up to 65 000 barrels water per day. The use of DHFC reduces the number of injecti
  show evidence of sanding and even failure of the down-hole completion5. It is therefore critical to understand the nature of water hammer in
 in both single-layer homogenous and layered gas-condensate reservoirs. ECLIPSE 300 compositional reservoir simulator which includes ou
  evaluation program for the well was solely logging-while-drilling (LWD)-based and included structural dip and azimuth from density and gam
als. The criteria used to judge the usefulness of these logs was the present or not of communication behind casing as determined by the phy
als. The criteria used to judge the usefulness of these logs was the present or not of communication behind casing as determined by the phy
d pumping procedure (coiled tubing and bull-heading) was implemented to best-fit individual well condition. Close cooperation among differe
n discussed in the literature. In the particular case of N’Kossa this issue was not only rendered difficult by the length of the perforated int
  s first determining what is desired wormhole pattern. Currently the numerical models focus on computer rendered wormholing pattern by pr
 ing more than 4 years and 20% are operating in the range of 3-4 years run life. The cumulative average run life of operating ESPs is 2.7 yea
zone oil fields around the world to increase oil production rate while reducing water production rate and lifting costs. Introduction Kuparuk Fi



 to flow to surface. Artificial lift (gas lift) has been identified as the best method to optimize production from the wells reviewed in this case. Ho
uction rates for optimum well performance. This approach has a significant impact on gas well production; often loaded up with liquid and pre
the completions the methodology for optimization of SAGD gas lift systems and recommendations for future improvement. Background Sur

  velocity power fluid is used to create drawdown at the throat of a surface venturi and this pressure drawdown is transmitted downhole by pre
 openhole completion. The highest cleanup efficiency is predicted to be achieved by an intelligent completion employing both sensors and IC

as undertaken. First the tubing was upsized from 7 in. to 9-5/8 in. Then semi-openhole completions with pre-drilled liners and openhole pack
B. The drilling scenario for Carina/Aries phase 1 included two horizontal wells to be drilled from the platform CARINA-1 (85 m water depth) an


 gn (ED) reduced the large number of simulation runs to a manageable few for probabilistic forecasting. Comparison of three options sugges
s offshore Trinidad and Tobago high rate gas fields and the relative performance of these completion types from sand control and well produ
  the horizontal completion allows development of the reserves which would have never been possible to produce with vertical wells because
 ir drill-in fluid and the sodium-potassium formate completion brine. Compared with other alternatives such as cased hole gravel-pack or fra

becomes pressurized and transfers the bore pressure to a piston in the valve immediately above. This piston squeezes a Cring and makes t
pleted using cased hole gravel pack. In order to select optimal completions it required both identification and estimation of the radial extent
g a sand face completion strategy several operators have a number of concerns. This paper examines sand control options (barefoot stand
n of Ca2+ Mg2+ and Fe2+ in the pill solution at 0.1 to 1 molar ratios significantly improves the retention of phosphonate. Alternatively these
pth design that will keep the wellbore continuously unloaded of produced liquids yet result in the maximum gas recovery possible under thos
pth design that will keep the wellbore continuously unloaded of produced liquids yet result in the maximum gas recovery possible under thos

zing state-of-the-art 3D seismic interpretation LWD resistivity at bit real-time imaging and distance to boundary measurements to place this
zing state-of-the-art 3D seismic interpretation LWD resistivity at bit real-time imaging and distance to boundary measurements to place this

environment when the signal is perturbed by outliers or by random noise levels up to the control error limits. The value of these control error l
ptance loop of the completion has been closed by having this well completed put on production and tested. Approval of the concept was ach
algorithm that adjusts flow-control devices with quantitative models for each of the components. Both pressure and flow-rate control systems
aisal and acceptance portions of the completion process were achieved when this well was completed put on production and tested. The co
 smart-well instrumentation levels on the updating process. We simulated the performance of this production-optimization strategy in a reser

and physical model. Results have proven that the dual-lateral well configuration accelerates the oil recovery by 90% in the early stage of pro
e saturation in a porous media. The offered results can be interpreted as a preliminary sight about the use of these treatments on lab scale b

ell abandonment.�The authors will highlight the inflow control device selection process integrated completion and reservoir analysis wel
port and became progressively more attractive in a layered-reservoir scenario as the pressure difference between the production zones incre

e near the surface; and a formation isolation device (FID) positioned in the gravel pack assembly. The key parameters were defined as partic
 reating an unobstructed flow path for the oil and lifting it to the surface. This process is intended to realize actual production that measures u
gree of parsimony is achieved. Essential definitions necessary for preliminary data structure are also covered. We demonstrate the practical
ous- and polymer-based drilling foams. On the basis of the experimental results of foam rheology and a steady-state momentum balance eq

bution and selective completion with blank pipes. Both oil well and gas wells are evaluated. For gas wells the standard pseudo-functions ar
 novel effective technologies capable of achieving this goal. One such technology is the solid acid system which was field tested for the first
  years a stimulation program has evolved with improvements in candidate selection performance and predictability. Future plans include co
  years a stimulation program has evolved with improvements in candidate selection performance and predictability. Future plans include co
ttributed to higher natural fracture/fissure density in the lower-porosity higher-modulus zones. Production data indicate that these natural fra

 educing the polymer requirement for the fracturing gel slurry. A secondary goal was to use slugs of the fiber to bridge at the fracture entry fac
ng fluid technology used with HGC materials as a significant improvement in HGC solution. This technology combination additionally enhance
  are often divided by lithological streaks that make vertical communication challenging. Hence in many instances acid fracturing ends up ove
able fiber usage were anticipated to be proven after proppant fractures geometries and production parameters (including PI and Jd) evaluatio
 centration resulted in low net pressure build up. These challenges were prevailed over by the application of a new fiber technology in which
  was done to look at surface tension and contact angle for each flowback aid using the recommended concentrations. Imbibition and drainag
situ stress contrast conditions is compared. The results are analyzed and explained based on fracture mechanics fundamentals as well as

 g pressure Pfrict = friction pressure Phyd = hydrostatic pressure The equation shows that an increase in hydrostatic pressure results in a re
hem as the base for completion and fracturing fluids. Because of the uncertainty of the produced water impurity composition and concentra
downhole. Recent developments in proper selection of fluid additives and viscosifiers for slickwater and crosslinked fluids are discussed. We
  tive permeability with interfacial tension (IFT) and velocity for these low IFT systems. They also require data that are not readily available in
 uction analysis techniques together with statistical data techniques were incorporated to evaluate stimulation techniques (proppant & fluid vo
  ar the bottom of the target zone because it induces selective growth of the fracture along the upper intervals and mitigates the risk of growin
 aneously controlling fracture height growth. In addition to the risk of the post-frac increase in water-cut the uncontrolled fracture height grow
 itudinal and transverse fracture applications. Success factors include the optimum perforation process overcoming fluid flow convergence to
e technique was used on stimulating a naturally completed horizontal well that experienced a production drop to zero shortly after the comple
 cess that is followed in the development of this field the implementation of a strategy of selective stimulation through the pumping of two hy
    on long intervals to divert matrix stimulation treatments from stimulated to un-stimulated intervals or from high permeability intervals to low
  olonged time over which the frac fluid remains in the formation before being flowed back often affects well productivity. This paper describe

 imulation in horizontal open hole completions have traditionally been limited at best. Previous stimulation attempts with coiled tubing have yie


 t. For each category the authors describe the significance of non-Darcy and multiphase flow effects by use of the fracture-flow theory and st



 t. For each category the authors describe the significance of non-Darcy and multiphase flow effects by use of the fracture-flow theory and st
 t. For each category the authors describe the significance of non-Darcy and multiphase flow effects by use of the fracture-flow theory and st
thin the zone of interest. High Pressure and high temperature operations posed additional challenges that had to be addressed. For Fracture
cations of the dimensionless productivity index and pseudosteady state shape factor solutions developed in this work are provided for fractur

e knowledge gained in Samara fields of the Volga-Urals basin with emphasis on the results obtained and highlighting the differences with the

 er valve a dart is dropped during the flushing operation. This dart lands on the C-ring and seals the bore inside the sliding sleeve. Pressure
ss in the cement and formation. Unstressed cement tests were then conducted on a variety of sliding sleeve valve shapes to verify the FEA
arent fracture toughness which is a function of the fracture length and is found from the analysis of energy dissipation in the plastic zone. Th
 eabilities were as high as 167 mD and reservoir heights ranged from 30 -90 feet.�In all cases the entire propped fracture design was suc

 urface treating pressures radio-active tracers and production data showed height growth containment and longer effective fracture half-leng
 ortantly the lack of fluid clean-up is a primary cause of ineffective or less than desired fracture length. This ineffective clean-up is believed to



 paper details an optimization workflow and integrated evaluation process that improve the treatment performance. Detailed fluid system use
e fracture. The new results presented here demonstrate successful strategies that mitigate the effects of excessive filter cake thickness. Exp
e fracture. The new results presented here demonstrate successful strategies that mitigate the effects of excessive filter cake thickness. Exp




e fracture. The new results presented here demonstrate successful strategies that mitigate the effects of excessive filter cake thickness. Exp
 ic fracture monitoring hydraulic fracture surface treating pressure-history matching and tracer and production log interpretation in addition to

 as an effect of TI anisotropy and use of such an anisotropic model may lead to the mislocation of the detected fracture(s).� The uncertai
with eight to twelve total stages for each well. The study shows mapping results for fracture treatments in both mapping areas. Fracture leng

pant embedment formation spalling temperature degradation conductivity loss over time non-Darcy flow multiphase flow non-uniform pro
 es distance with an accuracy of 0.001 in. The rock sample is mounted on a servo-table that automatically moves the sample in selectable in
and open hole sonic dipole did not provide obvious fracture orientation. Fracture height growth affect mostly fracture job size and cost. Heigh
nvironmentally safe coated proppant can be transported and applied without any of the restrictions associated with radioactive tracers. Once

servoir pressure and specific production conditions. A reliable methodology for selection of candidate wells for stimulation treatments was c
e increasing towards the tip of the fracture where liquid ratio and velocity are lower. This variation of permeability was explicitly modeled in
nt the flow within the fracture filtrate leak-off across the fracture faces and kinetics of filter cake growth. The flow within the reservoir due to
oelastic diverting acid versus the in-situ gelled acid.1 However the wells treated with viscoelastic surfactant based acid did clean out in a sho
uction. We discuss the reasons for and alternatives to conductivity impairment within the fracture; fracture cleanup width changes conducti

 uth length and symmetry with respect to rock properties. Hydraulic fracture stimulations to date at SR have encompassed limited entry “
 formation associated with fracturing results in small-magnitude microearthquakes that can be used to image the stimulated fracture network

 ic media. It allows for solid production from the proppant pack but also from the formation itself in case the fracture was created in a very we
½ï¿½Period I: Dominant orthogonal fracture propagation. It exhibits a rapid pressure increase due to the stress increase at the tip of the ortho
 ss of oil recovery measures. Fracturing fluid being left entrapped in the fracture decreases its effective oil collecting area. Thus stability and q

 opy; the latter anisotropy includes the creation of a propped width. While the methodology has been used in carbonates very few cases of its
  able data.�The results highlight the crucial role played by the filter cake and present new data that would significantly change the commo



eased. Another observation was that the formation was not fractured at pressures exceeding the expected closure stress. Possible explanat
veness of the fracturing treatments and improve the production results. Multiple hydraulic fracturing operations were evaluated in five differen
 ciated increases in overall fracture volume are shown which can result in increased treatment costs slower fracture growth and shorter ove
milar for all assets; however the drawdown applied in 1 asset is 4 times lower than the other assets. The performance of the wells in most as
known. In this work we report a series of steady state gas-condensate relative permeability values for a proppant filled and a sand packed fr
chanically-diverted acid squeeze to propped hydraulic-fracturing or acid-fracturing this later option being ultimately selected. However the rat
ents down the 5-1/2 by 2-3/8 annulus used at the Bajiaochang Gas Field Sichuan Basin China as a substitute to fracturing down casing an
s can be impaired by the formation of a condensate bank once the bottomhole pressure drops below the dewpoint. This paper outlines the fiv
n a realistic test case. We introduce a strategy to find an optimal production set point for this controller and the benefits of using downhole IC
ents the basic theory behind auto gas lift and how to apply it. The components of the theory are well known and commonly used in nodal ana
s offshore Trinidad and Tobago high rate gas fields and the relative performance of these completion types from sand control and well produ
usion. Also the blockage was accelerated due to droplets coalescence as a result of high shear rate or surfactant adsorption on the porous m

 he high-velocity coefficient in two-phase flow is investigated. Results show that when the liquid is strongly wetting the high-velocity coefficien
nd different approach which involves leaving drains in openhole condition and using a slow acting stimulation treatment for damage remova
 tion along the wellbore and therefore change the wellbore performance. When two-phase flow is involved especially gas-liquid flow the pre
at the key to operating horizontal wells is achieving and maintaining fractures in multiple locations and limiting fracture growth in the better qu
 bing after the operations have been completed. When drilling a horizontal well there are two preferred completion options. First the horizon
 bing after the operations have been completed. When drilling a horizontal well there are two preferred completion options. First the horizon
 rill-in fluid to prevent any damage to the reservoir. A carbonate particle-based filtercake was used to create a thin and reliable filter cake. Wh
 rill-in fluid to prevent any damage to the reservoir. A carbonate particle-based filtercake was used to create a thin and reliable filter cake. Wh
 th Slope reservoirs were evaluated to determine their potential for horizontal-openhole-completion applications. Focus areas in this evaluatio
 rajectories for achieving maximum reservoir exposure. The aim is to drain oil from stacked sand bodies that cannot be produced economica
  be less than an hour. The actual data also show the cumulative water cut one hour after restart was found to be below 50%. The cold restar
 +1BU have done in gas condensate wells in the Monagas Field Venezuela. The results have shown that the wells in this field produce unde



  successfully been applied for investigating key thermal characteristics of single-phase- and multiphase-fluid flow along a wellbore. In particu

 uccess of this installation. The combination of downhole chokes and flowmeters allows full control and monitoring of zonal injection rates an
 imely reacting to any changes to reservoir and well conditions. Using variable positions flow control valve early water breakthrough can be
entalized due to salt movement and several extend beneath salt structures and are difficult to image. Permanent downhole pressure and tem
ms to balance the horizontal well’s inflow profile and minimize the annular flow at the cost of a limited extra pressure drop. Fractured an
 cation of new open hole sand face completion architectures equipped with Inflow Control Device technology (first in Ecuador) in Block 15. Th
 e would be their installation across zones showing early water or gas break-though. This allows “Value being “Added to the reservo
mercially viable rates. ESPs are commonly used in wells which cannot lift the oil to surface due to low reservoir pressure high water cut and
 d when producing these reservoirs with a horizontal IW using a range of “Reactive and “Proactive choking policies. An example of


 nd maximize financial returns. In this study a strategy was developed to maximize Agbami’s full-field rate capacity in three production p
 eacting to any changes to reservoir and well conditions. Using variable-position flow control valves early water breakthrough can be delayed
g two completions in conjunction with surface and downhole monitoring. Three control strategies are tested. The first is a simple passive app
ydraulic fracturing technique as a means to improve productivity of oil and gas wells the hydraulic fracturing community has determined certa
ydraulic fracturing technique as a means to improve productivity of oil and gas wells the hydraulic fracturing community has determined certa
 reduce gas mobility and promote higher liquid recovery at the experimental conditions investigated. Foaming of CO2 builds-up a lower press
  marily generated in the high-permeability layers where it propagates at a much higher speed than in the low permeability layer. The propaga
 ontact with hydrocarbons.1 Foam is also an excellent mobility control agent that has been widely used to improve sweep efficiency in miscibl
m using conditions at the bottom of the well and the downhole tubing geometry. Other conditions exist where the use of downhole conditions p

performed. The analysis indicates that the well’s productivity had been substantially reduced. Before shut-in the surface pipeline system
 on production. This requires accurate methods to predict pressure drop in the velocity string as well as tubing-velocity string annulus. The av

uire the use of a SSSV (offshore). This paper addresses the phenomenon of liquid loading and presents various technologies that are curre
models. The onset of liquid loading and the dynamic behavior of a flooded well during a restart were predicted. These were then compared to
  adapting existing oil-field technologies to developing gas-specific technologies to “on the horizon technologies. Examples in each stage
be kept online five times longer than under normal operating circumstances while for another well its time online more than doubled. These
 we performed a sensitivity analysis of the well's energy (i.e. siphon or velocity tubing strings) versus adding energy to the well (i.e. gas lift inje
 sing separation equipment. As the production of the well continues the reservoir pressure drops to the point where water can no longer be l

ning the dynamic model with field test data. An example is given to illustrate the dynamic performance of plunger lift and the optimal design.
 such as coalbed methane. However smaller pipe sizes result in higher flow velocities for a corresponding surface flow rate. These higher flo
ent flow in the reservoir during acid injection considers frictional effects in the tubulars and predicts the depth of penetration of acid as a func

vity growth for general field applications. This paper introduces results from a fully-coupled geomechanical/reservoir simulator GMRS� wh

s to build a flow simulation model at the resolution of the petrophysical analysis. By calibrating the high resolution flow model with dynamic te
ments well tests and other field measurements. The calibrated rock mechanical properties from the 1D MEMs were distributed in the 3D mod
  were conducted using real shaped charges to perforate carbonate core samples under downhole conditions.� Acid was then injected into
 and enhance the well’s performance. The new technique was applied in 2003 to horizontal Well-1 which was drilled by in the Tadrart sa
 alyzed to determine the actual root cause prior to coming up with the proper job design and operational procedures. CTU with 1.5 CT reel w
  Dynamic underbalanced perforating coupled with high performance charges was selected as the technology that would improve productivity
 River perform similar to the Imperial D-36 HWCSS LEP wells from Cold Lake then the expected gross production performance that these w
 balance perforation. Although conventional underbalance perforation can be performed using pipe-conveyed or tubing-conveyed perforation
 nvasion stress-corrected penetration and crushed zone properties at log resolution.� An inflow profile and IPR curves are then generated
nes. With casingless completions even this option is not available. A downhole orienting and imaging platform has the unique capability to o
nes. With casingless completions even this option is not available. A downhole orienting and imaging platform has the unique capability to o
 ing. Laboratory tests show how this fast acting dynamic underbalance created across the perforated interval is used to clean�perforation


aintaining stringent health safety and environmental standards was proposed. The propellant-assisted perforating method uses standard per
ility in the permeability. �Propellant-assisted perforating was considered as it achieves effective stimulation diversion equally across the en
ility in the permeability. �Propellant-assisted perforating was considered as it achieves effective stimulation diversion equally across the en
ng pressure transient analysis methods to determine the skin were almost exclusively developed with an assumption that the skin factor rem
e of measuring both bottomhole temperature internal and external CT pressure and in addition casing collar locator. The primary objective



a horizontal well planned to have the lateral section slimmed down to 6 in. hole. After successfully drilling the hole to target depth (TD) a 6-in
ussed. A method based on energy conservation is used to establish a swell model to predict the post-detonation conditions of the perforator.

 ranged from 29% to 66%. Furthermore the reactive liner charges produced characteristic “dynamic overbalance conditions in the wellbo
ns are pulled the well is killed. Perforation and kill related damage severely impacts these wells leading to high skin and rapid production dec
ervoir under consideration was assumed in previous works. Using this assumption quasi steady state model for reactive flow around produc
ld data) fraction of produced water in the injected mixture and barium concentration in produced/re-injected water. The theoretical param
ired injection pressure and the number of injectors throughout the production period. In addition well planning and design will also benefit f

 mum flow rate. Using the combination of smart completion and portable MPFM (Multiphase Flow Meter) resulted in reducing the water cut (W
erceived technical complexity of the development and requirement to maximize completion efficiency the operator chose to maximize the in
was proposed. Another design challenge was that conventional wire-wrapped screens would have insufficent clearance to accommodate inte
 eased to the extent that the well was deemed unproducible to the facilities.� The failure of the first well caused a re-evaluation of the sand
 production liner. Drift diameter through the tapered production casing is 9-1/2 in. and 6-1/2 in. respectively. The 6-1/2 in. drift diameter allows
ction liner. Drift diameter through the tapered production casing is 9 1/2 and 6 1/2 in. respectively. The 6 1/2-in. drift diameter allows using co
  poor natural production from the vertical cased and perforated completions in Hawtah and little associated gas electrical submersible pump
d subsea-development options were evaluated. The compliant-tower alternative was selected because of its greater well-intervention capabil

 nputs including depth profiles for unconfined compressive strength (UCS) and in-situ stresses which involve sophisticated prediction techni
 p design selected to improve the pressure rating was substantially heavier than what has been used in traditional sand-control completions.
he extent that the well was deemed unproducible to the facilities.    A re-evaluation of the sand-exclusion method that included more extensiv

minimal problems. The retrieved screens had collapsed around the perforated base pipe. The well was reperforated new screens run and a
ing remedial sand control solutions were considered namely mechanical and screen-less (chemical consolidation) methods. A proprietary HD


 developed requiring extensive fluids testing and reporting at the well site. The paper describes in detail the reservoir completion philosophy

he near-wellbore zones of drilling damage mud-cake gravel packs and the sand screen. This investigation indicates that the non-Darcy eff
esign criteria consider a minimum critical velocity to avoid sand deposition. The specification of minimum flow for cleaning the ECP and pre

 ering production quotas.� The lower drawdown extends the integrity of sand control completion jewelry reduces water influx fines migrat
 developed requiring extensive fluids testing and reporting at the well site. The paper describes in detail the reservoir completion philosophy

reated-brine and three open-hole gravel packing case histories from one UGS field in Italy. In the three case studies the wells were gravel pa
 ia where two gas wells were drilled with an oil-based drill-in fluid and gravel packed with a viscous water-based fluid. The packing mechanis
  gravel packs. The average completion time has been 11.3 rig days/well for DS-STMZ wells. SS-STMZ completions have averaged of 22.2
ment. To minimize cost and still accomplish the project goals the wells were drilled from a single platform. Introduction Project Challeng
orkstring crossover ports open-hole and screen-washpipe annuli and then back to the surface through the washpipe and casing-workstring
 ols and techniques. These developments have resulted in successful gravel packing of wells drilled with oil-based (OB) fluids which have y



he NAOBM and/or the plugging induced by a mixture of formation sand mud and filter cake when draw-down was applied during cleanups.
se practices. Incomplete packing of perforation tunnels is mostly encountered in gravel-pack jobs completed with brine as the carrier fluid (w
 e practices. Incomplete packing of perforation tunnels is mostly encountered in gravel-pack jobs completed with brine as the carrier fluid (w
ainst field observation. The method estimated sand strength from logs in the X-1 well. A correlation between log-predicted UCS and lab-me
h angle wells this normally equates to shooting in the vertical plane through the well path. Over a decade of production experience with this t

ompletion interval. In the event of proppant production to surface (mechanical failure) the surface samples would be analyzed to directly det
 that the failure mode appeared to be wormhole-like failure2. To date there have been several failures with similar characteristics occurred in

 ess completion. In this paper the common sequence of events for a screenless completion is presented as well as the key technologies inv
 ess completion. In this paper the common sequence of events for a screenless completion is presented as well as the key technologies inv


 e effectiveness of the completions in the Duri field. This effort involved evaluated field data such as the frequency and type of workovers th
d by a joint venture between BG Exploration & Production India Limited (BGEPIL) ONGC and Reliance Industries Limited (RIL). In 2002 BG
 /d/well). The selection of contingency sandface completions is also discussed along with mitigation measures in the event of unexpected san
  of the behavior of both sand control techniques after 5 years of production and injection. An in depth analysis of the different productivity/inje
ded sand and oil. An algorithm in 2-D was developed and implemented in a finite element code. Two calculations are alternatively performed

own in Fig.1. � Fig.1 Cavity growth during sand production To model the sand flow each cavity must be meshed as shown in Fig.2 requ

anism for the sand production. This knowledge was required because attempts to run new completion designs without knowing the cause of
 production and fluid flow simulation.� The types of completion design analyzed include cased hole completion using conventional perfora
ght be achieved without overcomplicating the analyses and without requiring complex lab and field data that in most instances will be unav
ght be achieved without overcomplicating the analyses and without requiring complex lab and field data that in most instances will be unav
These findings contradicted with initial impression and previous expectation on this sandstone that it should have been sand-prone formation
These findings contradicted with initial impression and previous expectation on this sandstone that it should have been sand-prone formation
ation strength and sand production depends on the mineralogical composition of the sandstone and the degree of residual water saturation.
ation strength and sand production depends on the mineralogical composition of the sandstone and the degree of residual water saturation.
ains together and in fact become a sand-stabilizing agent.� The proposed approach is used in discussing sanding at several wells in two
ains together and in fact become a sand-stabilizing agent.� The proposed approach is used in discussing sanding at several wells in two

 ity) for a given cleat permeability the production profile of coal seams varies depending on whether the permeability is distributed among clo
geometry and formation consistency and behavior within the sand impacted regions. Sand detachment is simulated by removal of the elemen
geometry and formation consistency and behavior within the sand impacted regions. Sand detachment is simulated by removal of the elemen

nd execution of this operation due to the sand prone nature of the wells combined with the subsea environment. They were carefully assesse
e post-disaggregation phase additional features were considered including allowing for the removal of the disaggregated elements that have

e post-disaggregation phase additional features were considered including allowing for the removal of the disaggregated elements that have

 d zone. These volumetric estimates of sand production are often based on rock mechanical models which predict the extent of a yielded zo
 bility and sand production prediction tools. Mud weight stability profiles showing the variation of lower and upper bound mud weights with de
 e scale deposits were also identified.�These had not been predicted during the initial scaling studies.�This resulted in the well being s
 n in the upper tubing with potential failure of the downhole safety valve. The risk varied from negligible to severe and reflected the variable c
 he results from the 3D semianalytical model. It has been shown that total skin-factor equations based on the summation of individual compo
 effects notably the Karakas and Tariq model (1991) are not directly applicable to perforated horizontal completions. Using appropriate varia
 l long horizontal and multilateral wells. They were used in sour environments where hydrogen sulfide levels reached nearly 10 mol%. They
 of the reservoir untreated. Different acid systems have been developed to counter the problems in acid fracture stimulations. Chemical and m
milar to a standard API fracture conductivity cell but with a capacity to hold core samples that are 3 in. long in the leakoff direction. The long
 of the reservoir untreated. Different acid systems have been developed to counter the problems in acid fracture stimulations. Chemical and m
or dolomitic streaks that make vertical communication within the reservoir challenging. Hence acid fracturing ends up stimulating the highest
 or dolomitic streaks that make vertical communication within the reservoir challenging. Hence acid fracturing ends up stimulating the highest
 d. This paper reviews the properties of the vesicular-type VES diverting fluid reviews the operational considerations and presents several c
s is extremely high because of the level of new well-development and general stimulation activity in the North Sea sector. This demand coup


his paper demonstrates the diverting ability of the acid as a function of permeability characterized by introducing the concept of maximum p

ost-job production logs clearly show a change in the production profile after the stimulation with the viscoelastic diverting acid system with a


e fractures. To achieve this goal it was decided to conduct a field trial with a newly developed acid system. The new acid system is an ester
ost-job production logs clearly show a change in the production profile after the stimulation with the viscoelastic diverting acid system with a
drawdown required to meet completion objectives. The two exploratory wells in this study were cased with a perforation density of about 5
t. The application also deployed a new nonparticulate material that forms a highly viscous plug when it contacts water and that degrades whe
. The short and long term results are correlated with the stimulation procedures and practices. The present paper describes a comparison of

ntaining a viscoelastic surfactant system that allows upon acid spending the development of viscosity in situ has shown that significant skin
d in stimulating carbonate formations include formic acetic and more recently citric and lactic. Selecting a suitable organic acid for a specifi

trol of stimulation and gravel pack fluids is key for the appropriate fluid design and engineering. Failure to optimize fluid loss can lead to prem

 clay content in the formation the critical velocity was less than one cc/min. Moreover the retained matrix permeability after performing a stat
echanical techniques are very effective they are more expensive and time consuming than chemical techniques and they are often not appli
st to the reservoir impact final productivity. It equally affects the possibility to flow the well back after stimulation treatment. Hydraulic fracturin


¿½F). Spectroscopic data show that the sandstone surface remains modified by the chemical even after flooding the core with large volume
Resonance (NMR) Computed Tomography (CT) scanning Scanning Electron Microscopy (SEM) mercury injection as well as resistivity mea
per describes the application of acid/diversion systems and pumping schedules to improve acid coverage. The selection of in-situ crosslinked
 r fluid properties and reservoir layout. On the other hand the polymer viscosifying effect is not such an influencing factor and neither are the
er parameters such as high BHP (remaining reservoir energy) recoverable reserves f-h1 and favorable response to original fracture jobs (IP

s—with carbon dioxide advantages of enhanced cleanup and better hydrostatic pressure. This fluid was recently selected for the fracturing
nmental and economical benefits of using a water-based fracturing fluid a novel visco-elastic surfactant based CO2-compatible high foam
s—with carbon dioxide advantages of enhanced cleanup and better hydrostatic pressure. This fluid was recently selected for the fracturing
able pieces of information through the structured process helps put together the “big picture which subsequently provides the support fo
 permeability was quantified by comparing the gas relative permeabilities before and after treatment. Improvements in the gas relative perme




 ater from the stimulation fluid using two different types of viscoelastic surfactant (VES) polymer free diversion systems placed with coiled tu
id's production to be reduced. Knowledge of the influx time and source permits both production optimisation and improved reservoir sweep e
 DHFC reduces the number of injection wells by using one wellbore to enable conformed injection into multiple intervals. This eliminates the
 DHFC reduces the number of injection wells by using one wellbore to enable conformed injection into multiple intervals. This eliminates the
rstand the nature of water hammer including the magnitude frequency and energy dissipation. To study the water hammer in water injector
 eservoir simulator which includes our in-house relative permeability (kr) correlation accounting for the coupling (increase in kr by an increas
ip and azimuth from density and gamma imaging sensors and formation pressures and gradients from an LWD formation tester tool. Real-tim
hind casing as determined by the physical test. For the twenty-eight wells examined twenty-five of the cement log interpretations matched th
hind casing as determined by the physical test. For the twenty-eight wells examined twenty-five of the cement log interpretations matched th
on. Close cooperation among different parties (Well services
 ult by the length of the perforated intervals (up to 1200m) but also
  r rendered wormholing pattern by pre-selected acid formulation and volume f
  run life of operating ESPs is 2.7 years and that o
 lifting costs. Introduction Kuparuk Field (Fig.1) is the second largest oil field lo



m the wells reviewed in this case. However the in
 n; often loaded up with liquid and prematurely
uture improvement. Background Surmont an in-situ oil sands pro

wdown is transmitted downhole by pressure
 etion employing both sensors and ICVs. The well’s full production

 pre-drilled liners and openhole packers were selected instead of the conv
orm CARINA-1 (85 m water depth) and two horizontal wells from the platform ARIES


 Comparison of three options suggested that all of them nearly produced
pes from sand control and well productivity standpoints. Characteristics of bp Trinidad & Tobag
 o produce with vertical wells because of poor economics. Another cru
 uch as cased hole gravel-pack or frac-pack completions the openhol

 iston squeezes a Cring and makes the ID smaller. At the end of the fracture
 n and estimation of the radial extent of the near-wellbore mech
 sand control options (barefoot standalone pre-drilled liner / screens or slotted
n of phosphonate. Alternatively these metal ions can be dissolved from
um gas recovery possible under those conditions.�
um gas recovery possible under those conditions.�

boundary measurements to place this first MRC w
boundary measurements to place this first MRC w

 its. The value of these control error limits must be increased as the step
 ed. Approval of the concept was achieved when the anticipated benefits were reali
 essure and flow-rate control systems are discussed. Downhole contro
put on production and tested. The concept was approved when the anticipated bene
uction-optimization strategy in a reservoir simulator. Some numerical aspects of

very by 90% in the early stage of production compared to the horizontal well. Thu
se of these treatments on lab scale before applying them as

ompletion and reservoir analysis well completion operat
e between the production zones increased. However while DESPs had no significant advant

ey parameters were defined as particles of sharp sand with a d
ze actual production that measures up to the forecasted potential of the we
 ered. We demonstrate the practical utility of this methodology on a c
  steady-state momentum balance equation a foam-flow hydraulics model was develope

lls the standard pseudo-functions are used. Detailed discussion
m which was field tested for the first time in the world in a Saudi Aramco
predictability. Future plans include continuing to stimulate candidate well
predictability. Future plans include continuing to stimulate candidate well
n data indicate that these natural fractures or fissures do not me

 iber to bridge at the fracture entry face and divert the treatmen
ogy combination additionally enhances fracture placement succes
 nstances acid fracturing ends up over-stimulating the hig
meters (including PI and Jd) evaluation. Analyses of the fracturing trea
 n of a new fiber technology in which fiber is used (1) to transport high
 oncentrations. Imbibition and drainage tests were done which
 mechanics fundamentals as well as the coupled fluid pressure effect in hydraulic

n hydrostatic pressure results in a reduction in surface pressure. Th
mpurity composition and concentration it is extremely challen
crosslinked fluids are discussed. We will describe in detail ho
 data that are not readily available in particular the pressure profile (the two-ph
 lation techniques (proppant & fluid volumes) and to validate the diff
ervals and mitigates the risk of growing the fracture into the water-pr
 he uncontrolled fracture height growth into the water zone
overcoming fluid flow convergence towards the wellbore in case
  drop to zero shortly after the completion in 2004 due t
 ation through the pumping of two hydraulic fractures directed
 rom high permeability intervals to low permeability
  ell productivity. This paper describes the experience of three operators in Latin

 n attempts with coiled tubing have yielded modest improvements ma


 use of the fracture-flow theory and state-of-the-art fracture-production



use of the fracture-flow theory and state-of-the-art fracture-production
use of the fracture-flow theory and state-of-the-art fracture-production
at had to be addressed. For Fracture containment Schlumberger’s Sonic Scanner tool
d in this work are provided for fracture stimulation design.� A produ

 d highlighting the differences with the Western Siberian approach to hy

e inside the sliding sleeve. Pressure is then increased until the next
leeve valve shapes to verify the FEA study and to selec
gy dissipation in the plastic zone. The dependence of the apparent
tire propped fracture design was successfully pl

and longer effective fracture half-lengths.� Results also indicated successful stimulation past
his ineffective clean-up is believed to res



 rformance. Detailed fluid system used in the treatment is discussed i
 f excessive filter cake thickness. Experimental dat
 f excessive filter cake thickness. Experimental dat




 f excessive filter cake thickness. Experimental dat
duction log interpretation in addition to production analysis.� The resul

 etected fracture(s).� The uncertainty of the relative positions between t
 n both mapping areas. Fracture length was longer than expected and va

ow multiphase flow non-uniform proppant distribution cycl
 ly moves the sample in selectable increments
ostly fracture job size and cost. Height growth has also
ociated with radioactive tracers. Once the proppant is placed in

wells for stimulation treatments was clearly needed.
permeability was explicitly modeled in t
 . The flow within the reservoir due to leak-of
 tant based acid did clean out in a shorter period of time. The ma
ure cleanup width changes conductivity degradation with

have encompassed limited entry “waterfrac treatment techniques. The
mage the stimulated fracture network. Microseismic

 he fracture was created in a very weak reservoir formation. Acc
 stress increase at the tip of the orthogonal
oil collecting area. Thus stability and quality of displacem

d in carbonates very few cases of its application in t
ould significantly change the common industry pra



ed closure stress. Possible explanations for such b
 ations were evaluated in five different boreholes providing a di
ower fracture growth and shorter overall fracture length develo
e performance of the wells in most assets dropped st
 proppant filled and a sand packed fracture with
ultimately selected. However the rather adverse conditions exi
bstitute to fracturing down casing and subsequent snubbing operations. Three t
 dewpoint. This paper outlines the five steps—appropriate l
 nd the benefits of using downhole ICVs in comparison to the wellhead
 wn and commonly used in nodal analysis and conven
pes from sand control and well productivity standpoints. Characteristics of bp Trinidad & Tobag
surfactant adsorption on the porous medium. Furthermore emulsion droplet s

 ly wetting the high-velocity coefficient increases
ulation treatment for damage removal an
ed especially gas-liquid flow the pressure distribution in
miting fracture growth in the better quality
 completion options. First the horizontal section can be completed
 completion options. First the horizontal section can be completed
 ate a thin and reliable filter cake. While drilling this well
 ate a thin and reliable filter cake. While drilling this well
cations. Focus areas in this evaluation include in-situ reservoi
  that cannot be produced economically via separate dedicated wells. Thes
und to be below 50%. The cold restart procedures have been updated with the strategy
at the wells in this field produce under the Non-Darcy flow



-fluid flow along a wellbore. In particular the dependence

 monitoring of zonal injection rates and has proved to be a valuable t
ve early water breakthrough can be delayed to increase
ermanent downhole pressure and temperature sensors have been installed in all Na
 d extra pressure drop. Fractured and more hetero
 logy (first in Ecuador) in Block 15. The design and well preparation p
alue being “Added to the reservoir management process by
 servoir pressure high water cut and high back pressure
 ve choking policies. An example of successful “Proactive Control is when t


  ld rate capacity in three production phases; ramp-up pl
 y water breakthrough can be delayed to increase rec
 ted. The first is a simple passive approach using a fixed contro
 ring community has determined certain containment mecha
 ring community has determined certain containment mecha
ming of CO2 builds-up a lower pressure drop over the core at both low and high
e low permeability layer. The propagation of foam in the low permeability lay
o improve sweep efficiency in miscible gas steam and surfactant-based EOR.2 An
here the use of downhole conditions provide a better evaluatio

e shut-in the surface pipeline system induced unstable production
 ubing-velocity string annulus. The available meth

s various technologies that are curren
dicted. These were then compared to actual production da
echnologies. Examples in each stage of the development process will be shown. The e
me online more than doubled. These results we
ing energy to the well (i.e. gas lift injection
point where water can no longer be lifted to the surface by gas flow. Th

f plunger lift and the optimal design. The principle and approach
ng surface flow rate. These higher flow velocities reduce separat
depth of penetration of acid as a function of the acid v

 al/reservoir simulator GMRS� which predicts cavity geome

esolution flow model with dynamic test data from a
MEMs were distributed in the 3D model using Gaussian sequential simulati
 tions.� Acid was then injected into the perforations to create wormhol
 which was drilled by in the Tadrart sandstone formation of the Berkine
 procedures. CTU with 1.5 CT reel was used to convey 14
ology that would improve productivity in the challenging wells of Santa Ana. This tec
production performance that these wells will have under LEP conditions wi
veyed or tubing-conveyed perforation (TCP) depth uncertainties and the time req
e and IPR curves are then generated.� The analysis can be
 atform has the unique capability to orient guns along
 atform has the unique capability to orient guns along
erval is used to clean�perforation tunnels and produce low to zero damage perforatio


 erforating method uses standard perforating components and procedures thus
ulation diversion equally across the entire perf
ulation diversion equally across the entire perf
n assumption that the skin factor remains constant during a te
 collar locator. The primary objective of the job was to ensure that the



g the hole to target depth (TD) a 6-in. h
tonation conditions of the perforator. The model takes

  overbalance conditions in the wellbore in a system configuration whic
 to high skin and rapid production decline. The challenge in this f
model for reactive flow around production well is formulated. We obtained va
 ected water. The theoretical parameter of the size of
 anning and design will also benefit from predictions conc

   resulted in reducing the water cut (WC) form 20% to 0% maintaining t
he operator chose to maximize the integration of the services by bund
 icent clearance to accommodate intelligent-well completions. A feasibilit
ell caused a re-evaluation of the sand exclusion method employed which inclu
ely. The 6-1/2 in. drift diameter allows using common size screen
6 1/2-in. drift diameter allows using common-sized screens and p
 ted gas electrical submersible pumps (ESPs) have been used in Hawtah to enhan
of its greater well-intervention capability less-complex seawater-injection-system desi

nvolve sophisticated prediction techniques themselves. Continuous sand rate
 raditional sand-control completions. Initial burst tests with availab
n method that included more extensive core analysis and the types of wells

eperforated new screens run and a second frac pack pumped. When laying down
solidation) methods. A proprietary HDR squeeze pack technique (mechanical method)


il the reservoir completion philosophy drilling and c

ation indicates that the non-Darcy effect could significantly affect the product
m flow for cleaning the ECP and prevent the deposition of sand in the annular

ry reduces water influx fines migration and increases recovery factors
il the reservoir completion philosophy drilling and c

case studies the wells were gravel packed using shale stabilizer
 r-based fluid. The packing mechanisms and efficienci
  completions have averaged of 22.2 rig days/well inclusive of NPT and the upper completi
 orm. Introduction Project Challenges.�The Carina field contains a cons
 the washpipe and casing-workstring annulus. In the open-hole section flow th
h oil-based (OB) fluids which have yielded well productivi



-down was applied during cleanups. Based on collaborative laboratory work between the
leted with brine as the carrier fluid (water packs). The proposed
eted with brine as the carrier fluid (water packs). The proposed t
ween log-predicted UCS and lab-measured thick-walled cylinder strength (T
e of production experience with this technique on the

 les would be analyzed to directly determine which interval had fai
with similar characteristics occurred in Stag field. Water i

 d as well as the key technologies involved from perforating to p
 d as well as the key technologies involved from perforating to p


  frequency and type of workovers the amount and size of produc
  Industries Limited (RIL). In 2002 BGEPIL acquired the interests of Enron
  sures in the event of unexpected sand production. The impact
nalysis of the different productivity/injectivity characteristics suc
 lculations are alternatively performed: one on the intact zone (

st be meshed as shown in Fig.2 requiring 100-500 meshes aro

esigns without knowing the cause of the sand and understanding the risks had been pro
ompletion using conventional perforations or s
 that in most instances will be unavailable or the acquisition of which will incur
 that in most instances will be unavailable or the acquisition of which will incur
ould have been sand-prone formation. Facing these appa
ould have been sand-prone formation. Facing these appa
 degree of residual water saturation. The effect is most significant for sandstones
 degree of residual water saturation. The effect is most significant for sandstones
ssing sanding at several wells in two different fields.� These wells have been
ssing sanding at several wells in two different fields.� These wells have been

permeability is distributed among closely spaced fractures (cle
s simulated by removal of the elements that are deemed to
s simulated by removal of the elements that are deemed to

onment. They were carefully assessed and the risks were effectively m
he disaggregated elements that have satisfied the sanding criteria and conseq

he disaggregated elements that have satisfied the sanding criteria and conseq

 hich predict the extent of a yielded zone using various con
 nd upper bound mud weights with depth were developed for typi
s.�This resulted in the well being shut in and the squeeze treatments de
 o severe and reflected the variable composition of the produced wa
 n the summation of individual components do not work.� The 3D semianal
 completions. Using appropriate variable transformations
evels reached nearly 10 mol%. They were also utili
 fracture stimulations. Chemical and mechanica
ong in the leakoff direction. The long c
 fracture stimulations. Chemical and mechanica
uring ends up stimulating the highest reservoir qu
uring ends up stimulating the highest reservoir q
onsiderations and presents several case histories with VES diverting
North Sea sector. This demand coupled with a reduction in t


 roducing the concept of maximum pressure ratio (dP max /dP 0

oelastic diverting acid system with a significant increase i


m. The new acid system is an ester of an organic acid in the form of soli
oelastic diverting acid system with a significant increase i
with a perforation density of about 5 shots per foot (spf) over relati
ontacts water and that degrades when mixed with oil in the
ent paper describes a comparison of procedures and produc

n situ has shown that significant skin reductions can be obtained provided
g a suitable organic acid for a specific acidizing

o optimize fluid loss can lead to premature scre

x permeability after performing a static leakoff test
chniques and they are often not applicable or not effective in we
 ulation treatment. Hydraulic fracturing t


r flooding the core with large volumes of gas. A relative permeability model
ury injection as well as resistivity measurements chemical testing etc.� Eac
e. The selection of in-situ crosslinked and particulate diverters through lab
 nfluencing factor and neither are the she
 response to original fracture jobs (IP) could play an equally important r

 s recently selected for the fracturing treatments on three wells. Initial prod
  based CO2-compatible high foam quality (>60%) fluid was propo
 s recently selected for the fracturing treatments on three wells. Initial prod
  subsequently provides the support for engineering decisio
 provements in the gas relative permeability by a factor of about 2 were




 ersion systems placed with coiled tubing (CT) prov
 tion and improved reservoir sweep efficiency; proc
multiple intervals. This eliminates the need for injection wells de
multiple intervals. This eliminates the need for injection wells de
 y the water hammer in water injectors a field trial was conducted to rec
 oupling (increase in kr by an increase in velocity and interfacial
an LWD formation tester tool. Real-time formation press
ement log interpretations matched the communication test results. One well which c
ement log interpretations matched the communication test results. One well which c

				
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