cop_spe_papers by 4Fw8addN

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									  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
CONOCO           SPE   112130       Corporate Process
CONOCO           SPE   113933           EOR/IOR
CONOCO           SPE   102352        Flow Assurance
CONOCO           SPE   116593        Flow Assurance
CONOCO           SPE   115672        Flow Assurance
CONOCO           SPE   100065           Heavy Oil
CONOCO           SPE   112638           Heavy Oil
CONOCO           SPE   113173           Heavy Oil
CONOCO           SPE   117792           Heavy Oil
CONOCO           SPE   117571           Heavy OIl
CONOCO           SPE   105392           Heavy Oil
CONOCO           SPE   104119             HP/HT
CONOCO           SPE   116583   Low Permeability Reservoirs
CONOCO           SPE   110542      Reservoir Description
CONOCO           SPE   109971      Reservoir Description
CONOCO           SPE   110340      Reservoir Description
CONOCO           SPE   103803      Reservoir Description
CONOCO           SPE   115045      Reservoir Description
CONOCO          IPTC    11813      Reservoir Description
CONOCO           SPE   103083      Reservoir Description
CONOCO           SPE   100307      Reservoir Description
CONOCO           SPE   101556     Reservoir Development
CONOCO          IPTC    11115     Reservoir Management
CONOCO           SPE   117433     Reservoir Management
CONOCO           SPE   102439     Reservoir Management
CONOCO           SPE   100984     Reservoir Management
CONOCO           SPE   117434       Reservoir Modelling
CONOCO           SPE   118722       Reservoir Modelling
CONOCO           SPE   118752       Reservoir Modelling
CONOCO           SPE   119029       Reservoir Modelling
CONOCO           SPE   109867       Reservoir Modelling
CONOCO           SPE   103670       Reservoir Modelling
CONOCO           SPE    90009       Reservoir Modelling
CONOCO           SPE   116292       Reservoir Modelling
CONOCO           SPE   113474     Reservoir Performance
CONOCO           SPE   110132     Reservoir Performance
CONOCO           SPE   108699     Reservoir Performance
CONOCO           SPE   100607       State of the Nation
CONOCO           SPE   103775       State of the Nation
CONOCO           SPE   115753          Surveillence
CONOCO           SPE   117244    Unconventional Reservoirs
CONOCO           SPE   114995    Unconventional Reservoirs
CONOCO           SPE   114778    Unconventional Reservoirs
CONOCO           SPE   107705    Unconventional Reservoirs
CONOCO           SPE   114169    Unconventional Reservoirs
CONOCO           SPE   114485    Unconventional Reservoirs
CONOCO          IPTC    11333    Unconventional Reservoirs
CONOCO           SPE   116688    Unconventional Reservoirs
CONOCO           SPE   114172    Unconventional Reservoirs
CONOCO    SPE    102094   Unconventional Reservoirs
CONOCO    SPE    114912      Well Deliverability
CONOCO    SPE    117489      Well Deliverability
CONOCO    SPE    114011      Well Deliverability
CONOCO    SPE    106050      Well Deliverability
CONOCO    SPE    107793      Well Deliverability
CONOCO    SPE    114804      Well Deliverability
CONOCO    SPE     97121      Well Deliverability
CONOCO    SPE    103617      Well Deliverability
CONOCO    SPE    107780      Well Deliverability
CONOCO    SPE    105541      Well Deliverability
CONOCO    SPE    105542      Well Deliverability
CONOCO    SPE    121498      Well Deliverability
CONOCO    SPE    102802      Well Deliverability
CONOCO    SPE    103244      Well Deliverability
CONOCO    SPE     77363      Well Deliverability
CONOCO    SPE    107978      Well Deliverability
CONOCO    SPE    116711      Well Deliverability
CONOCO    SPE    117435         Well Testing

CHEVRON   SPE    121293     Reservoir Description


CHEVRON   SPE    90539      Reservoir Description

CHEVRON   SPE    102894     Reservoir Description
CHEVRON   SPE    103486     Reservoir Description

CHEVRON   SPE    96308      Reservoir Description


CHEVRON   SPE    102741     Reservoir Description



CHEVRON   IPTC   11488      Reservoir Description

CHEVRON   SPE    109810     Reservoir Description

CHEVRON   SPE    110515     Reservoir Description

CHEVRON   SPE    114183     Reservoir Description


CHEVRON   SPE    105087     Reservoir Description
CHEVRON   SPE              Reservoir Management


CHEVRON   IPTC   11219     Reservoir Management


CHEVRON   SPE    100656    Reservoir Management
CHEVRON   SPE    102988   Reservoir Management


CHEVRON   SPE    89755    Reservoir Management

CHEVRON   SPE    102557   Reservoir Management

CHEVRON   SPE    128335   Reservoir Management

CHEVRON   IPTC   11551    Reservoir Management

CHEVRON   SPE     98567   Reservoir Management
CHEVRON   SPE    108893   Reservoir Management


CHEVRON   SPE    116528   Reservoir Management

CHEVRON   SPE    107732   Reservoir Management


CHEVRON   IPTC   11540    Reservoir Management


CHEVRON   SPE    120102   Reservoir Management

CHEVRON   SPE    101028   Reservoir Management
CHEVRON   SPE     98198   Reservoir Management

CHEVRON   SPE    99959     Reservoir Modelling

CHEVRON   SPE    112257    Reservoir Modelling

CHEVRON   SPE    111921    Reservoir Modelling

CHEVRON   SPE    95523     Reservoir Modelling

CHEVRON   SPE    107200    Reservoir Modelling

CHEVRON   SPE    106176    Reservoir Modelling
CHEVRON   SPE     90058    Reservoir Modelling

CHEVRON   SPE    90065     Reservoir Modelling

CHEVRON   SPE    119138    Reservoir Modelling


CHEVRON   SPE    121299    Reservoir Modelling


CHEVRON   SPE    110081    Reservoir Modelling
CHEVRON   SPE    114983   Reservoir Modelling


CHEVRON   SPE    119002   Reservoir Modelling

CHEVRON   SPE    119172   Reservoir Modelling

CHEVRON   SPE    119165   Reservoir Modelling


CHEVRON   SPE    103194   Reservoir Modelling

CHEVRON   SPE    118963   Reservoir Modelling

CHEVRON   SPE    118839   Reservoir Modelling




CHEVRON   SPE    113904   Reservoir Modelling


CHEVRON   SPE    102070   Reservoir Modelling
CHEVRON   SPE    111916   Reservoir Modelling

CHEVRON   IPTC   12572    Reservoir Modelling

CHEVRON   SPE    106086   Reservoir Modelling


CHEVRON   SPE    106435   Reservoir Modelling

CHEVRON   SPE    101144   Reservoir Modelling

CHEVRON   SPE    99619    Reservoir Modelling
CHEVRON   SPE    84469    Reservoir Modelling

CHEVRON   SPE    120053   Reservoir Modelling

CHEVRON   SPE    119183   Reservoir Modelling

CHEVRON   SPE    96260    Reservoir Modelling

CHEVRON   SPE    112124   Reservoir Modelling

CHEVRON   SPE    99937    Reservoir Modelling

CHEVRON   SPE    99979    Reservoir Modelling


CHEVRON   IPTC   11489    Reservoir Modelling
CHEVRON   SPE    103258   Reservoir Modelling

CHEVRON   SPE    90091    Reservoir Modelling

CHEVRON   SPE    121335   Reservoir Modelling

CHEVRON   IPTC   12480    Reservoir Modelling


CHEVRON   SPE    95557    Reservoir Modelling

CHEVRON   SPE    103901   Reservoir Modelling

CHEVRON   SPE    102491   Reservoir Modelling


CHEVRON   SPE    109686   Reservoir Modelling

CHEVRON   SPE    103159   Reservoir Modelling

CHEVRON   SPE    107468   Reservoir Modelling

CHEVRON   SPE    121393   Reservoir Modelling

CHEVRON   SPE     93324   Reservoir Modelling
CHEVRON   SPE    100384   Reservoir Modelling


CHEVRON   SPE    95528    Reservoir Modelling
CHEVRON   SPE    84501    Reservoir Modelling

CHEVRON   SPE    128605   Reservoir Modelling

CHEVRON   SPE    118969   Reservoir Modelling



CHEVRON   SPE    121305   Reservoir Modelling
CHEVRON   SPE     92991   Reservoir Modelling

CHEVRON   SPE    111571   Reservoir Modelling

CHEVRON   SPE    119177   Reservoir Modelling

CHEVRON   SPE    114099   Reservoir Modelling

CHEVRON   SPE    99833    Reservoir Modelling


CHEVRON   SPE    118709   Reservoir Modelling

CHEVRON   SPE    93395    Reservoir Modelling
CHEVRON   SPE   119190    Reservoir Modelling

CHEVRON   SPE   90713     Reservoir Modelling

CHEVRON   SPE   103295    Reservoir Modelling

CHEVRON   SPE   99465     Reservoir Modelling


CHEVRON   SPE   109964    Reservoir Modelling

CHEVRON   SPE   81496     Reservoir Modelling

CHEVRON   SPE   105208    Reservoir Modelling

CHEVRON   SPE   100526    Reservoir Modelling

CHEVRON   SPE   92965     Reservoir Modelling

CHEVRON   SPE   119171    Reservoir Modelling

CHEVRON   SPE   109876    Reservoir Modelling

CHEVRON   SPE   89754     Reservoir Modelling


CHEVRON   SPE   109262    Reservoir Modelling

CHEVRON   SPE   109765    Reservoir Modelling


CHEVRON   SPE   109868    Reservoir Modelling

CHEVRON   SPE   114697    Reservoir Modelling

CHEVRON   SPE   114697    Reservoir Modelling


CHEVRON   SPE   100209   Reservoir Performance

CHEVRON   SPE   114909   Reservoir Performance

CHEVRON   SPE   92973    Reservoir Performance

CHEVRON   SPE   122357   Reservoir Performance



CHEVRON   SPE   96448    Reservoir Performance
CHEVRON   SPE    91393    Reservoir Performance

CHEVRON   SPE    106994   Reservoir Performance


CHEVRON   SPE    116758     State of the Nation

CHEVRON   SPE    113011     State of the Nation

CHEVRON   SPE    109670     State of the Nation




CHEVRON   SPE    98746      State of the Nation


CHEVRON   SPE    83995      State of the Nation


CHEVRON   SPE    116580     State of the Nation
CHEVRON   SPE               State of the Nation


CHEVRON   SPE    116916        Surveillence



CHEVRON   SPE    107268        Surveillence

CHEVRON   IPTC   12628         Surveillence


CHEVRON   IPTC   12343         Surveillence


CHEVRON   SPE    114981        Surveillence


CHEVRON   SPE    114352        Surveillence
CHEVRON   SPE    105200        Surveillence
CHEVRON   SPE    110097        Surveillence

CHEVRON   SPE    97912         Surveillence

CHEVRON   SPE    123320        Surveillence


CHEVRON   SPE    109608        Surveillence

CHEVRON   SPE    102200        Surveillence
CHEVRON   SPE    123145         Surveillence

CHEVRON   SPE    109855   Unconventional Reservoirs

CHEVRON   SPE    96018    Unconventional Reservoirs



CHEVRON   SPE    128337       Well Deliverability


CHEVRON   SPE    89753        Well Deliverability

CHEVRON   SPE    100834       Well Deliverability

CHEVRON   SPE    101987       Well Deliverability

CHEVRON   SPE    112531       Well Deliverability



CHEVRON   SPE    101821       Well Deliverability

CHEVRON   SPE    101019       Well Deliverability




CHEVRON   SPE    102326       Well Deliverability

CHEVRON   SPE    108142       Well Deliverability
CHEVRON   SPE    109247       Well Deliverability

CHEVRON   SPE    102990       Well Deliverability
CHEVRON   SPE    103433       Well Deliverability

CHEVRON   SPE    102773       Well Deliverability

CHEVRON   SPE    84399        Well Deliverability
CHEVRON   SPE    90541        Well Deliverability


CHEVRON   SPE    103308       Well Deliverability

CHEVRON   IPTC   11332        Well Deliverability


CHEVRON   SPE    103266       Well Deliverability
CHEVRON   SPE   116764   Well Deliverability

CHEVRON   SPE   109588   Well Deliverability


CHEVRON   SPE   108088   Well Deliverability



CHEVRON   SPE   128334   Well Deliverability
CHEVRON   SPE    98563   Well Deliverability

CHEVRON   SPE   112394   Well Deliverability

CHEVRON   SPE   110395   Well deliverability


CHEVRON   SPE   106707   Well Deliverability

CHEVRON   SPE   112084   Well Deliverability

CHEVRON   SPE   107440   Well Deliverability

CHEVRON   SPE   103821   Well Deliverability


CHEVRON   SPE   86504    Well Deliverability

CHEVRON   SPE   98221    Well Deliverability

CHEVRON   SPE   122630   Well Deliverability


CHEVRON   SPE   102669   Well Deliverability

CHEVRON   SPE   111431   Well Deliverability

CHEVRON   SPE   98375    Well Deliverability

CHEVRON   SPE   110272     Well Testing


CHEVRON   SPE   105134     Well Testing

CHEVRON   SPE   113903     Well Testing


CHEVRON   SPE   112732     Well Testing
            Section                              Subject
              CoP's OOC                           Ekofisk
                 WAG                    Kuparuk Project Performance
      Modelling - Slug Tracking                 Case Study
           Network Design                      Offshore Gas
          Subsea Pipelines
            Complex Wells                      Flow Behaviour
            Complex Wells
                  ESP
         Reservoir Modelling            Reaction-Diffusion Processes
                 SAGD                       Expanding Solvent
         Thermal Recovery                  Carbonate Reservoir
            Horizontal Well                      Clean-up
       Static Reservoir Model                   Permeability
        Fault Zone Modelling
        Formation Evaluation              Deep Reading Resitivity
        Formation Evaluation                       LWD
        Formation Evaluation           Pressure Testing while Drilling
        Formation Evaluation           Pressure Testing while Drilling
       Shared Earth Modelling               Seismic Integration
       Static Reservoir Model               minimodels - SAG
       Static Reservoir Model                  Permeability
           Integrated Asset                Optioneering Process
     Modelling - Integrated Asset            Large Well Count
       Performance Evaluation            Novel Statistical Analysis
    Produced Water Management                   XJG Fields
             Thin Oil Rim                           IOR
           Analytical Model                        SAGD
     Complex Reservoir Models               Solution Technique
     Complex Reservoir Models               Solution Technique
Coupled Geomechanical/Compositional         Solution Technique
Coupled Geomechanical/Compositional
        Gas Lift Optimisation         Integrated in Reservoir Simulation
                Gridding                             PEBI
            Inflow Profiling                    Complex wells
 Mechanism - Gas Assisted Drainage             Physical Models
 Mechanisms - Gas Assisted Drainage             Visual Models
   Naturally Fractured Reservoirs      Lab Testing - Transfer Functions
        Province Comparison              UKCS vs Alaska North Slope
     Unconventional Reservoirs                       China
        Water Entry Detection                     Gas Wells
         Bitumen Recovery                           XSAGD
          Coalbed Methane                        P/z Analysis
          Coalbed Methane                        Permeability
          Coalbed Methane                    Production Analysis
          Coalbed Methane                  Reservoir Management
          Coalbed Methane                        Well Testing
        Reservoir Description         Pressure Dependent Permeability
              Shale Gas                      Production Analysis
              Stimulation
          Tar Sands
          Artificial Lift           Formation Powered Jet Pump
          Artificial Lift                      SAGD
   Completion Optimisation               Big Bore Design
       Fracture Design                  Candidate selection
    Fracture Performance                 Chalk reservoirs
          Fracturing                 Massive Annular Fracturing
        Horizontal Well                      Openhole
   Lab Testing - Fracturing                Heterogeneity
  Modelling - Acid treatment              Horizontal Well
         Sand Control                 Completion Optimisation
         Sand Control                         Failure
      Sand Management                        Clean-out
      Sand Management                Observations Post-Failure
      Sand Management
      Skin Factor Model                   Horizontal wells
          Stimulation                     Acid Fracturing
 Water and Condensate Blocks            Chemical Treatment
       Horizontal WElls              Thermal Transient Analysis

   Natural Fracture Detection            PLT Interpretation


      NMR Interpretation

          Permeability                   PLT Interpretation
          Permeability                   PLT Interpretation

       Porosity Modelling              Carbonate Reservoirs


Relative Permeability Correlation        Gas Condensate



     Reservoir Connectivity           Downhole Fluid Analysis

             SCAL                        Gas Condensate

             SCAL                          Thermal Tests

             SCAL                          Thermal Tests


   Static Reservoir Model                   Case Study
Gas Condensate Development


Modelling - Experimental Design      Development Optimisation


Modelling - Experimental Design             Tahiti Field
Modelling - Experimental Design                      Tahiti Field


Modelling - Experimental Design                      Thin Oil Rim

  Modelling - Integrated Asset                Development Optimisation

  Modelling - Integrated Asset                  Infill Well Performance

 Produced Water Management                      Greater Burgan Field

 Produced Water Management
 Produced Water Management


    Production Optimisation                         Mature Fields

        Sour Reservoir


   Uncertainty Management                        Multiple Reservoirs


   Uncertainty Management                      Quantifying Uncertainty

        Well Intervention                        Candidate Selection
  Well Placement Optimisation                 Production Potential maps

   Adjoint Based Simulation                    Production Optimisation

   Adjoint Based Simulation                  Well Placement Optimisation

 Analytical - Net Voidage Curve                  Pressure response

      Annular Flow Model                             Two Phase

         Assisted HM                                   Justified

         Assisted HM                     Kernel principal component analysis
         Assisted HM                              LBFGS Algorithm

         Assisted HM              Simultaneous perturbation stochastic approximation

         Assisted HM                        Statistical Moment Equations


Capacitance-Resistive Technique                      Giant Fields


Capacitance-Resistive Technique                      Waterflood
   Capacitance-Resistive Technique                   Waterflood


       Chemical Flood Simulator                     Development

      Complex Physics Modelling                       Heavy Oil

      Complex Physics Modelling             Phase-Component Partitioning


    Coupled EOS/Sufactant Model

Coupled Reservoir/Geomechanical Model        Ensemble based Application

 Coupled Reservoir/Petro Elastic Model               4D Seismic




   Coupled Reservoir/Surface Model                   Deepwater


        Coupled Well/Reservoir                        Thermal
        Decline Curve Analysis

      Discrete Fracture Modelling                Carbonate reservoir

     Ensemble based Application                       Upscaling


      Finite Volume Formulation                       Gridding

       Fractional Flow Analysis                    Horizontal Wells

           Gas Condensate                             Accuracy
            Gas Potential                           Determination

              Giant Field

       Heterogeneity Modelling           Multiscale Finite Volume Formulation

          Inflow Performance                   Temperation Prediction

      Injector Producer Modelling                  Neural-Network

           Integrated Asset              Probabilistic Production Forecasting

           Integrated Asset              Probabilistic Production Forecasting


           Material Balance                 Complex Dynamic Behaviour
         Material Balance                         P/Z

     Modelling - Assisted Hm           Well Placement Optimisation

   Modelling - Multilateral Wells        Multilayered Reservoirs

 Modelling - Optimised Simulation        Production Optimisation


    Modelling Data Integration              History Matching

  Naturally Fractured Reservoirs        Finite Volume Formulation

  Naturally Fractured Reservoirs               Upscaling


  Naturally Fractured Reservoirs               Upscaling

      Near Wellbore Stability                Geomechanical

          Neural-Network                    History Matching

       Parametric Modelling            Ensemble based Application

      Prediction Uncertainty               PUNQ-S3 Problem
 Pressure and Rate Interpretation           Diagnostic Tool


Probabilistic Production Forecasting        Gas Condensate
Probabilistic Production Forecasting

Probabilistic Production Forecasting

      Production Constraints              Feedback Controllers



      Production Optimisation          Ensemble based Application
        Real Time Updating             Ensemble based Application

        Real Time Updating             Ensemble based Application

        Real Time Updating             Ensemble based Application

      Shared Earth Modelling                   Deepwater

        Simplified Workflow                   Mature Fields


            Simulation                    Experimental Design

            Simulation                  Finite Volume Framework
        Simulation             Multi-D Transport Equations Implemented

        Steamflood                      Modelling parameters

        Streamline                            Gridding

        Streamline                        History Matching


        Streamline                        History Matching

        Streamline                            Upscaling

 Uncertainty Management              Global Optimisation Methods

 Uncertainty Management            Probablistic Production Forecast

        Upscaling                       Adaptive local-global

        Upscaling                      Adaptive Reconstruction

   Water Front Tracking

      Wellbore Flow                       Gas-Condensate


      Wellbore Flow                       Horizontal Wells

      Wellbore Flow                   Temperadture Prediction


      Wellbore Flow                          Two Phase

Wellbore Stability Modelling

Wellbore Stability Modelling


  Breakthrough Profiling                 Temperature Effect

    Fault Reactivation                     Steamflooding

      Heterogeneity                 Statistical Moment Equations

        Mechanism                        Acid Breakthrough



        Mechanism                       Rel. Perm. Hysteresis
          Mechanism                  Water Vaporization

 Naturally Fractured Reservoirs    Shared Earth Modelling


       Decision Making                    Review

         Development                 Deepwater - GOM

        Flow Assurance                   Deepwater




     Fracture Diagnostics                Clean-up


        Gravel Packing                Horizontal Wells


      Inflow Performance                 Analytical
 Produced Water Management


          4D Seismic                    Enfield Field



      Downhole Sensors                   Placement

        Inflow Profiling             PLT Interpretation


        Inflow Profiling             Temperature Data


       PLT Interpretation            Gas-Liquid Slipage


       PLT Interpretation          Multiphase Flow Models
     Production Allocation               Optimisation
Rate and Pressure Interpretation     Downhole Gauges

    Steamflood Monitoring            Temperature Data

     Time Lapsed Logging            Formation Evalustion


    Water Sweep Efficiency            Carbon/Oxygen

     Waterflood Monitoring
          Well Monitoring                     Automated

                Coal

      Well Type Optimisation                     CBM



            Artificial Lift                    Gas Lift


      Completion Optimisation              Gas Condensate

          Complex Wells                  Carbonate Reservoir

Formation Damage/High Velocity Flow     Productivity Impairment

          Fracture Design                     Frac Fluids



          Fracture Design               Non-Darcy/Multiphase

          Fracture Design                   Water Control




        Fracture Diagnostics          Clean-up/Damage Mitigation

        Fracture Diagnostics            Microseismic Monitoring
        Fracture Diagnostics               Non-Darcy Effects

       Fracture Diagnostics            Water Injector Fracturing
   Gas Condensate Deliverability        Distinguished Lecture

      High Velocity Coefficient            Two Phase Flow

        Inflow Performance                   Profiling
           Inflow Profiling               Temperature Data


          Intelligent Well              Production Optimisation

           Liquid Loading                    Dual Lateral


           Liquid Loading
               Liquid Loading

Modelling - Coupled Reservoir/Geomechanical     Cavity Completion


            Perforation Methods                 Propellant assisted



            Perforation Methods
               Sand Control                         Deepwater

               Sand Control                         Deepwater

               Sand Control                        Gravel Pack


               Sand Control                      Horizontal Wells

               Sand Control                       Screen Failure

               Sand Control                   Screenless Completions

               Sand Control                         Steamflood


                Stimulation                       Acid treatment

                Stimulation                       Acid treatment

                Stimulation                       Acid treatment


                Stimulation                      Gas Condensate

                Stimulation                    Surfactant Fracturing

              Water Blocking                     Gas Condensate

        Analysis - Fluivial Reservoir          PTA/Seismic Attribute


         Analysis - Horizontal Wells           Carbonate Reservoir

           Analysis - Multiphase                     2 Phase


              Sand Prediction                 Pre Drill DST Prediction
                                              Title
Online Production Optimisation on Ekofisk
Kuparuk MWAG Project After 20 Years
Pipelines Slugging and Mitigation: Case Study for Stability and Production Optimization
Efficient Conceptual Design of an Offshore Gas Gathering Network
Effect of System Pressure on Restart Conditions of Subsea Pipelines
Rate-Time Flow Behavior of Heavy Oil From Horizontal and Multilateral Wells
The Use of Multilateral Well Designs for Improved Recovery in Heavy-Oil Reservoirs
ESP Operation, Optimization, and Performance Review: ConocoPhillips China Inc. Bohai Bay Project
Accurate Numerical Simulation of Reaction-Diffusion Processes for Heavy Oil Recovery
Expanding Solvent SAGD in Heavy Oil Reservoirs
Application of Thermal Recovery Processes in Heavy Oil Carbonate Reservoirs
Openhole Cleanup of Deep, High-Temperature Horizontal Wells With a Chelant-Based Acid System—Case Histories From In
Modeling Permeability in Tight Gas Sands Using Intelligent and Innovative Data Mining Techniques
Fluid Flow in a Fractured Reservoir Using a Geomechanically-Constrained Fault Zone Damage Model for Reservoir Simulation
A New Azimuthal Deep-Reading Resistivity Tool for Geosteering and Advanced Formation Evaluation
Combining Advanced Real-Time LWD Answers With Accurate and Flexible 3D Rotary-Steerable System for Proactive Reservo
Formation Pressure Testing While Drilling in Bohai Bay's Challenging Environment
Reservoir Fluid Evaluation from Real Time Pressure Gradient Analysis: Discussions on Principles, Workflow, and Applications
Incorporating Seismic Characterization Results into Bul Hanine Geological Model
Permeability Modeling for the SAGD Process Using Minimodels
Permeability Determination of the PL19-3 Field for Geologic Model Input
Field Development Plan by Optioneering Process Sensitive to Reservoir and Operational Constraints and Uncertainties
Reservoir Optimization and Monitoring: Mauddud Reservoir—Bahrain Field
An Unconventional But Definitive Analysis of a Field's Production Improvement
Production Diagnostics and Water Control for the XJG Fields, South China Sea
Identifying the Improved-Oil-Recovery Potential for a Depleted Reservoir in the Betty Field, Offshore Malaysia
A New Analytical Model for Conduction Heating during the SAGD Circulation Phase
Studies of Robust Two Stage Preconditioners for the Solution of Fully Implicit Multiphase Flow Problems
Towards a New Generation of Physics Driven Solvers for Black Oil and Compositional Flow Simulation
A New Solution Procedure for a Fully Coupled Geomechanics and Compositional Reservoir Simulator
Development of a Coupled Geomechanics Model for a Parallel Compositional Reservoir Simulator
Implementation of a Total-System Production-Optimization Model in a Complex Gas-Lifted Offshore Operation
Sequentially Adapted Flow-Based PEBI Grids for Reservoir Simulation
An Interpretation Method of Downhole Temperature and Pressure Data for Flow Profiles in Gas Wells
Range of Operability of Gas-Assisted Gravity Drainage Process
Mechanisms and Performance Demonstration of the Gas-Assisted Gravity-Drainage Process Using Visual Models
Impacts From Fractures On Oil Recovery Mechanisms In Carbonate Rocks At Oil-Wet And Water-Wet Conditions—Visualizin
U.K. North Sea and Alaska North Slope: A Comparative Analysis of Petroleum Provinces
Will the Blossom of Unconventional Natural Gas Development in North America Be Repeated in China?
Field Application of an Interpretation Method of Downhole Temperature and Pressure Data for Detecting Water Entry in Inclined
Thermal Efficiency and Acceleration Benefits of Cross SAGD (XSAGD)
Application of Flowing p/Z* Material Balance for Dry Coalbed-Methane Reservoirs
Predicting Sorption-Induced Strain and Permeability Increase With Depletion for CBM Reservoirs
Production Data Analysis of Coalbed-Methane Wells
Coalbed Methane Pilots: Timing, Design and Analysis
Case Study: Production Data and Pressure Transient Analysis of Horseshoe Canyon CBM Wells
Spatial Variation of San Juan Basin Fruitland Coalbed Methane Pressure Dependent Permeability: Magnitude and Functional F
Production Data Analysis of Shale Gas Reservoirs
Stimulating Unconventional Reservoirs: Lessons Learned, Successful Practices, Areas for Improvement
Quantifying Resources for the Surmont Lease with 2D Mapping and Multivariate Statistics
Formation Powered Jet Pump Use at Kuparuk Field in Alaska
SAGD Gas Lift Completions and Optimization: A Field Case Study at Surmont
Revised Big Bore Well Design Recovers Original Bayu-Undan Production Targets
Horizontal Fracture Stimulation Success in the Alpine Formation, North Slope, Alaska
Well Productivity In North Sea Chalks Related To Completion And Hydraulic Fracture Stimulation Practices
Massive Annular Fracturing Practices in BJC Gas Field, Sichuan, China
Predicting Horizontal-Openhole-Completion Success on the North Slope of Alaska
Laboratory Hydraulic Fracturing Test on a Rock With Artificial Discontinuities
An Acid-Placement Model for Long Horizontal Wells in Carbonate Reservoirs
Magnolia Deepwater Experience—Frac-Packing Long Perforated Intervals in Unconsolidated Silt Reservoirs
Lessons Learned on Sand-Control Failure and Subsequent Workover at Magnolia Deepwater Development
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
Use of Reservoir Formation Failure and Sanding Prediction Analysis for Viable Well-Construction and Completion-Design Optio
A New Skin-Factor Model for Perforated Horizontal Wells
Recent Acid-Fracturing Practices on Strawn Formation in Terrell County, Texas
A New Solution to Restore Productivity of Gas Wells With Condensate and Water Blocks
Thermal Transient Analysis Applied to Horizontal Wells

Using PLT Data to Estimate the Size of Natural Fractures

Limits of 2D NMR Interpretation Techniques to Quantify Pore Size, Wettability, and Fluid Type: A
Numerical Sensitivity Study

Permeability From Production Logs - Method and Application
Permeability From Production Logs—Method and Application
3D Porosity Modeling of a Carbonate Reservoir Using Continuous Multiple-Point Statistics
Simulation


Relative Permeability of Gas-Condensate Fluids: A General Correlation



Predicting Downhole Fluid Analysis Logs to Investigate Reservoir Connectivity
Experimental Determination of Relative Permeabilities for a Rich Gas/Condensate System Using
Live Fluid
Oil Recovery and Fracture Reconsolidation of Diatomaceous Reservoir Rock by Water Imbibition at
High Temperature

Alteration of Reservoir Diatomites by Hot Water Injection

The Wafra First Eocene Reservoir, Partitioned Neutral Zone (PNZ), Saudi Arabia and Kuwait:
Geology, Stratigraphy, and Static Reservoir Modeling
Engineer Your Gas/Condensate Systems, Reservoir to Sales Meter
The Jurassic-Age Marrat Reservoir at Humma Field, Partitioned Neutral Zone (PNZ), Saudi Arabia
and Kuwait—Utilization of a Probabilistic, Two Stage Design of Experiments Workflow for
Reservoir Characterization and Management

Tahiti: Development Strategy Assessment Using Design of Experiments and Response Surface
Methods
Tahiti Field: Assessment of Uncertainty in a Deepwater Reservoir Using Design of Experiments


Production Strategy for Thin-Oil Columns in Saturated Reservoirs

Integrated Optimization of Field Development, Planning, and Operation

A Practical Approach to Initial Production (IP) Rate Estimation for Infill Oil Wells

Effluent Water Disposal Experiences in the Greater Burgan Field of Kuwait

Constructed Treatment Wetlands for the Treatment and Reuse of Produced Water in Dry Climates
Produced-Water Management Alternatives for Offshore Environmental Stewardship


Horizontal Well Best Practices to Reverse Production Decline in Mature Fields in South China Sea

Improving Reserves and Production Using a CO2 Fluid Model in El Trapial Field, Argentina


Modeling Uncertainties of a Gas

Quantifying Uncertainty in Carbonate Reservoirs—Humma Marrat Reservoir, Partitioned Neutral
Zone (PNZ), Saudi Arabia and Kuwait
Using Neural Networks for Candidate Selection and Well Performance Prediction in Water-Shutoff
Treatments Using Polymer Gels—A Field Case Study
Closing the Loop Between Reservoir Modeling and Well Placement and Positioning
Production Optimization With Adjoint Models Under Nonlinear Control-State Path Inequality
Constraints

Efficient Well Placement Optimization With Gradient-Based Algorithms and Adjoint Models
Analytical Method for Diagnosing and Predicting Pressure Response With Injection in Waterflood
Reservoirs Using Net Voidage Curve

A Simple Model for Annular Two-Phase Flow in Wellbores

Improved Convergence Efficiency in an Assisted-History-Matching Experiment

A New Approach to Automatic History Matching Using Kernel PCA
An Improved Implementation of the LBFGS Algorithm for Automatic History Matching

A Stochastic Optimization Algorithm for Automatic History Matching
Dynamic Data Integration and Quantification of Prediction Uncertainty Using Statistical Moment
Equations


Improvements in Capacitance-Resistive Modeling and Optimization of Large Scale Reservoirs


The Use of Capacitance-Resistive Models for Rapid Estimation of Waterflood Performance
Field Applications of Capacitance-Resistive Models in Waterfloods


Development of a Three Phase, Fully Implicit, Parallel Chemical Flood Simulator
A General Unstructured Grid, Parallel, Fully Implicit Thermal Simulator and Its Application for Large
Scale Thermal Models

Efficient General Formulation Approach For Modeling Complex Physics

Coupling Equation-of-State Compositional and Surfactant Models in a Fully Implicit Parallel
Reservoir Simulator Using the Equivalent-Alkane-Carbon-Number Concept

Data Assimilation of Coupled Fluid Flow and Geomechanics via Ensemble Kalman Filter
Embedding a Petroelastic Model in a Multipurpose Flow Simulator to Enhance the Value of 4D
Seismic



Recent Advances and Practical Applications of Integrated Production Modeling at Jack Asset in
Deepwater Gulf of Mexico


Transient Fluid and Heat Flow Modeling in Coupled Wellbore/Reservoir Systems
Maximizing the Potential of Decline Curve Analysis

An Innovative Workflow to Model Fractures in a Giant Carbonate Reservoir

Ensemble-Level Upscaling for Efficient Estimation of Fine-Scale Production Statistics


A New Finite-Volume Approach to Efficient Discretization on Challenging Grids
Developing a Fractional Flow Curve from Historic Production to Predict Performance of New
Horizontal Wells, Bekasap Field, Indonesia

High-Resolution Prediction of Enhanced Condensate Recovery Processes
What Is the Real Measure of Gas-Well Deliverability Potential?
Development of a Full-Field Parallel Model to Design Pressure Maintenance Project in the Wara
Reservoir, Greater Burgan Field, Kuwait

Multiscale Finite Volume Formulation for the Saturation Equations

Prediction of Temperature Propagation Along a Horizontal Well During Injection Period

Neural-Network Based Sensitivity Analysis for Injector-Producer Relationship Identification
Increasing Confidence in Production Forecasting Through Risk-Based Integrated Asset Modelling,
Captain Field Case Study
Model-Based Framework for Oil Production Forecasting and Optimization: A Case Study in
Integrated Asset Management


Capturing Complex Dynamic Behaviour in a Material Balance Model
A Straight Line p/z Plot is Possible in Waterdrive Gas Reservoirs

Optimization of Well Placement Under Time-Dependent Uncertainty

Field Applications of a Semianalytical Model of Multilateral Wells in Multilayer Reservoirs

Applications of Optimal Control Theory for Efficient Production Optimisation of Realistic Reservoirs


A Practical Data-Integration Approach to History Matching: Application to a Deepwater Reservoir
Efficient Field-Scale Simulation for Black Oil in a Naturally Fractured Reservoir via Discrete
Fracture Networks and Homogenized Media
Upscaling Discrete Fracture Characterizations to Dual-Porosity, Dual-Permeability Models for
Efficient Simulation of Flow With Strong Gravitational Effects

Development and Application of New Computational Procedures for Modeling Miscible Gas
Injection in Fractured Reservoirs

Modeling Transient Thermo-Poroelastic Effects on 3D Wellbore Stability

Utilization of Artificial Neural Networks in the Optimization of History Matching
A New Method for Continual Forecasting of Interwell Connectivity in Waterfloods Using an
Extended Kalman Filter

Quantifying Uncertainty for the PUNQ-S3 Problem in a Bayesian Setting With RML and EnKF
Diagnosis of Reservoir Behavior From Measured Pressure/Rate Data

Decision Making With Uncertainty While Developing Multiple Gas/Condensate Reservoirs: Well
Count and Pipeline Optimization
Well Performance With Operating Limits Under Reservoir and Completion Uncertainties
Improving Production Forecasts Through the Application of Design of Experiments and Probabilistic
Analysis: A Case Study From Chevron, Nigeria

Feedback Controllers for the Simulation of Field Processes



An Improved Approach for Ensemble-Based Production Optimization
Real-Time Reservoir Model Updating Using Ensemble Kalman Filter With Confirming Option

Some Practical Issues on Real-Time Reservoir Model Updating Using Ensemble Kalman Filter

Generalization of the Ensemble Kalman Filter Using Kernels for Nongaussian Random Fields
The Effect of Geologic Parameters and Uncertainties on Subsurface Flow: Deepwater Depositional
Systems
Reservoir Modeling for Mature Fields—Impact of Work Flow and Upscaling on Fluid-Flow
Response

The Pains and Gains of Experimental Design and Response Surface Applications in Reservoir
Simulation Studies

Adaptive Multiscale Finite-Volume Framework for Reservoir Simulation
Multi-D Upwinding for Multi Phase Transport in Porous Media

Important Modeling Parameters for Predicting Steamflood Performance

Tracing Streamlines on Unstructured Grids From Finite Volume Discretizations

Compressible Streamlines and Three-Phase History Matching


Experiences With Streamline-Based Three-phase History Matching
Upscaling and 3D Streamline Screening of Several Multimillion-Cell Earth Models for Flow
Simulation
Application of Global Optimization Methods for History Matching and Probabilistic
Forecasting—Case Studies
Static and Dynamic Uncertainty Management for Probabilistic Production Forecast in Chuchupa
Field, Colombia

Efficient 3D Implementation of Local-Global Upscaling for Reservoir Simulation
Dynamic Upscaling of Multiphase Flow in Porous Media via Adaptive Reconstruction of Fine Scale
Variables

Real-Time Performance Analysis of Water-Injection Wells

Simplified Wellbore-Flow Modeling in Gas/Condensate Systems


A Dynamic Wellbore Modeling for Sinusoidal Horizontal Well Performance With High Water Cut

A Robust Steady-State Model for Flowing-Fluid Temperature in Complex Wells


A Basic Approach to Wellbore Two-Phase Flow Modeling
Building a Geomechanical Model for Kotabatak Field with Applications to Sanding Onset and
Wellbore Stability Predictions
Building a Geomechanical Model for Kotabatak Field with Applications to Sanding Onset and
Wellbore Stability Predictions


Prediction of Temperature Changes Caused by Water or Gas Entry Into a Horizontal Well
Steam Flooding Field Fault Reactivation Maximum Reservoir Pressure Prediction Using
Deterministic and Probabilistic Approaches

Conditional Statistical Moment Equations for Dynamic Data Integration in Heterogeneous Reservoirs
Models and Methods for Understanding of Early Acid Breakthrough Observed in Acid Core-floods of
Vuggy Carbonates



A New Model of Trapping and Relative Permeability Hysteresis for All Wettability Characteristics
Modeling of Experiments on Water Vaporization for Gas Injection Using Traveling Waves
An Integrated Geological and Engineering Assessment of Fracture Flow Potential in a Middle-East
Carbonate Reservoir


Bridging the Gap Between Real-Time Optimization and Information-Based Technologies

Deepwater Gulf of Mexico Development Challenges Overview

Flow Assurance Challenges in Deepwater Gas Developments




New Findings in Fracture Cleanup Change Common Industry Perceptions


Advances in Horizontal Openhole Gravel Packing


A Comprehensive Comparative Study on Analytical PI/IPR Correlations
The Latest in Ways To Improve Asset Value Through Better Water Management


Integrating 4D Seismic Data with Production Related Effects at Enfield, North West Shelf, Australia



Placement of Permanent Downhole-Pressure Sensors in Reservoir Surveillance
Field Case Histories Demonstrating Critical Role of PLT Flow Model Selection for Improved Water
Shut-off Results in Offshore Thailand


Real-Time Estimation of Total Flow Rate and Flow Profiling in DTS-Instrumented Wells

Appropriate Assessment of Gas-Liquid Slippage – A Critical Step from a Good Production
Logging Survey to a Successful Workover for Gas Wells

Field Case Histories Demonstrating the Critical Roles Played by Multiphase Flow Models in
Appropriate Production Log Interpretation
A New Rate-Allocation-Optimization Framework
Analyzing Simultaneous Rate and Pressure Data From Permanent Downhole Gauges
Fiber-Optic Distributed-Temperature-Sensing Technology Used for Reservoir Monitoring in an
Indonesia Steamflood
Time Lapse Neutron Logging Improves Formation Evaluation and Reduces Rig Time in the Gulf of
Thailand


Vertical Sweep Evaluation in the Lost Hills Diatomite Waterflood Using Carbon/Oxygen Logs

Waterflooding Surveillance and Monitoring: Putting Principles Into Practice
Automated, By Exception" Well Surveillance: A Key to Maximizing Oil Production"

Sorption-Induced Permeability Change of Coal During Gas-Injection Processes
A Parametric Study on the Benefits of Drilling Horizontal and Multilateral Wells in Coalbed Methane
Reservoirs


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

Exploring Reservoir Engineering Aspects of Completion in Gas/Condensate Reservoirs: West
African Examples

Application of a Maximum Reservoir Contact (MRC) Well in a Thin, Carbonate Reservoir in Kuwait
Effects of Formation Damage and High-Velocity Flow on the Productivity of Slotted-Liner
Completed Horizontal Wells

Weighted Frac Fluids for Lower-Surface Treating Pressures


Designing Hydraulic Fractures in Russian Oil and Gas Fields to Accommodate Non-Darcy and
Multiphase Flow

Water Control and Fracturing: A Reality




New Results Improve Fracture Cleanup Characterization and Damage Mitigation
Hydraulic Fracture Diagnostics In The Williams Fork Formation, Piceance Basin, Colorado Using
Surface Microseismic Monitoring Technology
Quantifying Non-Darcy Effects on the Productivity of a Cased-Hole Frac Pack (CHFP) Well

The Resiliency of�Frac-Packed Subsea Injection Wells
Deliverability of Gas-Condensate Reservoirs—Field Experiences and Prediction Techniques

Effect of Wettability on High-Velocity Coefficient in Two-Phase Gas/Liquid Flow
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


Maximizing Production Capacity Using Intelligent-Well Systems in a Deepwater, West-Africa Field
A Combined Well Completion and Flow Dynamic Modeling for a Dual-Lateral Well Load-up
Investigation


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
The Use of a Fully Coupled Geomechanics-Reservoir Simulator To Evaluate the Feasibility of a
Cavity Completion

New Solution To Improve Perforation Penetration and Breakdown: San Jorge Field, Argentina Case
Histories


A Novel Technology for Through Tubing Perforation in Highly Deviated Wells Where Electric Line Is
Limited
Deepwater Extended-Reach Sand-Control Completions and Interventions
Sanding Study for Deepwater Indonesia Development Wells: A Case History of Prediction and
Production
High-Angle Well Deliverability Modeling for Openhole Gravel-Pack Completion Under Ultrahigh Gas
Rate


Critical Conditions for Effective Sand-Sized Solids Transport in Horizontal and High-Angle Wells

A Novel Technique for Determining Screen Failure in Offshore Wells: A GOM Case History

Screenless Completions as a Viable Through-Tubing Sand Control Completion

Evaluation of Sand-Control Completions in the Duri Steamflood, Sumatra, Indonesia


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


Chemical Stimulation of Gas/Condensate Reservoirs
New Viscoelastic Surfactant Fracturing Fluids Now Compatible With CO2 Drastically Improve Gas
Production in Rockies
Wettability Alteration in Gas-Condensate Reservoirs to Mitigate Well Deliverability Loss by Water
Blocking
Integrating Pressure Transient Test Data With Seismic Attribute Analysis to Characterize an
Offshore Fluvial Reservoir

Challenges Encountered During a Comprehensive Test Analysis for a Horizontal Well in a Thin,
Carbonate Reservoir of the Greater Burgan Field, Kuwait

Use of Transient Testing Data To Calculate Absolute Permeability and Average Fluid Saturations

Deepwater Exploration Well Pre-Drill DST Sanding Potential Prediction Using Probabilistic and
Deterministic Approaches
                                 Author                                      Abstract
                                                                              Abstract As part of the long tradition of
Andrew Shere, SPE, and Yvonne Roberts, SPE, Weatherford/EPS, and Synnoeve Bakkevig, SPE, ConocoPhillips innovative
                                                                              Abstract Through ConocoPhillips
Wen Shi, SPE, Jeff Corwith, SPE, Andre Bouchard, Russ Bone, SPE, and Eric Reinbold, SPE, many phases of expansion the
                                                                              Abstract The ConocoPhillips Alpine facility on the
Y. Tang, SPE, Chevron Energy Technology Co., and T. Danielson, SPE, ConocoPhillips Upstream Technology Co.
                                                                              Abstract Offshore gas gathering networks require l
M.J. Watson, N.J. Hawkes, and P.F. Pickering, FEESA Limited, and L.D. Brown, ConocoPhillips Incorporated
                                                                              Abstract As SPE, and Probjot Singh, SPE, dollar
Chiedozie Ekweribe, SPE, and Faruk Civan, SPE, University of Oklahoma, Hyun Su Lee,the oil industry invests billions ofConoc
                                                                              Abstract This Switch Consulting; behavior of hea
M.D. Fetkovich, SPE, and G.E. Petrosky Jr., SPE, ConocoPhillips; C.B. Hughesman, SPE, paper examines theand�R.P. Saw
                                                                              Abstract There are now a variety of ways to achiev
Steven Fipke, Halliburton, Sperry Drilling Services; and Adriano Celli, Petrozuata
                                                                              Abstract ConocoPhillips China Inc. (COPC) opera
Zhizhuang Jiang, SPE, ConocoPhillips China Inc., and Bassam Zreik, SPE, Schlumberger
                                                                              Abstract Many examples of reaction-diffusion proc
Pradeep Ananth Govind and Sanjay Srinivasan, SPE, The University of Texas at Austin
                                                                              Abstract In recent Company, Sanjay Srinivasan, S
Pradeep Ananth Govind, SPE, ConocoPhillips Canada Ltd., Swapan Das, SPE, ConocoPhillipsyears several Steam Assisted G
Swapan Das, ConocoPhillips                                                    Abstract As the demand for oil grows the petroleu
                                                                              Abstract ConocoPhillips Nieuwland, and Juanita C
Kunto Wibisono, Robert C. Burton, and Richard M. Hodge, ConocoPhillips, and Rio Wijaya, BastiaanIndonesia Inc. Ltd. is prod
Liaqat Ali, SPE, Sandip Bordoloi, and Serene H. Wardinsky, ConocoPhillips Abstract Evaluation of gas potential in low permeab
                                                                              Abstract Secondary fractures and faults associate
Pijush Paul, SPE, and Mark Zoback, SPE, Stanford University, and Peter Hennings, ConocoPhillips
                                                                              Beste, G. Hu, M. Wu, J. Pitcher, companies Altho
M. Bittar, SPE, Halliburton Energy Services; J. Klein, ConocoPhillips; and R. Abstract Drilling services and oil C. Golla, G.have
                                                                              Abstract Development of formation evaluation tech
Trond Gravem, Alf Berle, Sven S. Gundersen, INTEQ, and Jarle Pedersen, Kjell Oddvar Rorvik, and Atle Hansen, ConocoPhill
                                                                               Inteq, and Jenson describes the experience and
Ulrich Hahne, Jos Pragt, Martin Venier, and Matthias Meister, Baker HughesAbstract This paperTan and Dai Chunsen, Conoco
L. Zhou, SPE, Baker Hughes; J. Mardambek, SPE, Rice University                Abstract Modern formation pressure testing while d
                                                                              Abstract Bul Pellerin and Ga�l Lecante, Beicip-F
Nicolas Desgoutte, Beicip-Franlab; Abdulmalik Al Abdulmalik, Qatar Petroleum; Matthieu Hanine field is located offshore Qatar
                                                                              Abstract The predicted flow performance of Steam
J.A. McLennan and C.V. Deutsch, U. of Alberta; D. Garner and T.J. Wheeler, ConocoPhillips Canada Ltd.; and J.-F. Richy and
M.D. Fetkovich, M.G. Gerard, L.Y. Chin, and D. Shuxing, ConocoPhillips        Abstract The overall structure of the PL19-3 field
                                                                              Abstract A revised Field Development Cuauro, Sc
E. Kasap, Schlumberger; G.J. Sanza, and M.I. Ali, Petronas Carigali; T. Friedel, A. Waheed, A.Y. Sukmana, and A.Plan (FDP)
                                                                              Abstract Ayda Abdulwahab, BAPCO
Ali E. AL-Muftah, BAPCO; William Vargas, PETE Schlumberger, Huston; CRK Murty,For a matured oil field like Bahrain Field w
R. Schulz and L. Harms, ConocoPhillips                                        Abstract Production results from capital or operati
                                                                              Abstract The China National Offshore Oil Corporat
Zhizhuang Jiang and Zhang Tao, ConocoPhillips, China Inc., and Khong Chee Kin and Robert North, Schlumberger China Inc.
                                                                              Abstract A reservoir Bhd.; andE. Kasap*, S. Yuso
T. Friedel, SPE, Schlumberger; G.J. Sanza, M.I. Ali, and A. Embong, SPE, Petronas Carigali Sdn simulation model calibrated w
                                                                              Abstract The initial steam chamber
Anh N. Duong, SPE, ConocoPhillips Canada, Timothy A. Tomberlin, ConocoPhillips, Martin Cyrot, Total E&P that developed
                                                                              Abstract The solution of the linear system of equa
Tareq M. Al-Shaalan, SPE, Saudi Arabian Oil Company; Hector Klie, SPE, Center for Subsurface Modeling, The University of T
                                                                              Abstract In recent years there has been a resurge
Hector Klie, ConocoPhillips; Jorge Monteagudo, Reservoir Engr. Research Inst. and Hussein Hoteit and Adolfo Rodriguez, Con
                                                                              Abstract Traditional reservoir simulators Company
Feng Pan, SPE, and Kamy Sepehrnoori, SPE, The University of Texas at Austin, and L.Y. Chin, SPE, ConocoPhillips cannot ca
                                                                               and L.Y. Chin, SPE, ConocoPhillips Company
Feng Pan, SPE, and Kamy Sepehrnoori, SPE, University of Texas at Austin,Abstract This paper presents a coupled geomecha
                                                                              Summary A ConocoPhillips Company; and C.J.N
M.S. Nadar, SPE, Edinburgh Petroleum Services; T.S. Schneider and K.L. Jackson, SPE,total-system production-optimization m
                                                                              Summary A technique for the
M.J. Mlacnik, SPE, and L.J. Durlofsky, SPE, Stanford U., and Z.E. Heinemann, SPE, Mining U. of Leoben sequential generatio
Ochi I. Achinivu, Zhuoyi Li, D. Zhu, and A.D. Hill, Texas A&M University      Abstract Accurate and reliable downhole data acq
T.N. Mahmoud, SPE, and D.N. Rao, SPE, Louisiana State University              Abstract The gas-assisted gravity drainage (GAGD
T.N. Mahmoud, SPE, and D.N. Rao, SPE, Louisiana State University              Abstract The Gas Assisted Gravity Drainage (GAG
                                                                              Abstract Bergen, and J. Stevens and J. Howard, C
M.A. Fern�, G. Ersland, �. Haugen, E. Johannesen, and A. Graue, University of The fracture/matrix transfer and fluid flow
                                                                              Abstract Consulting Services; and T. the SPE,
J.A. Walker, SPE, ConocoPhillips Alaska Inc.; D.O. Ogbe, SPE, Schlumberger Data &Alaska’s North Slope andZhu, United
Hongjie Xiong, Burlington Resources, and Stephen A. Holditch, Texas A&M U.    Abstract There are substantial volumes of unconve
Ochi I. Achnivu, D. Zhu, Texas A&M University, and Kenji Furui, ConocoPhillipsAbstract Accurate and reliable downhole data acqu
John L. Stalder, ConocoPhillips Canada Limited                                Abstract Two characteristics of XSAGD that accele
K. Morad, SPE, Fekete Associates Inc., and C.R. Clarkson, SPE, ConocoPhillips Abstract Material balance analysis�is a fundam
                                                                              Abstract It is well known that absolute permeability
C.R. Clarkson, ConocoPhillips, Z. Pan, CSIRO Petroleum Resources, I. Palmer, Higgs-Palmer Technologies, S. Harpalani, Sou
                                                                              R.R. Gierhart, SPE, BP America; and J.P. data an
C.R. Clarkson, SPE, ConocoPhillips; C.L. Jordan, SPE, BOE Solutions Inc.; Summary Recent advances in production Seidle, S
R.D. Roadifer, ConocoPhillips Alaska, Inc. and T.R. Moore, CDX Gas LLC Abstract Four distinct sequential phases comprise
C.R. Clarkson, SPE, ConocoPhillips                                            Abstract The Horseshoe Canyon (HSC) CBM play
                                                                              Abstract The Petroleum Consultants
R. R. Gierhart, SPE, BP; C.R. Clarkson, SPE, ConocoPhillips; and J.P. Seidle, SPE, MHASan Juan basin Fruitland coalbed me
Adam M. Lewis and Richard G. Hughes, Louisiana State University               Abstract Unconventional shale gas reservoirs have
David D.Cramer, ConocoPhillips                                                Abstract The term “unconventional reservoir ha
                                                                                Summary The McMurray formation consists of he
Weishan Ren, SPE, ConocoPhillips Canada; Clayton V. Deutsch, SPE, University of Alberta; David Garner, SPE, Chevron Can
                                                                                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
T.C. Handfield, T. Nations, S.G. Noonan; ConocoPhillips                         Abstract Gas lift completions for SAGD1 producers
                                                                                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
                                                                                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 Joint Chalk Norway; Rene Frederikse
Bart Vos and Hans de Pater, Pinnacle Technologies; Chris Cook, Norsk Hydro; Tommy Skjerven, BP Research (JCR) initiative
                                                                                Abstract Massive hydraulic fracturing China Ltd
Xing Zhenhui, Saint-Gobain (Guanghan) Proppant; Andrew Pfaff, Thomas Weller, David Wendt, EOG Resources has been suc
                                                                                Summary The Colville River
Michael D. Erwin, SPE, ConocoPhillips Alaska, and David O. Ogbe,SPE, University of Alaska Fairbanks field represents the fi
                                                                                 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
Varun Mishra, D. Zhu, and A.D. Hill, Texas A&M U., and K. Furui, ConocoPhillips Abstract In several places around the world notab
                                                                                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
                                                                                Abstract ConocoPhillips is developing the Magnolia
George Colwart, Robert C. Burton, Luke F. Eaton, and Richard M. Hodge, ConocoPhillips Co., and Kenyon Blake, Schlumberg
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
                                                                                Abstract Using two field
G.-F. Fuh, I. Ramshaw, K. Freedman, and N. Abdelmalek, ConocoPhillips, and N. Morita, Waseda U.case examples this pape
                                                                                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
                                                                                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 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
Anh N. Duong, SPE, ConocoPhillips Canada                                        Abstract The effectiveness of heat injection into a t
B. Todd Hoffman, SPE, drc consulting, and Wayne Narr, SPE, and Liyong
Li, SPE, Chevron ETC                                                            Abstract In naturally fractured reservoirs determin
Emmanuel Toumelin, SPE, and Carlos Torres-Verd�n, SPE, U. of
Texas at Austin, and Boqin Sun and Keh-Jim Dunn, Chevron Energy
Technology Co.                                                                  Summary Two-dimensional (2D) NMR techniques
M.J. Sullivan, D.L. Belanger, M.T. Skalinski, S.D. Jenkins, and P. Dunn,
Chevron                                                                         Abstract Estimation of effective permeability at the
Michael J. Sullivan, SPE, Chevron                                               Distinguished Author Series articles are general d
T. Zhang, Stanford U., and S. Bombarde, S. Strebelle, and E. Oatney,
Chevron Corp. ETC                                                               Summary Training images are numerical represen
V. Bang, SPE, and V. Kumar, SPE, U. of Texas at Austin; P.S.
Ayyalasomayajula, SPE, Chevron; and G.A. Pope, SPE, and M.M.
Sharma, SPE, U. of Texas at Austin                                              Abstract Predicting production from gas-condensa
Soraya S. Betancourt, Francois X. Dubost, and Oliver C. Mullins,
Schlumberger Oilfield Services; Myrt E. Cribbs and�Jefferson L. Creek,
Chevron Energy Technology Corporation; and Syriac G. Mathews,
Schlumberger Oilfield Services                                                  Abstract Compartmentalization is perhaps the sing
J.F. App, SPE, and J.E. Burger, SPE, Chevron Energy Technology
Company                                                                         Summary Measurement of gas and condensate re

M. Ikeda, G.-Q. Tang, C.M. Ross, and A.R. Kovscek, Stanford University         Abstract Spontaneous imbibition and coreflood ex
C.M. Ross, SPE, M. Ikeda, SPE, Schlumberger, G.-Q. Tang, SPE,
Chevron, and A.R. Kovscek, SPE, Stanford University                            Abstract Pore microstructure and mineral composi
W. Scott Meddaugh, SPE, Dennis Dull, Raymond A. Garber, and Stewart
Griest, Chevron Energy Technology Co., and David Barge, SPE, Saudia
Arabian Texaco                                                                 Abstract The First Eocene reservoir at Wafra Field
Shah Kabir, Chevron Energy Technology Company                                  Abstract Exploitation of gas/condensate reservoirs
W. Scott Meddaugh, SPE, Chevron Energy Technology Company; David
Barge, SPE, Saudi Arabian Chevron; and W.W.�(Bill) Todd, SPE, and
Stewart Griest, Chevron Energy Technology Company                              Abstract The Jurassic-age Humma Marrat carbona
P.E. Carreras, SPE, Chevron Energy Technology Co., and S.E. Turner,
SPE, and G.T. Wilkinson, SPE, Chevron North America Exploration and
Production Co                                                                  Abstract Tahiti field in deepwater Gulf of Mexico i
P.E. Carreras, SPE, and S.G. Johnson, SPE, Chevron Energy Technology
Co.; and S.E. Turner, SPE, Chevron North America E&P Co., Chevron
Corp.                                                                Abstract Tahiti prospect in deepwater Gulf of Mex
C.S. Kabir, SPE, Chevron Energy Technology Company; M. Agamini,
SPE, Chevron Nigeria Limited; and R.A. Holguin, SPE, Chevron North
America                                                              Summary Maximizing oil recovery in thin and ultra

B. Gűyagűler, SPE, Chevron, and K. Ghorayeb, SPE, Schlumberger       Abstract Field management (FM) is the simulation
Obor Eruvbetine, Olufemi Odusote, Inegbenose Aitokhuehi, Moses Imogu,
and Oyie Ekeng, Chevron Nigeria Ltd.                                   Abstract Asset development teams have the respo
Hamad Al-Ajmi, SPE, Issa Al-Jadi, SPE, Feras Al-Ruhaimani, SPE, Kuwait
Oil Company; Wahyu Budiarto, SPE, Chevron                              Abstract This paper presents the process of candid

N. Nijhawan and J.E. Myers, Chevron Corp.                                   Abstract When water is scarce its value increase
Akshay Sahni, Chevron and Steven T. Kovacevich, Chevron Corp.               Abstract As the hydrocarbon production in the Gul
You Hongqing, Wei Ping, Tian Xiang, Xu Xiang Dong, Lian JiHong, Thanh
Tran, Yoseph J. Partono : CACT, Jeffrey Kok, Liu Yang, Sarfraz Balka:
Schlumberger                                                                Abstract The Huizhou 6S and 3S oil fields in the Pe
M.A. Crotti, Inlab S.A.; Gustavo Fernandez, Chevron Argentina; and
Martin Terrado, Chevron Energy Technology Co.                               Abstract The El Trapial field is a 1.2 B bbl OOIP as
D.F. Frizzell, M.J. Sibley, B. Cotner, S.P. McCartney, G.R. Schmidt, SPE,
and R. Burkes, AICHE; J.C. Phelps, SEG, Chevron; and M. Tosdevin, and
J. Mazloom, SPE, Sasol Petroleum International                              Abstract A primary objective of any project evaluat
W. Scott Meddaugh, SPE, and Stewart Griest, Chevron Energy
Technology Company, Houston, TX, and David Barge, SPE, Saudi
Arabian Chevron, Houston, TX                                                Abstract The Jurassic-age Humma Marrat carbona
A. Saeedi, SPE, Chevron Corp., and K.V. Camarda and J.T. Liang, SPE,
The U. of Kansas                                                            Abstract Using actual field cases a neural-networ
N. Liu, Chevron ETC, and Y. Jalali, SPE, Schlumberger                       Abstract We present a methodology of converting
Pallav Sarma and Wen H. Chen, Chevron ETC; and Louis J. Durlofsky
and Khalid Aziz, Stanford University                                        Summary The general petroleum-production optim

Pallav Sarma and Wen H. Chen, Chevron Energy Technology Company             Abstract A key reservoir management decision tak
I.C. Okoro and S.E. Okojie, Chevron Nigeria Ltd., and J.O. Umurhohwo,
SPE                                                                         Abstract A critical component of waterflood manag
A.R. Hasan, U. of Minnesota-Duluth; and C.S. Kabir, Chevron Energy
Technology Co.                                                              Summary Annular flow is associated with producti

James F. Keating and Umut Ozdogan, Chevron North America E&P Co.            Abstract This study is an attempt to justify the incre
Pallav Sarma, Chevron ETC; Louis J. Durlofsky and Khalid Aziz, Stanford
U.; and Wen H. Chen, Chevron ETC                                            Abstract Efficient history matching of geologically c

Guohua Gao, SPE, Chevron Corp.; Gaoming Li, SPE, U. of Tulsa; and
Albert C. Reynolds, SPE, U. of Tulsa                                        Summary     For large- scale history- matching prob
P. Likanapaisal, Stanford University; L. Li, Chevron Energy Technology
Company; and H.A. Tchelepi, Stanford University                             Abstract A probabilistic framework for dynamic da
Daniel Weber, SPE, Thomas F. Edgar, Larry W. Lake, SPE, Leon Lasdon,
Sami Kawas, SPE, Morteza Sayarpour, SPE, The University of Texas at
Austin                                                                      Abstract Oil production strategies traditionally attem
M. Sayarpour, SPE, University of Texas at Austin; E. Zuluaga, SPE, and
C.S. Kabir, SPE, Chevron ETC; and Larry W. Lake, SPE, University of
Texas at Austin                                                             Abstract The capacitance-resistive model (CRM) o
M. Sayarpour, SPE, U. of Texas-Austin; C. S. Kabir, SPE, Chevron ETC;
L. W. Lake, SPE, U. of Texas-Austin                                         Abstract Application of fast simple and yet powerfu
N. Fathi Najafabadi, SPE, University of Texas at Austin; C. Han, SPE,
Chevron; and M. Delshad and K. Sepehrnoori, SPE, University of Texas at
Austin                                                                      Abstract Field-scale applications of chemical flood
Xundan Shi and Yih-Bor Chang, Chevron; Mathieu Muller and Eguono
Obi, Total USA Inc.; and Kok-Thye Lim, Chevron                              Abstract We describe the construction of a genera
H. Cao and P.I. Crumpton, Schlumberger, and M.L. Schrader, Chevron
Energy Technology Company                                                   Abstract This paper describes a general formulatio
C. Han, SPE, M. Delshad, SPE, G.A. Pope, SPE, and K. Sepehrnoori,
SPE, Center for Petroleum and Geosystems Engineering, University of
Texas at Austin                                                             Summary Equation-of-state (EOS) compositional
                                                                                                Carbon
Haibin Chang, Peking University; Yan Chen, SPE, Chevron; and Dongxiao
Zhang, SPE, U. of Southern California                                       Abstract In reservoir history matching or data assi

John R. Fanchi, Chevron ETC                                                 Abstract Time-lapse (4D) seismic can be effective
Umut Ozdogan, Chevron Energy Technology Co.; James F. Keating,
Chevron North America Exploration and Production Co.; Mark Knobles,
Chevron North America Exploration and Production Co.; Adwait
Chawathe, Chevron North America Exploration and Production Co.; and
Doruk Seren, Chevron Energy Technology Co.                                  Abstract This paper presents an integrated produc
B. Izgec, SPE, Chevron ETC/Texas A&M University; C.S. Kabir, SPE,
Chevron ETC; D. Zhu, SPE, Texas A&M University; and A.R. Hasan, SPE,
University of Minnesota-Duluth                                              Summary This paper presents a transient wellbore
I. Aitokhuehi, SPE, Chevron Nigeria Limited                                 Abstract The data most collected within the oil ind
Mun-Hong Hui, Bradley Mallison, and Kok-Thye Lim, SPE, Chevron
Energy Technology Company                                                   Abstract Most of the oil reserves in the giant carbo
Yuguang Chen, SPE, Chevron Energy Technology Company, and Louis J.
Durlofsky, SPE, Stanford University                                         Summary Upscaling is often needed in reservoir s

I. Aavatsmark, G.T. Eigestad, and B.-O. Heimsund, CIPR; B.T. Mallison,
Chevron; J.M. Nordbotten, U. of Bergen; and E. �ian, CIPR                 Abstract MPFA methods were introduced to solve
J. Sitorus, SPE, A. Sofyan, SPE, and M.Y. Abdulfatah, SPE, Chevron
Pacific Indonesia                                                           Abstract A fractional flow curve (fw versus Sw) is u
K. Jessen, University of Southern California, M.G. Gerritsen, Stanford
University, and B.T. Mallison, Chevron Energy Technology Company            Summary This paper investigates the accuracy of
C.S. Kabir, SPE, Chevron Energy Technology Co.                              Summary This paper probes the usefulness of est
Eddie Ma, KOC; Lee Williams and Anil Ambastha, Chevron; and Meqdad
Al-Naqi, KOC                                                                Abstract The Wara reservoir is one of the four ma
H. Zhou, SPE, Stanford University; S.H. Lee, SPE, Chevron Energy
Technology Company; and H.A. Tchelepi, SPE, Stanford University             Abstract Recent advances in multiscale methods

Guohua Gao, SPE, Chevron Corp.; and Younes Jalali, SPE, Schlumberger        Summary This paper presents a mathematical mo
U. Demiryurek, F. Banaei-Kashani, and C. Shahabi, University of Southern
California, and Frank Wilkinson, Chevron                                    Abstract Determining injector-producer relationshi
L.M. Wickens, SPE, RPS Energy, and G. De Jonge, SPE, Chevron
Upstream Europe                                                             Abstract To assist in the probabilistic forecasting
C. Zhang, A. Orangi, and A. Bakshi, U. of Southern California; W. Da Sie,
Chevron Corp.; and V.K. Prasanna, U. of Southern California                 Abstract This paper describes the design and imp

Jalal Mazloom and Mike Tosdevin, SPE, Sasol Petroleum International,
and Dominique Frizzell, Bill Foley, and Mike Sibley, SPE, Chevron           Abstract Sometimes a simple and quick material b
M. Elahmady, Chevron, and R.A. Wattenbarger, Texas A&M U.                 Abstract Field data and simulated models have rev
Umut Ozdogan, SPE, Chevron Energy Technology Co., and Roland N.
Horne, SPE, Stanford U.                                                   Summary Well-placement decisions made during
Yan Pan, Medhat M. Kamal and Jitendra Kikani, Chevron Energy
Technology Company                                                        Abstract Advanced drilling technology has been wi
P. Sarma and W.H. Chen, Chevron Energy Technology Company, CA,
USA                                                                       Abstract In practical reservoir management altho
B. Todd Hoffman, SPE, Montana Tech; Jef K. Caers, SPE, Stanford U.;
Xian-Huan Wen, SPE, Chevron Corp.; and Sebastien Strebelle, SPE,
Chevron                                                                   Summary This paper presents an innovative meth

Liyong Li and Seong H. Lee, Chevron Energy Technology Co.                 Abstract This paper describes a hybrid finite volum
B. Gong, SPE, M. Karimi-Fard, SPE, and L.J. Durlofsky, SPE, Stanford
University                                                                Summary The geological complexity of fractured r
Mun-Hong Hui,�SPE, and Bin Gong, SPE, Chevron Energy Technology
Company, and Mohammad Karimi-Fard, SPE, and Louis J. Durlofsky,
SPE, Stanford University                                                  Abstract Detailed geological characterizations of na
H.S. Farahani, M. Yu, S. Miska, and N. Takach, SPE, U. of Tulsa, and G.
Chen, SPE, Chevron Energy Technology Co.                                  Abstract The temperature difference between the
Asha Ramgulam, Turgay Ertekin, and Peter B. Flemings, Pennsylvania
State U.                                                                  Abstract Artificial neural networks are becoming in
Daoyuan Zhai, Jerry M. Mendel, Feilong Liu, University of Southern
California                                                                Abstract This paper is based on a relatively simple
Guohua Gao, SPE, Chevron Corp.; Mohammad Zafari, SPE,
Schlumberger; and Albert C. Reynolds, SPE, U. of Tulsa                    Summary The well known PUNQ-S3 reservoir mo
C.S. Kabir, SPE, Chevron ETC, and B. Izgec, SPE, Texas A&M U.             Abstract This paper presents a simple diagnostic
C.S. Kabir, SPE, Chevron ETC; S.B. Gorell, SPE, Landmark Graphics;
M.E. Portillo, SPE, University of Texas/Chevron; and A.S. Cullick, SPE,
Landmark Graphics                                                         Summary Well-developed methodology exists for
C.D. Wehunt, SPE, Chevron Energy Technology Co.                           Summary����������ï¿
Olaoluwa Adepoju, SPE, Olufemi Odusote, SPE, and Djuro Novakovic,
SPE, Chevron Nigeria Limited                                              Abstract A reliable production forecast is a critical
B. G�yag�ler, Chevron, and A.T. Papadopoulos, and J.A. Philpot,
Schlumberger                                                              Abstract Control systems with feedback controller
Masroor M. Chaudhri, SPE, Chevron Energy Technology Company,
Hemant A. Phale, SPE, University of Oklahoma, Ning Liu, SPE, Chevron
Energy Technology Company, Dean S. Oliver, SPE, University of
Oklahoma                                                                  Abstract For oil reservoirs under water and/or gas
Xian-Huan Wen, SPE, and Wen H. Chen, SPE, Chevron Corp.                   Summary The ensemble Kalman Filter technique

Xian-Huan Wen and Wen H. Chen, Chevron Energy Technology Company Summary The concept of closed-loop" reservoir m
P. Sarma and W.H. Chen, Chevron Energy Technology Company, CA,
USA                                                                  Abstract Efficient history matching (model updatin
William J. Milliken, Marjorie Levy, and Sebastien Strebelle, Chevron
Energy Technology Company; and Ye Zhang University of Michigan       Abstract The application of reservoir simulation as

W.S. Meddaugh, SPE, Chevron Energy Technology Co.                         Abstract Scoping studies using data from three m

C. Amudo, SPE, Chevron Australia Pty Ltd; T. Graf, SPE, and R.
Dandekar, SPE, Schlumberger; and J.M. Randle, SPE, Chevron Vietnam        Abstract With the dearth of easy oil in the industry
H.A. Tchelepi, SPE, Stanford U.; P. Jenny, ETH Z�rich; S.H. Lee, SPE,
and C. Wolfsteiner, SPE, Chevron ETC                                      Summary A multiscale finite-volume (MSFV) fram
J. Kozdon, SPE, Stanford University; B. Mallison, SPE, Chevron ETC; M.
Gerritsen, SPE, Stanford University; and W. Chen, SPE, Chevron ETC         Abstract Multidimensional transport for reservoir s
Cengiz Satik, Mridul Kumar, Sam DeFrancisco, Viet Hoang, and Mike
Basham, Chevron Energy Technology Company                                  Summary A comprehensive numerical modeling s
S.F. Matringe, SPE, Stanford, R. Juanes, SPE, Massachusetts Institute of
Technology, and H.A. Tchelepi, SPE, Stanford                               Summary The accuracy of streamline reservoir sim
H. Cheng, SPE, D. Oyerinde, SPE, and A. Datta-Gupta, SPE, Texas A&M
U., and W. Milliken, SPE, Chevron Energy Technology Co.                    Abstract Reconciling high-resolution geologic mo

Adedayo Oyerinde, SPE, Akhil Datta-Gupta, SPE, Texas A&M University,
and William Milliken, SPE, Chevron Energy Technology Company               Abstract Streamline-based assisted and automatic
Ajay K. Samantray, Shell; Qasem M. Dashti, SPE, and Eddie D.C. Ma,
Kuwait Oil Co.; and Pradeep S. Kumar, SPE, Chevron Intl. E&P               Summary Nine multimillion-cell geostatistical earth
M.K. Choudhary, SPE, and S. Yoon, SPE, Chevron Energy Technology
Co., and B.E. Ludvigsen, Scandpower PT                                     Abstract Subsurface uncertainties have a major in
N. Rivera, SPE, N.S. Meza, J.S. Kim, SPE, P.A. Clark, SPE, R. Garber,
and A. Fajardo, Chevron, and V. Pe�a, Ecopetrol                          Abstract Structural stratigraphic and petrophysic
Xian-Huan Wen, SPE, Chevron Energy Technology Co.; and Yuguang
Chen, SPE, and Louis J. Durlofsky, SPE, Stanford U.�                     Summary Upscaling is often applied to coarsen de
S.H. Lee, SPE, Chevron Energy Technology Company, and X. Wang,
SPE, H. Zhou, SPE, and H.A. Tchelepi, SPE, Stanford University             Abstract We propose an upscaling method that is
B. Izgec, SPE, Chevron ETC/Texas A&M University and C.S. Kabir, SPE,
Chevron ETC                                                                Abstract This work presents a complete reformula
C.S. Kabir, SPE, Chevron Energy Technology Co., and A.R. Hasan, SPE,
U. of Minnesota-Duluth                                                     Summary Predicting long-term reservoir performa
Yula Tang and Martin Wolff, Chevron Energy Technology Company, and
Patrick Condon and Katharine Ogden, Chevron International E&P
Company                                                                    Abstract The Banzala Field (Block 0 Angola) has p
A.R. Hasan, SPE, University of Minnesota–Duluth; C.S. Kabir, SPE,
Chevron ETC; and X. Wang, SPE, Baker Hughes                                Abstract This paper presents an analytic model for

A.R. Hasan, SPE, University of Minnesota–Duluth; C.S. Kabir, SPE,
Chevron ETC; and M. Sayarpour, SPE, University of Texas at Austin          Abstract This study presents a simplified two-phas

X. Yi, H.E. Goodman, R.S. Williams, W.K. Hilarides, Chevron Corp.          Abstract Kotabatak field Sumatra Indonesia is a h


K. Yoshioka, Chevron ETC; D. Zhu, and A.D. Hill, Texas A&M University;
P. Dawkrajai, Thailand Defense Energy Department; and L. W. Lake,
University of Texas at Austin                                              Summary With the recent development of temper

X. Yi, Chevron Corporation                                                 Abstract Fault reactivation induced by excessive re

Liyong Li, SPE, Chevron, and Hamdi A. Tchelepi, SPE, Stanford U.           Summary An inversion method for the integration

O.Izgec, D.Zhu, A.D.Hill, SPE, Texas A&M University                        Abstract Previously we have studied the acidizatio
Elizabeth J. Spiteri, SPE, Chevron Energy Technology Company; Ruben
Juanes, SPE, Massachusetts Institute of Technology; Martin J. Blunt,
SPE, Imperial College London; and Franklin M. Orr, Jr., SPE, Stanford
University                                                                 Summary The complex physics of multiphase flow
Elizabeth Zuluaga* and Larry W. Lake, University of Texas at Austin, SPE
* Now with Chevron Energy Technology Company                                 Summary Dry gas injected into wells will vaporize

Whitaker, A.E., Kabir, C.S., and Narr, W., Chevron ETC                       Abstract The extent to which fractures affect fluid p
Michael Brul�, Technomation; Yanni Charalambous, Oxy; Mark L.
Crawford, ExxonMobil Global Services Company; and Charles Crawley,
Chevron                                                                      Abstract For the past several years the problem o
Frank Close, Bob McCavitt, and Brian Smith, Chevron North America E&P
Company                                                                      Abstract Chevron's role as a major player in the gl
Richard Kopps, Rama Venkatesan, Jeff Creek, and Alberto Montesi,
Chevron Energy Technology Company                                            Abstract The Flow Assurance strategy is crucial in
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.; M. K�hler, SPE, Gaz de France; S. Marino,
SPE, Schlumberger; G. Nitters, SPE, Shell; D. Norman, SPE, Chevron
Corp.; and G. Turk, SPE, BP America Inc.                                     Abstract This paper summarizes part of the resul
Syed Ali, SPE, Chevron Energy Technology Co., Tommy Grigsby, SPE,
and Sanjay Vitthal,* SPE, Halliburton Energy Services Inc. *Currently with
Shell Corp.                                                                  Summary Technological advancement in horizont
Suk Kyoon Choi, SPE, The University of Texas at Austin, and Liang-Biao
Ouyang, SPE, and Wann-Sheng (Bill) Huang, SPE, Chevron Energy
Technology Company                                                           Abstract Inflow performance is one of the significan
Steven K. Cheung, Chevron Energy Technology Co.                              Abstract Many wells and reservoirs are premature
Amna Ali, SPE, Ian Taggart, SPE, Benjamin Mee, Megan Smith and
Andre Gerhardt, Woodside Energy Ltd. and Laurent Bourdon, Shell
Development (Australia)                                                      Abstract The Enfield field has a 160 m oil column

B. Izgec, SPE, Chevron ETC/Texas A&M U.; M.E. Cribbs, SPE, Chevron
North America & Exploration; S.V. Pace, SPE, Chevron ETC; D. Zhu,
SPE, Texas A&M U.; and C.S. Kabir, SPE, Chevron ETC                          Summary This paper probes the gauge-placemen

Liang-Biao Ouyang, SPE, Chevron Energy Technology Company                    Abstract Production logging (PLT) has been routin

C.S. Kabir, SPE, and B. Izgec, SPE, Chevron ETC; A.R. Hasan, SPE, U.
Minnesota-Duluth; and X. Wang, SPE, and J. Lee, SPE, Baker Hughes            Abstract Distributed temperature sending or DTS

Liang-Biao Ouyang, SPE, Chevron Energy Technology Company; Polpipat
Suthichoti, SPE, Chevron Thailand Exploration & Production Company  Abstract Production logging (PLT) has been routin

Liang-Biao Ouyang, SPE, Chevron Energy Technology Company; Polpipat
Suthichoti, SPE, Chevron Thailand Exploration &Production Company            Abstract Production logging (PLT) has been routin
B. G�yag�ler and T. Byer, Chevron                                        Summary Determination of the operating condition
Himansu Rai, SPE, and Roland N. Horne, SPE, Stanford University              Abstract Permanent downhole gauge data provide
D.K. Nath, Halliburton Energy Services; Riki Sugianto, PT Chevron Pacific
Indonesia; and Doug Finley, Halliburton Energy Services                      Summary The world’s largest steamflood ope
Karen Whittlesey, SPE, and James Logan, SPE, Chevron, and Huw
Rossiter, SPE, Halliburton                                                   Abstract In Chevron's Gulf of Thailand (GOT) ope
A. Badruzzaman, SPE, Chevron Energy Technology Company; T.
Badruzzaman, Pacific Consultants & Engineers; and M.F. Morea and D.J.
Julander, Chevron North America E&P Company                                  Abstract We discuss our experience to date with th
R. Martin Terrado, Suryo Yudono, and Ganesh Thakur, Chevron Energy
Technology Company                                                           Summary This paper illustrates how practical app
Peter Schipperijn, SPE, Chevron Energy Technology Company; Raymond
Thavarajah, SPE, and Ana Simonato, SPE, Chevron North America
Exploration and Production Company; and Mohsen Mehdizadeh, SPE,
Science Application International Corporation (SAIC)                           Abstract The increased need to maximize product
W. Lin, SPE, G.-Q. Tang, SPE, and A.R. Kovscek, SPE, Stanford
University                                                                     Abstract Our study has two features. First laborato
Nikola Maricic, SPE, Chevron Corporation; Shahab D. Mohaghegh, SPE,
and Emre Artun, SPE, West Virginia University                                  Summary Recent years have witnessed a renewe

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

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
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
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
Lloyd Simms III and Brad Clarkson, Halliburton, and Gilbert Navaira,
Chevron                                                                        Abstract With Gulf of Mexico (GOM) hydrocarbon d
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
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

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
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
Liang-Biao Ouyang, SPE, Chevron Energy Technology Company              Abstract Well completion plays a critical role in the

R.A. McCarty, SPE, Chevron IE&P, and W.D. Norman, SPE, Chevron ETC             Abstract This paper documents the utilization of fr
Jairam Kamath, Chevron                                                         Distinguished Author Series articles are general d
Myeong Noh* and Abbas Firoozabadi, SPE, Reservoir Engineering
Research Institute (RERI) * now with Chevron Corporation                       Summary Gas-well productivity is affected by two
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
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

Yula Tang and W.S. (Bill) Huang, Chevron Energy Technology Company             Abstract A dual-lateral well was completed in a Ch

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
E. Zuluaga and J.H. Schmidt, Chevron ETC, and R.H. Dean, Simwulf
Systems                                                                   Abstract Cavity completions have been widely use
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
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
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

Yula Tang, W.S. (Bill) Huang, Chevron Energy Technology Company           Abstract Open-hole Gravel packing is increasingly
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
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
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
David Underdown, SPE, Chevron; Henky Chan, SPE, Chevron Pacific
Indonesia                                                                 Summary The Duri field in Sumatra Indonesia sh
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
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
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
Myeong Noh* and Abbas Firoozabadi, RERI *currently with Chevron
Corporation                                                               Summary Liquid blocking in some gas-condensate
Akshay Sahni, SPE, Ken Kelsch, SPE, Hathaiporn Samorn, and
Chalatpon Boonmeelapprasert, SPE, Chevron                                 Abstract Interpreting pressure transient tests in co

A.K. Ambastha, SPE, and M. Anderson, SPE, Chevron Corp.; H. Gandhi,
SPE, Kuwait Oil Co.; and P.-D. Maizeret, SPE, Schlumberger                Abstract Mauddud reservoir in the Greater Burgan

Medhat M. Kamal and Yan Pan, Chevron Energy Technology Company            Abstract A new well testing analysis method is pres
Xianjie Yi, James E. Sabolcik, and Harvey E. Goodman, Chevron Energy
Technology Company, and Brent W. Walton, Chevron International
Exploration & Production Company                                          Abstract Sand control decisions are often made ba
he long tradition of innovative production growth and enhancement projects in the Greater Ekofisk Area in 2004 ConocoPhillips Norway AS (
any phases of expansion the Kuparuk hydrocarbon miscible water-alternating-gas (MWAG) project has grown from 10 patterns on 2 drillsites
 oPhillips Alpine facility on the Alaskan North Slope has experienced slugging problems severe enough to trip the high-high inlet separator le
 s gathering networks require large capital investments in wells subsea equipment pipelines and compression systems. Generally the optim
dustry invests billions of dollars in oil and gas production from deep waters the concern for flow assurance of reservoir fluids to the surface a
  examines the behavior of heavy oil reservoirs developed with horizontal and multilateral wells.�Advanced decline curve analyses were us
 ow a variety of ways to achieve higher recovery factors from heavy oil reservoirs but most of them involve the injection of thermal energy or c
  ips China Inc. (COPC) operates the Penglai 19-3 oil field located offshore in Bohai Bay the People’s Republic of China. COPC holds a
ples of reaction-diffusion processes are encountered in enhanced heavy oil recovery applications. A typical instance of such a process is whe
 ars several Steam Assisted Gravity Drainage (SAGD) projects have proven effective for the recovery of heavy oil and bitumen and Expandin
 and for oil grows the petroleum industry is expanding the technology envelope to access and exploit many unconventional resources.� Th
  ps Indonesia Inc. Ltd. is producing oil and gas in various locations in Indonesia both on and offshore. This paper covers work performed in t
  f gas potential in low permeability reservoirs (< 0.1 md) generally referred to as Tight Gas reservoirs is not verystraight forward as in convent
  ractures and faults associated with larger reservoir scale faults affect both permeability and permeability anisotropy and hence may play an
  ices and oil companies have long been interested in acquiring the capability of landing a well accurately in a hydrocarbon reservoir and rema
nt of formation evaluation technologies for azimuthal deep-reading measurements and accurate and flexible 3D rotary steerable drilling syste
  escribes the experience and lessons learned to acquire logging while drilling (LWD) formation pressure and near-wellbore mobility data in B
mation pressure testing while drilling (FPWD) tools provide accurate formation pressure measurements even under very challenging drilling a
 ield is located offshore Qatar with primary oil production from the Reservoir-X carbonates. In 2005 and 2006 Qatar Petroleum recognized th
 ed flow performance of Steam Assisted Gravity Drainage (SAGD) well pairs is sensitive to the spatial distribution of permeability. �A numb
   structure of the PL19-3 field which is located in Bohai Bay is an asymmetrical wrench anticline that formed by a combination of differential
 eld Development Plan (FDP) for Betty Field was prepared based on a process that was simultaneously sensitive to reservoir and operational
 ed oil field like Bahrain Field with a long production history it is required to identify underperforming areas infill wells and upgrade the reserve
 results from capital or operational investments are often difficult to identify and quantify due to a field’s decline and other factors that intro
National Offshore Oil Corporation (CNOOC) Shell and ConocoPhillips China Inc. (COPC) are partners in the development of the XJG oil fie
 simulation model calibrated with 25 years of production history was used to determine a cost effective reservoir management and productio
 eam chamber that developed during the circulation phase of a Steam Assisted Gravity Drainage (SAGD) process impacts the efficiency of bi
n of the linear system of equations for a large scale reservoir simulation has several challenges. Preconditioners are used to speed up the co
  ars there has been a resurgence in developing new solver technologies for addressing highly complex and large-scale flow simulations on s
  eservoir simulators cannot capture the complicated interactions between fluid production and reservoir rock deformation during hydrocarbon
  resents a coupled geomechanics and compositional model and applies it to the oil and gas recovery process. An equation of state composit
  tem production-optimization model has been implemented in a complex gas lifted offshore operation resulting in production gains and opera
   e for the sequential generation of perpendicular-bisectional (PEBI) grids adapted to flow information is presented and applied. The procedur
nd reliable downhole data acquisition has been made possible by advanced permanent monitoring systems such as downhole pressure and t
 sisted gravity drainage (GAGD) process is being developed to overcome the limitations of and as an alternative to the conventional WAG p
  sisted Gravity Drainage (GAGD) process developed at LSU is designed to take advantage of gravity to allow vertical segregation between
 /matrix transfer and fluid flow behavior in fractured carbonate rock was experimentally investigated using magnetic resonance imaging (MRI)
™s North Slope and the United Kingdom North Sea were petroleum frontiers in the truest sense around 1960 when industry gained access to
ubstantial volumes of unconventional gas resources in China including tight gas sands and coal bed methane (CBM). Rapid economic growt
 d reliable downhole data acquisition has been made possible by advanced permanent monitoring systems such as downhole pressure and te
 eristics of XSAGD that accelerate bitumen recovery and improve thermal efficiency are discussed in this simulation study. First it is well und
 ance analysis�is a fundamental technique for estimating gas-in-place.� It can be achieved using: 1) Static material balance using static
 wn that absolute permeability changes occur in coalbed methane (CBM) reservoirs during primary depletion or enhanced recovery/CO2 sequ
 vances in production data analysis (PDA) techniques have greatly assisted engineers in extracting meaningful reservoir and stimulation infor
    sequential phases comprise a recommended process for coalbed methane (CBM) prospect assessment: initial screening reconnaissance
  hoe Canyon (HSC) CBM play of the Western Canadian Sedimentary Basin is unique to low-rank coal reservoirs because of lack of water pro
an basin Fruitland coalbed methane (CBM) resource is the most significant CBM play discovered in the world to date and comprises areas w
  nal shale gas reservoirs have become a very important part of the resource base throughout the world but especially in the United States. P
 œunconventional reservoir has different meanings to different people. Certain reservoirs termed unconventional have a rock matrix consistin
urray formation consists of heterogeneous Cretaceous-bitumen-saturated sands. The reservoirs are thick and laterally extensive in the main
 owered jet pumps (FPJP) were pioneered for use in Kuparuk Field wells on the North Slope of Alaska. Unlike conventional surface powered
pletions for SAGD1 producers are unique. Conventional gas lift valves and mandrels with a packer completion cannot be used due to the ext
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
 eld located on the North Slope of Alaska was developed using open-hole horizontal completions drilled along the maximum principle stress a
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
 raulic fracturing has been successfully applied in tight gas reservoir development. Economic completion of tight gas sands with large hydrau
 e River field represents the first widespread and successful application of horizontal openhole completions on the North Slope of Alaska and
 and subsequent results of a hydraulic fracturing test performed on a large block of high modulus and low permeability rock (Colton sandston
 aces around the world notably the North Sea and the Middle East carbonate reservoirs are being accessed with very long horizontal wells (2
 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
 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
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
 eld case examples this paper presents our current well construction and completion design analysis based on the following approach: (1) ca
ombination of analytical calculations and 3D finite-element simulation we have developed a comprehensive skin-factor model for perforated h
an acid fracture treatment is to generate a highly conductive pathway of sufficient length from the reservoir to the wellbore. Depth of penetrat
uction from gas condensate reservoirs significant productivity loss occurs after the pressure near the production wells drops below the dew p
eness of heat injection into a target formation has a great impact on the efficiency of bitumen and heavy oil recovery and energy savings und

 ractured reservoirs determining fracture properties such as size and permeability is difficult due to the limited data about the fractures. The


 nsional (2D) NMR techniques have been proposed as efficient methods to infer a variety of petrophysical parameters including mixed fluid s

 of effective permeability at the reservoir scale has been a long standing challenge in carbonate fields.� The carbonate depositional and dia
  Series articles are general descriptive representations that summarize the state of the art in an area of technology by describing recent deve

mages are numerical representations of geological conceptual models that provide prior information on reservoir architecture. A new emergin


 roduction from gas-condensate wells requires an accurate relative permeability model when a condensate bank forms. At high flow rates typ



 ntalization is perhaps the single biggest risk factor in deepwater petroleum production. Downhole fluid analysis (DFA) is a new tool to reduce

ment of gas and condensate relative permeabilities typically is performed through steady-state linear coreflood experiments using model fluids

us imbibition and coreflood experiments were conducted on samples from two diatomaceous oil reservoirs to measure oil recovery as a funct

 tructure and mineral composition of diatomaceous reservoir core were analyzed in concert with core-scale thermal recovery tests. Samples f


ocene reservoir at Wafra Field was discovered in 1954 and has produced about 290 million barrels of 17-19� API high sulfur oil.� The d
 of gas/condensate reservoirs presents considerable challenge from day-to-day reservoir-management's perspective. Initially uncertainty an


c-age Humma Marrat carbonate reservoir is mainly located in the southwest corner of the Partitioned Neutral Zone (PNZ) between Saudi Ara


 n deepwater Gulf of Mexico is a three-way anticlinal structure trapped against salt with primary hydrocarbon-bearing turbidite sands ranging
ect in deepwater Gulf of Mexico is a three-way anticlinal structure trapped against salt with primary pay sands ranging from 24 000 to 27 00


g oil recovery in thin and ultrathin (< 30 ft) oil columns is a challenge because of coning or cresting of unwanted fluids regardless of well orie

gement (FM) is the simulation workflow through which predictive scenarios are carried out to assist in field development plans surface facility

opment teams have the responsibility of identifying evaluating and executing infill well opportunities. In maturing these projects realistic fore

 resents the process of candidate well selection design execution and evaluation that lead to the successful implementation of acid fracturin

 r is scarce its value increases. Produced water is the largest byproduct in oil and gas production and as a field matures the ratio of water
ocarbon production in the Gulf of Thailand has matured managing associated produced water has become a focus of attention. Produced w


u 6S and 3S oil fields in the Pearl River Basin Offshore South China Sea are mature fields which have produced 40% to 60% of their origina

al field is a 1.2 B bbl OOIP asset located onshore in Argentina South America. The field was discovered in 1991. Water injection started in 1


bjective of any project evaluation is to understand the fundamental economic value and the uncertainty in that value. The uncertainty in value


c-age Humma Marrat carbonate reservoir was discovered in 1998. Eleven wells have been drilled to date including several horizontal comple

 l field cases a neural-network model was developed to identify candidate wells and predict well performance for water shutoff treatments us
  a methodology of converting standard reservoir models to maps of production potential for screening regions that are most favorable for we

al petroleum-production optimization problem falls into the category of optimal control problems with nonlinear control-state path inequality c

voir management decision taken throughout the life of a reservoir is the determination of optimal well locations that maximizes asset value (s

mponent of waterflood management is the ability to proactively determine the impact of injection rates on the reservoir pressure and the cap

ow is associated with production from both gas-condensate and geothermal wells. Oil wells also experience it during high-gas-to-oil-ratio (hig

 an attempt to justify the increased performance of an assisted history matching experiment with plausible concepts. These concepts were b

ory matching of geologically complex reservoirs is important in many applications but it is central in closed-loop reservoir modeling in which


- scale history- matching problems optimization algorithms which require only the gradient of the objective function and avoid explicit compu

tic framework for dynamic data integration (history matching) has become accepted practice. The idea is to build an ensemble of reservoir m


 n strategies traditionally attempt to combine and balance complex geophysical petrophysical thermodynamic and economic factors to deter


ance-resistive model (CRM) offers the promise of rapid evaluation of waterflood performance. This semianalytical modeling approach is a ge
of fast simple and yet powerful analytic tools capacitance-resistive models (CRMs) are demonstrated with four field examples. Most waterfl


applications of chemical flooding become more attractive with higher oil prices. Several pilot and commercial scale chemical floods are curre

e the construction of a general unstructured grid parallel fully-implicit simulator for complex physics associated with heavy oil thermal recove

describes a general formulation for phase-component partitioning that can accommodate any number of phases and components any comp


              Number Concept

 history matching or data assimilation dynamic data such as production rates and pressures are used to constrain reservoir models and to u

 (4D) seismic can be effectively integrated into the reservoir management process by embedding the calculation of seismic attributes in a flow




 resents an integrated production model construction and forecasting workflow along with three practical real field applications from the Jack


r presents a transient wellbore simulator coupled with a semianalytic temperature model for computing wellbore-fluid-temperature profiles in
ost collected within the oil industry is the rate-time data. This data is analyzed with decline curve to primarily determine well/reservoir remaini

oil reserves in the giant carbonate field of interest reside in the fractured regions of the reservoir. The extensive fractures pose significant ch

 is often needed in reservoir simulation to coarsen highly detailed geological descriptions. Most existing upscaling procedures aim to reprodu


ods were introduced to solve control-volume formulations on general simulation grids for porous media flow. While these methods are gener

 flow curve (fw versus Sw) is used to describe the immiscible fluid displacement process.� Developing a representative fractional flow curv

r investigates the accuracy of first- and high-order numerical methods in simulating enhanced condensate processes in 1D 2D and 3D. We
r probes the usefulness of establishing the traditional time-variant absolute-open-flow potential (AOFP) on a given well. Our contention is tha

eservoir is one of the four main reservoirs in the Greater Burgan field the world’s largest sandstone oil field.� It has experienced signi

ances in multiscale methods have shown great promise in modeling multiphase flow in highly detailed heterogeneous domains.�Existing m

r presents a mathematical model describing the variation of temperature along the length of a horizontal well during the process of water inje

g injector-producer relationships i.e. to quantify the inter-well connectivity between injectors and producers in a reservoir is a complex and n

n the probabilistic forecasting and decision making process for their Captain North Sea heavy oil asset Chevron has developed an Integrate

 describes the design and implementation of a prototype toolkit that demonstrates Integrated Asset Management (IAM) functionality through


 a simple and quick material balance method is preferred to using a numerical simulation model. This preference can be justified when prepa
nd simulated models have revealed that in some cases waterdrive gas reservoirs can be mistakenly misidentified using material balance me

 ment decisions made during the early stages of exploration and development activities have the capability to improve later placement decisi

 illing technology has been widely and successfully applied to construct multilateral wells in reservoirs. This paper presents several field appli

 reservoir management although the intent is generally the maximization of some key quantity (net present value or NPV etc.) the operating


r presents an innovative methodology to integrate prior geologic information well-log data seismic data and production data into a consisten

describes a hybrid finite volume method designed to simulate multi-phase flow in a field-scale naturally fractured reservoir. Lee et al. (WRR

gical complexity of fractured reservoirs requires the use of simplified models for flow simulation. This is often addressed in practice by using


 logical characterizations of naturally fractured reservoirs are commonly in the form of discrete fracture models in which each fracture is defi

ature difference between the wellbore drilling mud and the formation especially in deep wells causes volumetric expansion of pore fluid and

ral networks are becoming increasingly popular in the oil and gas industry. In the past studies have been done on the use of artificial neural

s based on a relatively simple parametric model that characterizes the system function between a specific producer and each of its contributi

nown PUNQ-S3 reservoir model represents a synthetic problem which was formulated to test the ability of various methods and research gro
presents a simple diagnostic tool to identify reservoir flow behavior from a Cartesian pressure/rate graph. Some of the benefits of the propo


oped methodology exists for handling uncertainty for a single reservoir. However development of multiple fields presents a significant challe
�������������������������� This paper shows how to evaluate we

 oduction forecast is a critical part of the planning and decision making of companies in the oil and gas industry. The forecasts form part of a

 ems with feedback controllers are useful in reservoir simulation as they enable the maintenance of desired operating conditions of a field. Th



voirs under water and/or gas drive it is challenging and rewarding to effectively manage the water/gas fronts to maximize the sweep efficienc
mble Kalman Filter technique (EnKF) has been reported to be very efficient for real-time updating of reservoir models to match the most curre

 pt of closed-loop" reservoir management is currently receiving considerable attention in the petroleum industry. A "real-time" or "continuous"

tory matching (model updating) of geologically complex reservoirs is important in many applications but it is central in closed-loop reservoir m

ion of reservoir simulation as a tool for reservoir development and management is widespread in the oil and gas industry. Moreover it is reco

udies using data from three mature fields suggest that simple workflows that use only essential stratigraphic and facies constraints are as g


arth of easy oil in the industry the importance of consistency in quantifying uncertainties and assessing their impact on investment decisions

ale finite-volume (MSFV) framework for reservoir simulation is described. This adaptive MSFV formulation is locally conservative and yields a
 ional transport for reservoir simulation is typically solved by applying 1D numerical methods in each spatial coordinate direction. This approa

hensive numerical modeling study was performed to investigate impact of pattern confinement on steamflood simulation results using a thre

acy of streamline reservoir simulations depends strongly on the quality of the velocity field and the accuracy of the streamline tracing method

g high-resolution geologic models to field production history is still by far the most time-consuming aspect of the workflow for both geoscient


based assisted and automatic history matching techniques have shown great potential in reconciling high resolution geologic models to prod

million-cell geostatistical earth models of the Marrat reservoir in Magwa field Kuwait were upscaled for streamline (SL) screening and finite-

 uncertainties have a major influence on investment decisions in major capital projects. By understanding and quantifying subsurface uncerta

stratigraphic and petrophysical uncertainties result in a wide range of geologic interpretations. For fields with long production and pressure

is often applied to coarsen detailed geological reservoir descriptions to sizes that can be accommodated by flow simulators. Adaptive local-g

e an upscaling method that is based on dynamic simulation of a given model in which the accuracy of the upscaled model is continuously mo

resents a complete reformulation of the Hall method involving both pre- and post-breakthrough situations. Two approaches involving both tra

 long-term reservoir performance with realistic wellbore models is fraught with uncertainty owing to the complexity of two-phase flow. That is


 Field (Block 0 Angola) has produced oil with horizontal wells and ESP’s as the artificial lift method for more than seven years. These w

 resents an analytic model for computing the wellbore-fluid-temperature profile for steady fluid flow. Although wells with constant-deviation an


resents a simplified two-phase flow model using the drift-flux approach to well orientation geometry and fluids. For estimating the static hea

eld Sumatra Indonesia is a heavily-faulted field undergoing an aggressive drilling and development campaign. Nine horizontal wells had bee




ecent development of temperature measurement systems such as fiber-optic distributed temperature sensors continuous temperature profil

ation induced by excessive reservoir steam pressure in heavy oil fields is suspected as one of the possible perpetrators that caused steam e

on method for the integration of dynamic (pressure) data directly into statistical moment equations (SMEs) is presented. The method is demo

we have studied the acidization of vuggy carbonates with acid core flood experiments in 4-inch diameter by 20-inch long cores high resolutio



 ex physics of multiphase flow in porous media are usually modeled at the field scale using Darcy-type formulations. The key descriptors of s
ected into wells will vaporize water from near the wellbore. The vaporization starts from the well and proceeds outward. Gas flowing to produ

o which fractures affect fluid pathways is a vital component of understanding and modeling fluid flow in any reservoir. We examined a Lower


several years the problem of reducing time-to-decision in field operations and capital projects has been repeatedly described and analyzed

ole as a major player in the global energy arena is due in large part to the Company’s extensive oil and gas exploration and production o

ssurance strategy is crucial in the early stages of development of subsea gas fields.� The key questions in early development are an optim




summarizes part of the results of an investigation of fracture clean-up mechanisms undertaken under a Joint Industry Project active since th


ical advancement in horizontal drilling and openhole completing techniques for soft-rock formations finally has bridged the gap between the


mance is one of the significant components to quantify the reservoir’s capability to produce hydrocarbon. There are two commonly-used
and reservoirs are prematurely abandoned due to excess water production resulting in lost production and recovery.� We need ways to d


field has a 160 m oil column located between a medium sized gas cap and a water/leg aquifer system. Enfield is undergoing an active water



r probes the gauge-placement issue with regard to yielding quality formation parameters unaffected by wellbore effects. Nonphysical or biase

ogging (PLT) has been routinely practiced in oil and gas industry to estimate oil water and/or gas production profile determine fluid entry or


emperature sending or DTS is gaining increasing popularity because of its potential to generate flow profiles over completed intervals. In fac


ogging (PLT) has been routinely applied in oil and gas industry to estimate phase production profile determine oil/gas/water producing layers


ogging (PLT) has been routinely practiced in oil and gas industry to estimate oil water and/or gas production profile determine fluid entry or
tion of the operating conditions of a field under a set of physical system constraints (e.g. compressor limits) and engineering preferences (e
downhole gauge data provide us with reservoir information in space and time and aid in well and reservoir management. Interpretation of pe

’s largest steamflood operation is conducted on the island of Sumatra in Indonesia. Fiber-optic distributed-temperature-sensing (DTS) su

s Gulf of Thailand (GOT) operations costs drive logging and formation evaluation. Programs for logging and evaluation are based on consid


our experience to date with the Carbon/Oxygen logging technique to determine vertical sweep in Belridge Diatomite in the Lost Hills Field. W

r illustrates how practical application of surveillance and monitoring principles is a key to understanding reservoir performance and identifyin
 ed need to maximize production from mature assets has resulted in the transformation of the oilfield surveillance workflow.� Hitherto wel

as two features. First laboratory experiments measured the change of the absolute permeability of a coal pack as a function of pore pressure

 ars have witnessed a renewed interest in development of coalbed methane (CBM) reservoirs. Optimizing CBM production is of interest to ma



 of improved Oil Recovery in mature fields is almost inevitable. However the method applied in the IOR process is dependent on the econom


 r explores multiple completion options in gas/condensate reservoirs with compositional simulations. Besides intelligent-well completion (IWC

 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

 is a relatively simple and cost-effective well completion technique for horizontal wells. However fluid flow into a slotted-liner completion is qu

 Mexico (GOM) hydrocarbon discoveries reaching record depths and very high bottomhole pressures the need for proven weighted fracturin



y and multiphase flow effects in hydraulic fractures have been well documented in the last several years. The pressure losses caused by thes

 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.




cumented in the literature that hydraulic fracture treatments although successful often underperform: Frac and Pack completions exhibit pos

microseismic array was utilized to perform hydraulic fracture diagnostics during stimulation of the Chevron Skinner Ridge (SR) #698-22-1 well
 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

 documents the utilization of fracpack completion technology for water injectors in sand control environments.� This paper is a look back a
 Series articles are general descriptive representations that summarize the state of the art in an area of technology by describing recent deve

 roductivity is affected by two distinct mechanisms: liquid blocking and high-velocity flow in two-phase flow. The former has been studied exte

             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


 water fields with a limited number of wells may require intelligent well systems to maximize production capacity under facility constraints. Agb

 al well was completed in a Chevron subsea condensate field with high peak rate. Within one year the production significantly declined with h


 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

letions have been widely used to increase productivity from non-conventional sources such as coalbed methane reservoirs and “heavy o


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



 remedial work such as through tubing perforation has been successfully carried out in most vertical/deviated wells. However in high angle/h
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

Gravel packing is increasingly becoming a standard practice in the deep-water subsea completion environment. A Chevron offshore gas res


emoval of small sand-sized solids is critical for successful drilling and completion operations in sand reservoirs. Recent experience in extend

mpletions in the Gulf of Mexico must typically address sand control. Our industry has made significant progress with respect to sand control e

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

eld in Sumatra Indonesia shown in Fig. 1 and operated by Chevron Pacific Indonesia (CPI) is one of the largest onshore steamflood opera


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


productivity loss occurs in gas-condensate wells when the bottom hole flowing pressure drops below the dewpoint pressure. The decline in p

 carbon dioxide (CO2)–foamed fracturing fluids were used to stimulate wells in the Waltman field in Wyoming—due to the low formation 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

 pressure transient tests in complex faulted and stratigraphic environments can be difficult. In fluvial depositional environments where sand c


 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

esting analysis method is presented. The method allows for calculating the absolute permeability of the formation in the area influenced by th


 decisions are often made based on a deterministically predicted Safe Drawdown Pressure (SDP) without proper regard to the amount of un
  in 2004 ConocoPhillips Norway AS (COPNo) implemented the Onshore Operations Centre (OOC). The OOC facilitates improved collaborat
 grown from 10 patterns on 2 drillsites (Small Scale EOR or SSEOR) to today’s 283 patterns on 32 drillsites. It now covers an area with
                                                                                        OnePetro
 to trip the high-high inlet separator level causing frequent plant shutdowns and loss of production of 110 kbbl/d.� A slugging study was co
                                                                                        OnePetro OnePetro
ession systems. Generally the optimum design for such systems can only be found by assessing multiple scenarios. Many scenarios may ha
                                                                                        OnePetro
 ce of reservoir fluids to the surface and their subsequent delivery to relevant markets becomes very critical to justifying project economics an
 nced decline curve analyses were used to characterize flow regimes and estimate the time to pseudosteady-state.� Reservoir and well p
                                                                                        OnePetro
ve the injection of thermal energy or chemicals to reduce the oil viscosity. While these techniques have been highly successful they can also
™s Republic of China. COPC holds a production sharing agreement with China National Offshore Oil Corporation (CNOOC). The Penglai 19-
cal instance of such a process is when a chemical diffuses through a fluid column and then undergoes reaction with another chemical specie
  heavy oil and bitumen and Expanding Solvent (ES) SAGD pilot projects have shown positive indications of improved performance. This pap
any unconventional resources.� The current focus of all major oil companies is heavy oil in highly porous and permeable sandstone reserv
 his paper covers work performed in the Belanak field offshore Indonesia. The field is located in Natuna Sea north of Indonesia near the bor
not verystraight forward as in conventional reservoirs. This study is focused on modeling permeability in the Travis Peak Formation where the
  y anisotropy and hence may play an important role in controlling the production behavior of a faulted reservoir. It is well known from geologic
  in a hydrocarbon reservoir and remaining in it for optimal drainage. Although traditional logging-while-drilling (LWD) propagation resistivity to
xible 3D rotary steerable drilling systems have made it possible to provide truly proactive well placement. Real time use of new and advanced
  and near-wellbore mobility data in Bohai Bay. This area is known to be difficult in terms of measuring key parameters for reservoir descriptio
                                                                                        OnePetro
 even under very challenging drilling and formation testing conditions. Pressure data from logging while drilling (LWD) tools are primarily used
2006 Qatar Petroleum recognized that future development of this mature field would require a modern state of the art reservoir model and
stribution of permeability. �A number of permeability measurements are taken from small scale core plug data.� The data may be taken
                                                                                        OnePetro
 rmed by a combination of differential subsidence strike-slip faulting and normal faulting. Faults form the main trapping components for the
sensitive to reservoir and operational constraints and uncertainties. This so called “Optioneering process was an iterative multidisciplinar
                                                                                        OnePetro
  s infill wells and upgrade the reserves. This paper describes the application of a practical process (1) to develop systematic workflow for pr
™s decline and other factors that introduce noise in the data. This was the case with a series of operational improvements in a tight gas field
                                                                                        OnePetro OnePetro
  in the development of the XJG oil fields in the South China Sea. The XJG fields are in a mature production phase and challenge COPC (the
                                                                                        OnePetro
 reservoir management and production strategy which optimises future recovery from an oil rim reservoir in the Betty Field offshore Malaysia
 ) process impacts the efficiency of bitumen recovery tremendously. The circulation phase during which both horizontal injector and producer
ditioners are used to speed up the convergence rate of the solution of such systems. In theory a preconditioner defines a matrix M that can b
 and large-scale flow simulations on specialized parallel and multicore architectures in a very effective manner. Methods such as algebraic m
                                                                                         when both
rock deformation during hydrocarbon recovery. In particular in a recovery process OnePetro phase behavior and deformation of reservoir ro
ocess. An equation of state compositional simulator called the General Purpose Adaptive Simulator (GPAS) developed at the University of T
  sulting in production gains and operating-cost reductions. Whereas previous optimization models considered only the wells and production-g
presented and applied. The procedure includes a fine-scale flow solution the generation of an initial streamline–isopotential grid grid optim
 ms such as downhole pressure and temperature gauges and fiber optic sensors. These downhole measurement instruments are increasingl
 ernative to the conventional WAG process. In our recent paper (SPE 110132) we have presented the visual model results to demonstrate th
o allow vertical segregation between the injected CO2 and reservoir crude oil due to the difference in their densities. The GAGD process use
g magnetic resonance imaging (MRI). Viscous oil-water displacements in stacked carbonate core plugs were investigated at wettability condi
1960 when industry gained access to both areas. Exploration of these two petroleum provinces progressed almost simultaneously with both
 thane (CBM). Rapid economic growth in China has increased the demand for more sources of clean energy such as natural gas from uncon
ms such as downhole pressure and temperature gauges and fiber optic sensors. These downhole measurement instruments are increasingly
                                                                                        OnePetro
s simulation study. First it is well understood that the significant oil mobilization process during SAGD occurs at the periphery of the steam c
1) Static material balance using static (shut-in) reservoir pressures where a plot of static �p/z versus cumulative gas production is created
etion or enhanced recovery/CO2 sequestration operations. Sorption-induced strain in CBM reservoirs also known as matrix-shrinkage or -sw
ningful reservoir and stimulation information from well-production and flowing-pressure data. Application of these techniques to coalbed-meth
  nt: initial screening reconnaissance pilot testing and final appraisal. A stepwise approach through these four phases provides for a program
  servoirs because of lack of water production; the production characteristics are qualitatively similar to conventional low-pressure dry gas res
world to date and comprises areas within both Colorado and New Mexico of the United States. It contains three distinctly different performanc
 but especially in the United States. Production data analysis techniques using various forms of material balance time originally put forth by P
  entional have a rock matrix consisting of inter-particle pore networks with very small pore connections imparting very poor fluid-flow characte
k and laterally extensive in the main fairways. Many commercial projects are in the early stages of development. Resources too deep to mine
Unlike conventional surface powered jet pumps these pumps are hydraulically powered by a prolific producing upper zone called the C sand
pletion cannot be used due to the extreme temperatures of the downhole environment. Most lift gas enters the production stream downhole v
 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
 along the maximum principle stress and dominant fault orientation (northwest/southeast). Open-hole completions were considered the best c
 The objective of the initiative is to increase the ultimate recovery in their respective chalk assets to 60%. Analyzing the different production t
  of tight gas sands with large hydraulic fracturing treatments requires cost effective and time saving operations. Traditional large fracturing jo
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
w permeability rock (Colton sandstone) are presented. The focus of this experimental study was to assess the effects of discontinuities on hy
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
nks block 783 in the Gulf of Mexico. The wells target multiple zones resulting in complex directional wells with 50�-60� maximum hole-a
                                                                                          OnePetro
 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
                                                     OnePetro
are applied to light oil and gas reservoirs the equations controlling generation of eroded solid mass or sand release rate are vastly simplified
 sed on the following approach: (1) carry out detailed evaluation or determination of reservoir formation strength distribution using core testing
sive skin-factor model for perforated horizontal wells. In this paper we present the mathematical model development and validation by compa
 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
oduction wells drops below the dew point of the hydrocarbon fluid. Many of these gas reservoirs also have some water accumulation near th
 oil recovery and energy savings under many steam heating processes such as the startup phase of SAGD (Steam Assisted Gravity Drainag

                                                  OnePetro
 limited data about the fractures. The primary information that is available mainly from image logs or core is known only at the wellbore; how


al parameters including mixed fluid saturation in-situ oil viscosity wettability and pore structure. However no study has been presented to q

½ The carbonate depositional and diagenetic history can be quite complex and this can lead to a permeability field which is quite difficult to c
                                                                                 in the topics
technology by describing recent developments for readers who are not specialists OnePetro discussed. Written by individuals recognized

eservoir architecture. A new emerging geostatistical approach named multiple-point statistics (MPS) simulation allows extracting multiple-po


ate bank forms. At high flow rates typical of many gas-condensate wells the relative permeability is rate dependent. Such rate dependence c



nalysis (DFA) is a new tool to reduce uncertainty associated with reservoir connectivity. Fluid data from DFA logs and various laboratory anal

 flood experiments using model fluids. This study addresses experimental measurement of relative permeabilities for a rich-gas/condensate

 rs to measure oil recovery as a function of temperature and to quantify changes if any in the rock fabric resulting from the flow of brine and

ale thermal recovery tests. Samples from two diatomaceous oil reservoirs were subjected to spontaneous and forced imbibition coreflood exp


                                                                                       OnePetro OnePetro
 -19� API high sulfur oil.� The dolomite reservoir is Eocene/Paleocene age.� The average porosity is 35% and the average permeab
s perspective. Initially uncertainty and variability of liquid content and volume of reserves in each reservoir pose difficulty in designing surfac


 utral Zone (PNZ) between Saudi Arabia and Kuwait. The reservoir was discovered in 1998. The reservoir depth is about 9000 ft subsea. The


arbon-bearing turbidite sands ranging from 24 000 to 27 000 ft TVD. The discovery well was drilled in 2002 and two appraisal wells were dr
                                                                                 OnePetro
 sands ranging from 24 000 to 27 000 ft TVD. The field contains several hydrocarbon-bearing turbidite sands. The discovery well was drilled


wanted fluids regardless of well orientation. Significant oil is left behind above the well completion even for horizontal wells when bottom- or

 ld development plans surface facility design/de-bottlenecking uncertainty/sensitivity analysis and instantaneous/lifetime revenue optimizatio

maturing these projects realistic forecasts are needed. An intrinsic part of these forecasts is the initial rate of production which influences th
                                                 OnePetro

                                                                                       treatment
ssful implementation of acid fracturing treatment in Marrat field. The acid fracturingOnePetro is quite challenging due to presence of high pre

s a field matures the ratio of water to oil produced increases. Excess produced water is the main reason for abandoning wells and declarin
me a focus of attention. Produced water management in an offshore environment requires innovation both from a surface facility and subsu


 roduced 40% to 60% of their original oil in place since 1991. Currently the field production is rapidly declining and water production is increas

d in 1991. Water injection started in 1993 with current infill drilling and development of some areas still taking place. This field consists of sev


n that value. The uncertainty in value is a function of numerous variables in both the surface and subsurface parts of a project which are often
                                                                                     OnePetro


e including several horizontal completions. The gross reservoir interval is about 235 m (730 feet) thick. The reservoir produces from three int

 ance for water shutoff treatments using polymer gels. A feedforward-backpropagation algorithm was used to develop the neural networks. T
egions that are most favorable for well placement.�A technique is developed to apply this method to the problem of field development whe

nlinear control-state path inequality constraints (i.e. constraints that must be satisfied at every time step) and it is acknowledged that such p

 ations that maximizes asset value (such as Net Present Value NPV). Because this well placement optimization problem is a discrete-param

n the reservoir pressure and the capacity to diagnose injection anomalies. The most reliable means of doing this is through the use of numer

nce it during high-gas-to-oil-ratio (high-GOR) production. The current semimechanistic modeling approach requires estimation of film thickne

ble concepts. These concepts were based on patterns within the error vector (the unique distributions of the error components). The observe

 ed-loop reservoir modeling in which real-time model updating is required. Within the context of closed-loop reservoir modeling the two appr


 ve function and avoid explicit computation of the Hessian appear to be the best approach. Unfortunately such algorithms have not been ext

s to build an ensemble of reservoir models all of which being consistent with the geologic scenario and also honoring all available (static and


                                              OnePetro
 namic and economic factors to determine an optimal method to recover hydrocarbons from a given reservoir. Reservoir simulators have trad


ianalytical modeling approach is a generalized nonlinear multivariate regression technique that is rooted in signal processing. Put simply a r
with four field examples. Most waterfloods lend themselves to this treatment. This spreadsheet-based tool is ideally suited for engineers who


ercial scale chemical floods are currently in operation or design. Economic feasibility of such projects relies on how cost-effectively the remai

 ociated with heavy oil thermal recovery. The primary focus of the simulator is on the physics associated with steam injection and Steam Ass

 phases and components any component existing in any phase and requires no special ordering of phases or components. This type of for




                                                                               OnePetro
 constrain reservoir models and to update model parameters. As such even if under certain conceptualization the model parameters do not

 culation of seismic attributes in a flow simulator. This paper describes a petroelastic model embedded in a multi-purpose flow simulator. The




 real field applications from the Jack asset located in deepwater Gulf of Mexico. Integrated production modeling is a composite modeling stra


wellbore-fluid-temperature profiles in flowing and shut-in wells. Either an analytic or a numeric reservoir model can be combined with the tran
arily determine well/reservoir remaining reserves. However rate-time data which is a form of extended well testing can also be used to estim

xtensive fractures pose significant challenges for reservoir characterization gridding discretization simulation and upscaling. In this work w

upscaling procedures aim to reproduce fine-scale results for a particular geological model (realization). In this work we develop and test a ne


low. While these methods are general in the sense that they may be applied to any grid their convergence properties vary. An important pro

g a representative fractional flow curve for a specific reservoir can be quite challenging when fluid and special core analysis data is limited.ï¿

te processes in 1D 2D and 3D. We compare the predictions of a standard single point upwind (SPU) scheme with a third-order accurate fin
on a given well. Our contention is that a well’s AOFP is not a measure of its future potential in a volumetric system owing to ever-declinin

 oil field.� It has experienced significant pressure decline after 60 years of primary production.� In 2005 design for a pressure maintena

                                                                             OnePetro
eterogeneous domains.�Existing multiscale methods however solve for the flow field (pressure and total-velocity) only. Once the fine-sca

 well during the process of water injection. The model is obtained from a theoretical treatment accounting for both mass transfer and heat tra

ers in a reservoir is a complex and non-stationary problem. In this paper we present a neural-network-based sensitivity analysis approach to

Chevron has developed an Integrated Asset Model (IAM). This model includes probabilistic predictions of facilities performance and produc

nagement (IAM) functionality through an integrated production and forecasting workflow. A graphical modeling environment specially configu


eference can be justified when preparing the development plan and production optimization for a collection of hydrocarbon reservoirs (lean a
identified using material balance methods as depletion drive gas reservoirs causing a significant overestimation in gas reserves. The famou

 ity to improve later placement decisions by providing more information (greater certainty). Therefore recovery and efficient use of informatio

                                                  OnePetro
his paper presents several field applications of the modeling of complex well architectures. A generalized semi-analytical segmented model

 ent value or NPV etc.) the operating parameters are seldom if ever determined using formal optimization techniques. The usual approach t


 and production data into a consistent 3D reservoir model.� Furthermore the method is applied to a real channel reservoir from the Africa

                                                                                OnePetro
fractured reservoir. Lee et al. (WRR 37:443-455 2001) developed a hierarchical approach in which the permeability contribution from short f

often addressed in practice by using flow modeling procedures based on the dual-porosity dual-permeability concept. However in most exis


models in which each fracture is defined explicitly. The efficient simulation of flow processes in such models poses a great challenge. In rece

olumetric expansion of pore fluid and rock matrix. Most existing models ignore the effect of convective heat transfer which is a valid assump

 n done on the use of artificial neural networks in reservoir characterization field development and formation damage prediction to name a fe

ic producer and each of its contributing injectors. The model has only two parameters for each producer-injector pair; so if N injectors are as

 of various methods and research groups to quantify the uncertainty in the prediction of cumulative oil production. Previous results reported o
ph. Some of the benefits of the proposed tool are its simplicity without requiring any calculations leading to understanding of reservoir comp


                                                                                    OnePetro
le fields presents a significant challenge when uncertainty in a large number of variables such as gas in place and liquid yield occur in each
This paper shows how to evaluate well performance under conditions of reservoir and completion uncertainty while also considering the impa

ndustry. The forecasts form part of a company’s business and strategic plans and form the basis of evaluating an existing asset major c

red operating conditions of a field. This in turn helps establish the value of implementing automated mechanisms in the field and also in dete



                                                 OnePetro
 onts to maximize the sweep efficiency. In the past a wide variety of approaches were developed and implemented for optimizing the reservo
ervoir models to match the most current production data. Using EnKF an ensemble of reservoir models assimilating the most current observ

                                                                                     OnePetro
ndustry. A "real-time" or "continuous" reservoir model updating technique is a critical component for the feasible application of any closed-loo

                                                                                      required.
 it is central in closed-loop reservoir modeling in which real-time model updating isOnePetro Within the context of closed-loop modeling one

 and gas industry. Moreover it is recognized that the results of any reservoir simulation model are strongly influenced by the underlying geolo

 phic and facies constraints are as good in capturing overall reservoir fluid flow response as complex highly constrained workflows that use


their impact on investment decisions have become very crucial in management decisions. This has seen the stocks of both experimental de

on is locally conservative and yields accurate results of both flow and transport in large-scale highly heterogeneous reservoir models. IMPES
 tial coordinate direction. This approach is simple but the disadvantage is that numerical errors become highly correlated with the underlying

 flood simulation results using a three-phase and 3D thermal reservoir simulator. In addition the effects of cyclic steaming of the producers

 acy of the streamline tracing method. For problems described on complex grids (e.g. corner-point geometry or fully unstructured grids) with f

ct of the workflow for both geoscientists and engineers. Recently streamline-based assisted and automatic history matching techniques hav


 h resolution geologic models to production data. However a major drawback of these approaches has been incompressibility or slight comp

 streamline (SL) screening and finite-difference (FD) flow simulation. The scaleup strategy consisted of (1) maintaining square areal blocks o
                                                                                   OnePetro

 g and quantifying subsurface uncertainties better investment risks can be reduced and decision quality can be improved.� Quantifying su

s with long production and pressure history 3D-dynamic simulations have been very useful in providing feedback to geologic modelers whi

d by flow simulators. Adaptive local-global upscaling is a new and accurate methodology that incorporates global coarse-scale flow informatio

e upscaled model is continuously monitored via indirect error-measures. If the indirect measures are bigger than a specified tolerance the up

 s. Two approaches involving both transient and material-balance methods produced very similar solutions which were verified with the resul

 omplexity of two-phase flow. That is because even a calibrated two-phase-flow model departs from its expected performance trend when ch


 for more than seven years. These wells were drilled with large sinusoidal undulations intentionally to cut the pay section a number of times.

ough wells with constant-deviation angle can be handled with existing analytic models complex well architectures demand rigorous treatmen


d fluids. For estimating the static head the model uses a single expression for liquid holdup with flow-pattern-dependent values for flow para

mpaign. Nine horizontal wells had been drilled with four more planned in 2008. One of the horizontal wells recently experienced well collapse




 nsors continuous temperature profiles in a horizontal well can be obtained with high precision. Small temperature changes with a resolution

ble perpetrators that caused steam eruption to the surface. This can lead to significant financial losses related to environment cleanup and c

 s) is presented. The method is demonstrated for incompressible flow in heterogeneous reservoirs. In addition to information about the mean

 by 20-inch long cores high resolution computerized tomography imaging image processing and geostatistical characterization. The obvious



ormulations. The key descriptors of such models are the relative permeabilities to each of the flowing phases. It is well known that whenever
 ceeds outward. Gas flowing to producers is in equilibrium with the reservoir brine but water will be vaporized because the pressure drop tha

any reservoir. We examined a Lower Cretaceous grainstone for which production extending over 50 years including recent horizontal drilling


n repeatedly described and analyzed in qualitative and anecdotal terms. In this paper we take an engineering approach to measure and unde

and gas exploration and production operations. A large proportion of the Company’s extensive reserves are located in deepwater locatio

ons in early development are an optimal tradeoff between managing risk effectively while ensuring deliverability and keeping CAPEX within a




a Joint Industry Project active since the year 2002. It is well documented in the literature that hydraulic fractures although successful often


 lly has bridged the gap between the drilling and completion disciplines.�The success achieved with openhole gravel packing has created a


 rbon. There are two commonly-used quantities to represent reservoir inflow performance: productivity index (PI) and inflow performance rela
and recovery.� We need ways to delay water production in new fields and to maximize efficiency in mature producing fields.� This talk


Enfield is undergoing an active water-flood utilizing both up-dip and down-dip water injection. The water-flood reservoir management of such



wellbore effects. Nonphysical or biased results may result if the wellbore effects are unaccounted for. We used a wellbore/reservoir simulator

uction profile determine fluid entry or exit location and amount along perforation interval(s) and detect major oil/gas/water producing layers.


ofiles over completed intervals. In fact several studies have reported successful reproduction of field data obtained with conventional produc


ermine oil/gas/water producing layers and detect major fluid entry or exit. Through successful PLT surveys and appropriate interpretation it


 ction profile determine fluid entry or exit location and amount along perforation interval(s) and detect major oil/gas/water producing layers. T
                                                                                      OnePetro
mits) and engineering preferences (e.g. voidage replacement) is a primary concern for petroleum engineers. Rule-based systems have been
oir management. Interpretation of permanent downhole gauge data is a fairly new problem and several outstanding issues remain in this are

 buted-temperature-sensing (DTS) surveys are used in the Sumatra fields to provide valuable data for reservoir management. The DTS profi
                                                                                 OnePetro

 and evaluation are based on consideration of perceived value and the potential for comprehensive utilization. Well lifespan is short and eco


ge Diatomite in the Lost Hills Field. We describe early interpretation challenges with overly optimistic saturation estimation. This required in-h

 reservoir performance and identifying opportunities that will improve ultimate oil recovery. Implementation of various principles recommende
 veillance workflow.� Hitherto wells were reviewed sequentially throughout the field on a calendar basis.� This was a time-consuming p

al pack as a function of pore pressure and injected gas composition at constant effective stress. Second adsorption solution theory describe

g CBM production is of interest to many operators. Drilling horizontal and multilateral wells is gaining popularity in many different coalbed res



process is dependent on the economics and value of the method. In the Southern Offshore area of Chevron operations there are huge cost


ides intelligent-well completion (IWC) options included commingling two reservoirs of contrasting conductivity (permeability-thickness produc

one with “good porosity.� Matrix permeability is low and natural fracture density can be quite variable in this reservoir.� Thus this re

w into a slotted-liner completion is quite complicated due to three dimensional flow convergence around slots and limited open-to-flow areas.

e need for proven weighted fracturing stimulation fluids has become urgent. As previous studies have shown frac packs have a significant



 The pressure losses caused by these phenomena are accepted widely to be of great significance in most gas-well completions in the United

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




rac and Pack completions exhibit positive skin values and traditional hydraulic fracture completions show discrepancies between the placed

n Skinner Ridge (SR) #698-22-1 well Williams Fork Formation (Late Cretaceous) Garfield County western Piceance Basin western Colora
                                                                                   OnePetro
pletion options are available for potential deployment in new wells especially those in deep water and offshore; however the cost could vary

                                                                                     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
technology by describing recent developments for readers who are not specialists in the topics discussed. Written by individuals recognized

w. The former has been studied extensively recently but the understanding of the latter is limited. High-velocity gas flow in single phase has


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


apacity under facility constraints. Agbami field a highly-dipping reservoir with many producing zones and few wells will use an intelligent wel

roduction significantly declined with high water-cut. The well was shut down and then brought back to production observing much reduced fl


 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

methane reservoirs and “heavy oil from weakly consolidated formations. In the 1990s the technique was applied to conventional wells wh


gentina. El Trapial wells are characterized by stratified shallow- to medium-depth reservoirs with permeabilities of 35md to 85md and poros



 iated wells. However in high angle/horizontal wells it has become a major undertaking due to inability of the gravity-assisted electric line to
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

onment. A Chevron offshore gas reservoir will be developed with high-angle near-horizontal wells with openhole gravel packs completion (O


                                                                                      transport OnePetro
servoirs. Recent experience in extended-reach drilling also indicates that inefficientOnePetro of smaller cuttings is a main factor for excessive

 ogress with respect to sand control equipment and implementation. However even properly designed and executed completions are subjec

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

he largest onshore steamflood operations in the world. Producing heavy oil (approximately 25�API) from an essentially unconsolidated res


 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


 dewpoint pressure. The decline in productivity is due to near-well accumulation of condensate in the reservoir rock which is significant even

 yoming—due to the low formation permeability and rock properties—and have been proven effective but still not perfect. Limitations on 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

ositional environments where sand continuity is a significant uncertainty pressure transient test interpretation can generate several non-uniq


one with “good porosity.� Matrix permeability is low and natural fracture density can be variable in this reservoir.� Thus this reservo

 ormation in the area influenced by the test and the average saturations in this area. The method applies to two-phase flow in the reservoir (o


                                                                                   OnePetro
 ut proper regard to the amount of uncertainty associated with the value of SDP. These uncertainties can be large when planning a Drillstem
 OOC facilitates improved collaborative working processes that optimise production and streamline operations through more proactive use o

0 kbbl/d.� A slugging study was commissioned to investigate the cause of the existing CD-2 pipeline slugging and possible mitigation pro


eady-state.� Reservoir and well parameters such as the OOIP Arps “b exponent decline rate reserves permeability and well produc

rporation (CNOOC). The Penglai 19-3 field is the second largest oil field in China with 3.8 billion bbl of oil in place discovered in May 1999 an
eaction with another chemical species. The reaction products further diffuse through the porous media. The challenges involved in modeling
s of improved performance. This paper presents the results of a simulation study performed to investigate important aspects of the ES-SAGD
ous and permeable sandstone reservoirs (oil sand) which presents a significant opportunity. However viscous oil trapped in carbonates (ove
Sea north of Indonesia near the border between Indonesia and Malaysia. The gas produced by the Belanak field is transported to Singapore
the Travis Peak Formation where there are many challenges. One may encounter low resistivity pay due to clay coated grains and alternating
  ervoir. It is well known from geologic studies that there is a concentration of secondary fractures and faults in a damage zone adjacent to lar
 illing (LWD) propagation resistivity tools can help to achieve this goal their overall effectiveness is not satisfactory because they lack azimuth
. Real time use of new and advanced LWD data in horizontal drilling gives the opportunity to extend the envelope for well planning and reser
ey parameters for reservoir description in conventional wireline logging (WL) programs. While comparisons between WL and LWD including

 state of the art reservoir model and initiated several projects to achieve that goal: reprocessing and elastic inversion of the 1995 vintage 3D
plug data.� The data may be taken preferentially from certain geologic locations and there may be inconsistencies in the data.� The me

cess was an iterative multidisciplinary optimization task that generated an action plan based on multiple options developed by reservoir prod


 ion phase and challenge COPC (the field operator) with surface fluid handling capacity issues as a result of high water cuts. Additionally the

both horizontal injector and producer in a SAGD well pair are put under circulation is designed to establish inter-well communication and cre
ditioner defines a matrix M that can be inexpensively inverted and represents a good approximation of a given matrix A. In this work two-sta
anner. Methods such as algebraic multigrid (AMG) Krylov recycling (e.g. deflation Krylov-secant) and extensions to two-stage preconditione

AS) developed at the University of Texas at Austin which uses a finite difference method for the solution of its governing partial differential e
dered only the wells and production-gathering network the new model is able to consider the combined performance of the total system incl
 amline–isopotential grid grid optimization and upscaling. The grid optimization is accomplished through application of a hybrid procedure
surement instruments are increasingly incorporated as part of the intelligent completion in complex (highly slanted horizontal and multilatera
 isual model results to demonstrate the feasibility of the GAGD process and the various mechanisms responsible for the high recoveries achi
 ir densities. The GAGD process uses the existing vertical wells for CO2 gas injection and a horizontal well near the bottom of the payzone fo
 were investigated at wettability conditions ranging from strongly water-wet to moderately oil-wet. The impact of wettability and was investigat
 sed almost simultaneously with both emerging as significant sources of oil and gas. Both provinces entered the 1960’s with no oil produ
 ergy such as natural gas from unconventional reservoirs. In the 1980’s in North America the combination of federal tax credits and var
urement instruments are increasingly incorporated as part of the intelligent completion in complex (highly slanted horizontal and multilateral

 cumulative gas production is created to estimate original-gas-in-place (OGIP) or 2) Flowing material balance where gas rates and flowing pr
so known as matrix-shrinkage or -swelling may dominate permeability changes at low pressures as is the case for CBM wells undergoing p
  of these techniques to coalbed-methane (CBM) reservoirs requires the unique coal storage and transport properties to be accounted for. In
 e four phases provides for a program of progressively ramping work and cost while creating a series of discrete decision points at which an
onventional low-pressure dry gas reservoirs.� However the complex geologic history of the coals and non-coal interbeds has imparted stro
 s three distinctly different performance areas within the 6 800 mile2 (17 600 km2) enclosed by the Fruitland outcrop. Two of these areas are
 balance time originally put forth by Palacio and Blasingame (1993) have been proposed and validated in recent publications for a variety of p
mparting very poor fluid-flow characteristics. Abundant volumes of oil or gas can be stored in these rocks and often the rock is high in organ
 opment. Resources too deep to mine are considering steam assisted gravity drainage (SAGD) (Butler 1991). Detailed high-resolution 3D geo
ducing upper zone called the C sand to generate greater drawdown on a less productive lower zone called the A sand. Formation powered je
ers the production stream downhole via open-ended tubing or nozzles which if not properly sized can result in operational issues such as flu
 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
mpletions were considered the best completion option based on rock mechanics improved profile surveillance and cost. The original Alpine
. Analyzing the different production technology options used in the assets thus far was the next step in better understanding the different rec
 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
 mine why this completion technique was selected and identify key parameters that favored its successful application in the Colville River field
 ss the effects of discontinuities on hydraulic fracture growth. A high viscosity fluid was used in order to provide fracture growth similar to actu
  stimulated to remove drilling fluid filter cakes and to overcome formation damage effects or to create acid fractures or deep matrix stimulat
s with 50�-60� maximum hole-angles. The wells are completed using dry trees from the TLP and are producing primarily from massive


and release rate are vastly simplified4-11 necessitating further field observations controlling sand flow rate in order to improve accuracy.�
 trength distribution using core testing log data and drilling data analysis for rock strength estimate and its correlation with core testing results
development and validation by comparison with finite-element simulation results. With the new perforation skin model we then show how to o
 acid-fracturing treatment. Depth of penetration is controlled by the acid reaction rate leakoff and stimulation rate. Acid reaction rate is a fun
ve some water accumulation near the wells. This adds significantly to the total liquid blocking. Experiments were conducted using both outcr
GD (Steam Assisted Gravity Drainage) (Butler 1991). However this parameter is hard to calculate due to many unknown variables such as v




 er no study has been presented to quantify the petrophysical limitations of such methods. We address this problem by introducing a pore-sc

 ability field which is quite difficult to characterize.� Permeability in vuggy or fractured intervals can be dramatically different from the matrix


mulation allows extracting multiple-point structures from such training images and anchoring these structures to the data actually observed in


 dependent. Such rate dependence can be modeled using a capillary number to calculate the decrease in residual saturations and the corres



DFA logs and various laboratory analyses are studied to elucidate hydrocarbon composition variations in large reservoir sand bodies. This pr

meabilities for a rich-gas/condensate reservoir using a live single-phase reservoir fluid. Using a live single-phase reservoir fluid eliminates th

 c resulting from the flow of brine and synthetic steam condensate (180-230�C pH = 7 and 10) through diatomite subjected to a radial conf

 s and forced imbibition coreflood experiments using hot synthetic steam condensate (180�C to 230�C pH = 10). The effects of these e



 oir pose difficulty in designing surface facilities. Of course contractual obligations dictate that the required gas volumes are delivered daily w


 ir depth is about 9000 ft subsea. The gross reservoir interval is approximately 730 ft thick (110 ft net). The lowermost Marrat E zone contribu


 002 and two appraisal wells were drilled soon afterwards. Due to significant uncertainties remaining after appraisal probabilistic methods w
 for horizontal wells when bottom- or edge-water invasion occurs. Two depletion strategies may be enacted to improve recovery of the rema

ntaneous/lifetime revenue optimization from a hydrocarbon field. This involves among others the usage of reservoir simulators surface-netw




on for abandoning wells and declaring fields uneconomic. The challenge of produced water is further compounded by water being a valuab
both from a surface facility and subsurface viewpoint. Produced water can be disposed in oil sands (waterfloods) aquifer or wet sands and in


lining and water production is increasing. However through reservoir surveillance data geologic and reservoir modeling significant recovera

aking place. This field consists of several sandstone reservoirs with average permeability and porosity of 75 mD and 17% respectively. One u




The reservoir produces from three intervals – Marrat A Marrat C and Marrat E. The partially dolomitized lowermost Marrat E interval contri

 ed to develop the neural networks. The before and after treatment data for 22 wells treated with polymer gels in the Arbuckle formation in ce
he problem of field development where field production profile moves through successive phases of buildup plateau and decline.�This re

) and it is acknowledged that such path constraints involving state variables can be difficult to handle. Currently one category of methods im

mization problem is a discrete-parameter problem (well locations are discrete parameters in the simulation model) gradients of the objective

oing this is through the use of numerical models. However these models may be expensive to build and difficult to maintain. Therefore a sim

ch requires estimation of film thickness before computing frictional pressure drop as gas flows past the wavy-liquid film surrounding the pipe

 the error components). The observed patterns were very similar to patterns seen while using Error Surface Analyses (ESA) to manually hist

oop reservoir modeling the two approaches receiving the most attention to date are ensemble Kalman filtering and gradient-based methods


y such algorithms have not been extensively used in practice because computation of the gradient of the objective function by the adjoint me

also honoring all available (static and dynamic) information. In addition to data assimilation the probabilistic framework provides an assessm




 in signal processing. Put simply a rate variation at an injector introduces a signal with the corresponding response felt at one or more prod
 ol is ideally suited for engineers who manage daily flood performance. We envision CRM’s application to precede any detailed full-field n


 es on how cost-effectively the remaining oil volume is recovered. Robust design and optimization are essential for technical success and pro

  with steam injection and Steam Assisted Gravity Drainage (SAGD) and to simulate such models efficiently using parallel processing. The si

 ases or components. This type of formulation is desirable for flexibility in reservoir simulation but has not previously been used in commercia




n a multi-purpose flow simulator. The flow simulator may be used to model gas black oil compositional and thermal systems. The petroelas




modeling is a composite modeling strategy that couples subsurface (material balance or simulation) models to a surface network model via w


model can be combined with the transient wellbore model for rapid computations of pressure temperature and velocity. We verified the simu
well testing can also be used to estimate other reservoir parameters such as permeability and/or relative permeability curve. In this paper w

ulation and upscaling. In this work we present an innovative workflow that addresses these challenges and provides the capability to realistic

 n this work we develop and test a new approach ensemble-level upscaling for efficiently generating upscaled two-phase flow parameters (


nce properties vary. An important property for multiphase flow is the monotonicity of the numerical elliptic operator. In a recent paper [1] con

pecial core analysis data is limited.� This paper demonstrates a technique to develop a reservoir scale fractional flow curve from historic p

cheme with a third-order accurate finite difference (FD) simulator based on a third-order essentially nonoscillatory (ENO) flux reconstruction
umetric system owing to ever-declining reservoir pressure. To circumvent this reality we suggest a two-step approach. First conduct a multir

 2005 design for a pressure maintenance project (PMP) via a peripheral waterflood was initiated to arrest pressure decline and improve oil re



 g for both mass transfer and heat transfer between a horizontal well and a reservoir. The treatment is 1D linear in the wellbore and 1D radial

based sensitivity analysis approach to address this problem. To the best of our knowledge sensitivity analysis has never been applied for ide

 of facilities performance and production enabling decision risk analysis for strategic and operational decisions. The IAM includes risk-base

odeling environment specially configured for this domain is used to instantiate the asset model. Automatic conversion of legacy data into stru


 ion of hydrocarbon reservoirs (lean and rich gas condensate oil rim and gas cap) some connected to an aquifer and the reservoirs cannot
timation in gas reserves. The famous straight-line plot of p/z vs. Gp has been traditionally used to estimate original gas in place (and gas res

covery and efficient use of information may add value beyond the amount of oil recovered. This study proposes an approach that emphasize



on techniques. The usual approach to do so is manually which is quite time consuming and very likely to provide suboptimal results. With th


 eal channel reservoir from the African coast.� The methodology relies on the probability-perturbation method (PPM).� Perturbing proba



bility concept. However in most existing approaches there is not a systematic and quantitative link between the underlying geological mode


dels poses a great challenge. In recent work we developed systematic procedures for upscaling discrete fracture models to coarsescale con

eat transfer which is a valid assumption for low permeability formations such as shales. However convection plays an important role in cont

ation damage prediction to name a few. The aim of this study is to provide guidelines to successfully develop and train an artificial neural net

 -injector pair; so if N injectors are assumed to contribute to a producer there will be 2N unknown parameters. An adaptive strategy using a

oduction. Previous results reported on this project suggest that the randomized maximum likelihood (RML) method gives a biased character
g to understanding of reservoir compartmentalization and application of an appropriate material-balance technique.� Data diagnosis en



ainty while also considering the impact of completion decisions and operating constraints.� This topic is important because it can help to r

evaluating an existing asset major capital project or exploration prospect. It therefore follows that generating a reliable and representative p

chanisms in the field and also in determining long term field operating strategies. A generic controller framework is constructed within a rese




assimilating the most current observations of production data is always available. Thus the estimations of reservoir model parameters and




gly influenced by the underlying geologic model. However the direct relationship between geologic parameters and subsurface flow is obscur

 ghly constrained workflows that use detailed stratigraphic and facies constraints.� Thus considerable time and cost saving may be reali


n the stocks of both experimental design and response surface techniques in the E&P industry rise significantly as an alternative to the more

rogeneous reservoir models. IMPES and sequential implicit formulations are described. The algorithms are sensitive to the specific characte
 highly correlated with the underlying computational grid. In many real-field applications this can result in strong sensitivity to grid design for th

 of cyclic steaming of the producers grid size and other physical parameters were evaluated. Detailed multipattern single-sand steamflood

 etry or fully unstructured grids) with full-tensor permeabilities advanced discretization methods such as the family of multipoint flux approxim

atic history matching techniques have shown great potential in this regard and several field applications have demonstrated the feasibility o


been incompressibility or slight compressibility assumptions that have limited applications to two-phase water-oil displacements only. Recent



can be improved.� Quantifying subsurface uncertainties for a mature field involves history matching or solving the inverse problem which

  feedback to geologic modelers which results in improved static models.        The Chuchupa Field has produced 1.9 Tscf of dry gas or approx

es global coarse-scale flow information into the boundary conditions used to compute upscaled quantities (e.g. coarse-scale transmissibilitie

ger than a specified tolerance the upscaled model is dynamically updated with approximate fine scale information that is reconstructed by a

ns which were verified with the results of coupled geomechanical/fluid-flow simulations. The new formulations allow tracking the expanding w

 xpected performance trend when changes in flow conditions occur. These inevitable changes include gas/liquid ratio wellhead pressure an


 the pay section a number of times. Banzala “A horizontal wells underperformed expected production possibly due to downhole slugging

hitectures demand rigorous treatment. For example changing geothermal-temperature gradient and deepwater wells present significant cha


attern-dependent values for flow parameter and rise velocity. The gradual change in the parameter values near transition boundaries avoids d

s recently experienced well collapse (and sudden productivity decline) after some time on production with cavings being flushed out during c




mperature changes with a resolution on the order of 0.1�F can be detected by modern temperature-measuring instruments in intelligent co

elated to environment cleanup and curtailed oil production. A traditional approach to fault reactivation prediction provides a deterministic criti

ddition to information about the mean variance and correlation structure of the permeability few permeability measurements are assumed a

atistical characterization. The obvious major finding from these tests is that acid propagates wormholes through vuggy carbonates much mor



ases. It is well known that whenever the fluid saturations undergo a cyclic process relative permeabilities display hysteresis effects. In this
orized because the pressure drop that occurs toward the wellbore increases the ability of the gas to contain water. Thus there are different m

 rs including recent horizontal drilling has provided some clues about fractures but their exact locations intensity and overall effect have bee


 ering approach to measure and understand the problem in quantitative and fact-based terms. We first review the mission of the SPE IT Tech

 ves are located in deepwater locations throughout the world. The Company is one of the largest producers of crude oil and natural gas on th

 rability and keeping CAPEX within acceptable project economic limits.� The Flow Assurance plan addresses the interaction between prod




 actures although successful often underperform: Frac and Pack completions exhibit positive skin values and traditional hydraulic fracture


 penhole gravel packing has created a mainstay completion technique that has been used in deepwater developments in Brazil and West Afr


ndex (PI) and inflow performance relationship (IPR). Both relate fluid flow rate to pressure difference between bottomhole and reservoir. Muc
mature producing fields.� This talk highlights some of the latest technology in prevention diagnosis mechanical/chemical methods and wi


 flood reservoir management of such a field requires timely information concerning reservoir pressures water-flood sweep and movement of



 e used a wellbore/reservoir simulator that conserves mass momentum and energy to develop a comprehensive understanding of the gauge

major oil/gas/water producing layers. Through successful PLT surveys and appropriate interpretation we may also identify thief zones and hig


 a obtained with conventional production logs in both vertical and deviated wells. One input that enters into typical DTS calculations is the to


eys and appropriate interpretation it may also be possible to identify thief zones and high perm channels locate injected fluid breakthrough m


 ajor oil/gas/water producing layers. Through successful PLT surveys and appropriate interpretation we may also identify thief zones and hig

outstanding issues remain in this area. This paper addresses some of the challenges in analyzing flow rate data and pressure data from per



zation. Well lifespan is short and economics rarely provide for the use of higher technology at non-discounted prices. A recent business initia


uration estimation. This required in-house Monte Carlo modeling to understand the tool response in very high porosity reservoirs. A newer ve

on of various principles recommended by industry experts is presented using examples from fields currently in production. Practices in proc
sis.� This was a time-consuming process with the potential of considerable time lag between problem occurrence and diagnosis.� The

  adsorption solution theory described adsorption equilibria and aided interpretation. The gases tested include pure methane (CH4) nitrogen

pularity in many different coalbed reservoirs with varying results. This study concentrates on variations of horizontal- and multilateral-well con



vron operations there are huge cost implications in the implementation of gas lift on several offshore jackets. New facilities for gas lift opera


 ctivity (permeability-thickness product) and selectively perforating zones or reservoirs to offset the permeability contrast. At the outset a valu

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

 slots and limited open-to-flow areas. Furthermore the compounded effects of formation damage and non-Darcy flow on the fluid flow toward

shown frac packs have a significant impact in maintaining well productivity in the later production life stages of unconsolidated reservoirs. Th



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




w discrepancies between the placed propped length and the effective production fracture length. Ineffective fracture clean-up is often cited a

tern Piceance Basin western Colorado. Production from very low permeability Williams Fork gas sandstones requires fracture stimulation to



ed. Written by individuals recognized as experts in the area these articles provide key references to more definitive work and present specific

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


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


d few wells will use an intelligent well systems to manage fluid fronts in a gravity-stable recovery scheme. The reservoir has many producing

oduction observing much reduced flow rate for three days and eventually stopped flow. During the production depletion shuts-in restarts a


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

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


eabilities of 35md to 85md and porosities of 18 to 30%. The wells are completed in oil reservoirs that have been perforated using convention



f the gravity-assisted electric line to convey perforating guns to angles greater than 65�. With this electric line limitation the options availa
 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

penhole gravel packs completion (OHGP) for its first phase development. The ultra high rate for individual well could be up to 320 MMSCFD




nd executed completions are subject to mechanical failure with the first indications often being production of solids into a common separatio

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


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




servoir rock which is significant even for wells producing very lean gas with liquid dropout values less than 1%. Many different methods such

 but still not perfect. Limitations on the amount of proppant placed near water zones and formation damage from polymer residuals were the



etation can generate several non-unique solutions all of which may match test data. Using seismic attribute analysis to constrain pressure tra


this reservoir.� Thus this reservoir must be exploited using horizontal wells.� Recently a 2 270 ft long horizontal well has been drilled i

s to two-phase flow in the reservoir (oil and water or oil and gas). Future expansion to three-phase flow is possible. Current analysis methods
 ations through more proactive use of both field equipment and software tools. This paper describes the specification development and impl

slugging and possible mitigation procedures which could alleviate and/or eliminate slugging.� Further the Alpine expansion called for an


eserves permeability and well productivity indices were also determined. Example analyses are presented for single dual and triple lateral

  l in place discovered in May 1999 and put on production in December 2002. Electrical submersible pumps (ESPs) were selected as the mo
The challenges involved in modeling these processes are accurate representation of the propagation of the reaction front which is very locali
 e important aspects of the ES-SAGD process. In an ES-SAGD process a solvent is added to the injected steam that remains in the vapor p
 iscous oil trapped in carbonates (over 1.6 trillion bbl)1 potentially a huge resource for future needs application of new technologies to be ex
anak field is transported to Singapore and Malaysia. Belanak wells which are drilled in the Gabus Massive reservoir have a bottom hole stat
e to clay coated grains and alternating thin laminae of finer and coarser sandstones with distinctly different pore geometries natural fractures
ults in a damage zone adjacent to larger faults. Because there is usually inadequate data to incorporate damage zone fractures and faults int
atisfactory because they lack azimuthal sensitivity. Ideally geosteering and advanced formation evaluations such as anisotropy calculations
 envelope for well planning and reservoir information gathered in a single run. Optimum interpretation from real time data acquisition facilitate
ons between WL and LWD including costs savings associated with the LWD approach are common today in operators’ minds the inta

stic inversion of the 1995 vintage 3D seismic petrophysical data collection and analysis and comprehensive reservoir characterization. This
onsistencies in the data.� The measurement scale is significantly less than that required for input to flow simulation.� Mini-models of po

 options developed by reservoir production drilling and facilities engineering and ranked by economics. The process specifically involved firs


 lt of high water cuts. Additionally there are no more slots available in the existing platforms for infill drilling. Typical completions include san

 ish inter-well communication and create an initial steam chamber. It is desirable to know the mid-point temperatures between and along the
  given matrix A. In this work two-stage preconditioners consisting of the approximated inverses M1 and M2 are investigated for multiphase f
extensions to two-stage preconditioners (e.g. GPR) have been copping the scene in latest solver advances.� Nevertheless there is still a

 n of its governing partial differential equations (PDEs) is iteratively coupled with a geomechanics model that is developed using a finite elem
 performance of the total system including downhole well configurations the complex production-gathering and lift-gas-distribution pipeline n
 gh application of a hybrid procedure with gradient and Laplacian smoothing steps while the upscaling is based on a global-local procedure th
 ly slanted horizontal and multilateral) wells where they provide bottomhole temperature pressure and sometimes volumetric flow rate along
 ponsible for the high recoveries achieved. In this paper we present visual and quantitative results from the physical model experiments to de
well near the bottom of the payzone for oil production. In this experimental study a physical model consisting of two parallel glass plates con
 pact of wettability and was investigated in a series of flooding experiments. The objective was to determine the impacts on fluid flow from diff
tered the 1960’s with no oil production but by the end of the 20th century the provinces combined had delivered almost 50 billion barre
bination of federal tax credits and various technical development programs sponsored by private organizations public companies and govern
 y slanted horizontal and multilateral) wells where they provide bottomhole temperature pressure and sometimes volumetric flow rate along

 ance where gas rates and flowing pressures are used to estimate average reservoir pressure. The flowing material balance concept of Aga
 he case for CBM wells undergoing primary depletion in the Fruitland Coal fairway of the San Juan Basin. Several analytical models have be
ort properties to be accounted for. In recent work the authors [ex. Clarkson et al. (2007a) and Jordan et al. (2006)] and others [ex. Gerami e
  discrete decision points at which analysis of results and risks can be assessed. While covering each of these phases in some degree this p
 non-coal interbeds has imparted strong vertical and lateral heterogeneities that make the play difficult to characterize using conventional me
and outcrop. Two of these areas are considered in this topic: “Fairway and “Colorado Type II. Explaining well performance in these a
n recent publications for a variety of problems (including shale gas and coalbed methane systems) using an adjusted system compressibility
s and often the rock is high in organic content and the source of the hydrocarbon. Yet because of marginal rock matrix quality these reservo
 991). Detailed high-resolution 3D geostatistical modeling is useful for individual well-pair or pad flow simulation but is neither practical nor ne
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
sult in operational issues such as fluid / gas slugging and pressure instabilities which negatively impact the overall lift efficiency. In 2006 Co
 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
 illance and cost. The original Alpine field development plan did not include hydraulic fracture stimulation based on the reservoir characteriza
better understanding the different recovery increment options. The initial 4 year productivity from 4 assets was analyzed. This paper presents
ment of high pumping rate (30~55bpm). Post-frac snubbing operations are often needed to run tubing and clean out wellbores. Snubbing ope
ul application in the Colville River field. The optimal completion technique for a candidate well is determined by reservoir properties geologic
 rovide fracture growth similar to actual field conditions. Fracture growth and its internal fluid pressure were monitored by fixed probes placed
 cid fractures or deep matrix stimulation to enhance productivity. Good acid coverage with a relatively small acid volume is required to econo
are producing primarily from massive fine-grained Pleistocene-aged reservoirs. These reservoirs require sand-control to prevent sand prod


  te in order to improve accuracy.� Sand flow is catastrophic when formation is soft. However if certain conditions are satisfied the sand ra
 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 skin model we then show how to optimize horizontal well perforating to maximize well productivity. A cased perforated well may have low
  ation rate. Acid reaction rate is a function of several factors the most important of which is the reservoir temperature. Yet another concern i
ents were conducted using both outcrop sandstone and reservoir cores to measure the effect of liquid blocking on gas relative permeability. A
o many unknown variables such as variations in operational conditions and steam saturation along the horizontal wellbores heat return rates




 his problem by introducing a pore-scale framework to accurately simulate suites of NMR measurements acquired in complex rock/fluid mod

 dramatically different from the matrix permeability measured in core plugs.� However realistic estimates of oil recovery and optimized res


ures to the data actually observed in the reservoir. By reproducing multiple-point statistics inferred from training images MPS enables the mo


 n residual saturations and the corresponding increase in relative permeability as viscous forces become dominant over the interfacial forces



 large reservoir sand bodies. This procedure was applied in the Deepwater Tahiti field in the Gulf of Mexico uncovering a large concentration

 le-phase reservoir fluid eliminates the difficulties in designing a relatively simple model fluid that replicates the complicated thermodynamic a

h diatomite subjected to a radial confining stress. Spontaneous imbibition tests at temperature gauge oil recovery potential at negligible pres

¿½C pH = 10). The effects of these experiments on the rock fabric were determined by comparing mineralogy pore structure and physical p



ed gas volumes are delivered daily with spare capacity in hand. Management issues of this type occur in the backdrop of potential loss of we


he lowermost Marrat E zone contributes 80-90% of the production based on PLT data. The productivity of the Marrat E is dominated by a for


ter appraisal probabilistic methods were used to assess development alternatives. In this study the classical experimental design method
cted to improve recovery of the remaining oil. In the first option a conventional horizontal is completed below the gas/oil contact (GOC). Onc

 of reservoir simulators surface-network simulators process-modeling simulators and economics packages.��� We present a com




ompounded by water being a valuable resource especially in arid oil producing regions of the world. In dry climates where easily accessible
erfloods) aquifer or wet sands and in depleted hydrocarbon sands. This paper provides insights into the subsurface disposal alternatives of p


servoir modeling significant recoverable oil was identified in shaly sandstone reservoirs and attic structural locations of clean sandstone rese

 75 mD and 17% respectively. One unique challenge of El Trapial field is that the light oil coexist with gas that contains high CO2 concentrat




ed lowermost Marrat E interval contributes 75-85% of the total production from zones averaging 20-25% porosity and 10-100 mD permeabilit

r gels in the Arbuckle formation in central Kansas were used to train and verify the neural networks. Polymers and gels have been used exte
dup plateau and decline.�This results from successive drilling and commissioning of wells at a prescribed frequency (e.g. quarterly) unti

urrently one category of methods implicitly incorporates the constraints into the forward and adjoint equations to address this issue. Howeve

on model) gradients of the objective function (NPV) with respect to these parameters are not defined. Thus gradient-based methods have n

d difficult to maintain. Therefore a simpler and less expensive method to forecast the impact of injection rates on reservoir pressures under

wavy-liquid film surrounding the pipe wall. This study intends to investigate this film thickness and its impact on pressure-drop computation in

 ace Analyses (ESA) to manually history match models. ESA is the animation of errors at their respective spatial locations though time. This

 iltering and gradient-based methods using Karhunen-Loeve representations (eigen-decomposition) of the permeability field. Both of these pr


e objective function by the adjoint method requires explicit knowledge of the simulator numerics and expertise in simulation development. He

istic framework provides an assessment of the prediction uncertainty due to incomplete knowledge of the reservoir description. Methods bas




ng response felt at one or more producers. CRM uses production and injection rate data and bottomhole pressure if available to calibrate th
on to precede any detailed full-field numerical modeling. We have selected field case studies in a way to demonstrate CRMs capabilities in d


ssential for technical success and profitability. The main objective in chemical flooding design is to keep the surfactant in Type III near the op

ntly using parallel processing. The simulator solves component material balance energy balance and mass equilibrium equations for compo

t previously been used in commercial simulators due to its complexity and inefficiencies in both memory and speed. Here we describe an eff




 and thermal systems. The petroelastic model can calculate such reservoir geophysical attributes as P-wave and S-wave velocities and impe




els to a surface network model via well–bore models. The objective of using an integrated production model (IPM) is to predict the reservo


re and velocity. We verified the simulator with transient data from gas and oil wells where both surface and downhole data were available. T
e permeability curve. In this paper we utilized Masoner’s decline derivation to show that estimates of the relative permeability curve can

and provides the capability to realistically model the impact of fractures on oil recovery for a practical field study. Our approach allows us to d

pscaled two-phase flow parameters (e.g. upscaled relative permeabilities) for multiple geological realizations. The ensemble-level upscaling


c operator. In a recent paper [1] conditions for monotonicity on quadrilateral grids have been developed. These conditions indicate that MPF

e fractional flow curve from historic production data.� The curve becomes the basis for an analogous model that allows the estimation of o

oscillatory (ENO) flux reconstruction with matching temporal accuracy. We include physical dispersion in the mathematical model of these m
step approach. First conduct a multirate test to establish reservoir parameters such as permeability mechanical and non-Darcy skin and av

st pressure decline and improve oil recovery. A key building block of the Wara PMP is a stand-alone full-field Wara simulation model.� Th



D linear in the wellbore and 1D radial in the reservoir. A numerical algorithm for reservoir temperature calculation is proposed and an analytic

alysis has never been applied for identification of the injector-producer relationships yet we show that it is an intuitive while fundamental app

ecisions. The IAM includes risk-based oil gas and water production forecasts for the Captain Field and cash flows. These forecasts take fu

 tic conversion of legacy data into structured model representations is facilitated through a model synthesis tool. The actual optimization is p


n aquifer and the reservoirs cannot be modelled separately. This situation can occur when multiple gas reservoirs are needed to be develop
 ate original gas in place (and gas reserves) for depletion-drive gas reservoirs. A gas reservoir in contact with an aquifer in transient phase (u

 oposes an approach that emphasizes the value of time-dependent information to achieve better decisions in terms of reduced uncertainty an



o provide suboptimal results. With the advent of new numerical formulations and powerful computational resources it now appears possible


 method (PPM).� Perturbing probabilities rather than actual petrophysical properties guarantees that the conceptual geologic model is ma



ween the underlying geological model [in this case a discrete fracture model (DFM)] and the parameters appearing in the flow model. In this


 e fracture models to coarsescale continuum descriptions referred to as multiple subregion (MSR) models. In this work we extend these form

ection plays an important role in controlling wellbore stability in high permeability formations such as sandstones. A 3-D thermo-poroelastic m

velop and train an artificial neural network (ANN) that will predict reservoir properties that can give an improved history match when input into

meters. An adaptive strategy using an Extended Kalman Filter (EKF) is used to estimate the 2N parameters which are then used to genera

ML) method gives a biased characterization of the uncertainty. A major objective of this paper is to show that this is incorrect. With a correct i
e technique.� Data diagnosis entails graphing pressure with rate and discerning trends; positive slope signifies the pseudosteady-state



  is important because it can help to reconcile the often large gap between short-term deliverability and reliable and sustainable performance

 rating a reliable and representative production forecast is a key desire of any Oil and Gas company. There are many factors surface and su

amework is constructed within a reservoir simulator that enables the usage of different kinds of controller algorithms for managing a variety o




 of reservoir model parameters and their associated uncertainty as well as the forecasts are always up-to-date. In this paper we apply the




meters and subsurface flow is obscure. In this paper we explore this relationship in a deepwater depositional system using data from two res

 le time and cost saving may be realized during initial model building and updating if simple but appropriate workflows are used.� The r


 ficantly as an alternative to the more traditional uncertainty analysis. Whilst there are papers describing experimental design workflows and

 are sensitive to the specific characteristics of flow (i.e. pressure and total velocity) and transport (i.e. saturation). To compute the fine-scale
 strong sensitivity to grid design for the computed saturation/composition fields but also for critical integrated data such as breakthrough tim

multipattern single-sand steamflood models were constructed using properties of a heavy-oil field in California. All models included an initial

  the family of multipoint flux approximation (MPFA) schemes are necessary to obtain an accurate representation of the fluxes across contro

s have demonstrated the feasibility of the approach. However most of these applications have been limited to two-phase water-oil flow und


water-oil displacements only. Recent generalization of streamline models to compressible flow has greatly expanded the scope and applicab



or solving the inverse problem which is not only difficult but also non-unique in nature. A suite of acceptable history matched models which h

oduced 1.9 Tscf of dry gas or approximately 40% of the Original Gas in Place (OGIP).�At the time of this study 3 new horizontal wells w

 s (e.g. coarse-scale transmissibilities). The procedure is iterated until a self-consistent solution is obtained. In this work we extend this appr

nformation that is reconstructed by a multi-scale finite volume method (Jenny et al. JCP 217; 627-641 2006). Upscaling of multi-phase flow

 ations allow tracking the expanding water-bank radius from inception to breakthrough. Pressure of this bank at the water/oil interface is eval

as/liquid ratio wellhead pressure and flowline pressure with time among others. Influx of water further exacerbates the prediction problem.


 n possibly due to downhole slugging. In addition declining reservoir pressures rising GOR and rising water-cut have also adversely affecte

epwater wells present significant challenges. Additionally available analytic models rarely provide calculation methods for various required th


es near transition boundaries avoids discontinuity in the estimated gradients unlike most available methods. Frictional and kinetic heads are

 th cavings being flushed out during coil tubing workover operations. In addition to horizontal well drilling feasibility of open horizontal well com




measuring instruments in intelligent completions which may aid the diagnosis of downhole flow conditions. Since in a producing horizontal we

 ediction provides a deterministic critical reservoir pressure without proper regard to the uncertainties in the model input parameters and the p

ability measurements are assumed available. Moreover few measurements of the dependent variable are available. The first two statistical m

 hrough vuggy carbonates much more rapidly than occurs in more homogeneous rocks. Acid-created wormholes were observed to break thr



es display hysteresis effects. In this paper we investigate hysteresis in the relative permeability of the hydrocarbon phase in a two-phase sy
ain water. Thus there are different mechanisms for injection and production. For both gas injection and gas production vaporization concen

 intensity and overall effect have been elusive. This study attempts to discern open fractures if any and their locations to facilitate building n


eview the mission of the SPE IT Technical Section–Oilfield Integration (SPE ITTS OI) subcommittee. Several contexts of oilfield integration

ers of crude oil and natural gas on the Gulf of Mexico (GoM) shelf and among the top acreage holders in the Gulf's deepwater1 and ultra dee

dresses the interaction between production chemistry and multiphase flow and the resulting effects on operability deliverability and system p




ues and traditional hydraulic fracture completions show discrepancies between the placed propped length and the effective production frac


developments in Brazil and West Africa to deliver reliable high-rate well completions. The technology also has been an enabler for heavy-oil


ween bottomhole and reservoir. Much effort has been made on developing the PI or IPR solutions suitable for specific circumstances since D
echanical/chemical methods and with supporting field case history.� Specific applications for injector producer reservoir-wide and facilit


water-flood sweep and movement of gas and water contacts. Conventional reservoir monitoring practice obtains this information by monitorin



ehensive understanding of the gauge-placement issue. First we reproduced a field example from a deepwater asset to demonstrate the sim

 may also identify thief zones and high perm channels locate injected fluid breakthrough monitor fluid front movements detect crossflow an


into typical DTS calculations is the total flow rate at surface. In absence of dedicated flowmetering uncertainty normally creeps into assigned


s locate injected fluid breakthrough monitor fluid front movements detect crossflow and fluid migration assist in reservoir simulation studies


 may also identify thief zones and high perm channels locate injected fluid breakthrough monitor fluid front movements detect crossflow an

ate data and pressure data from permanent downhole gauges - development of improved algorithms for reliable and accurate identification o



unted prices. A recent business initiative recognized that oil vs gas fluid identification from logging measurements was a risk that should be m


 high porosity reservoirs. A newer vendor algorithm however underestimated the oil saturation. In-house test algorithms were then develope

ntly in production. Practices in processing valuable information and analyzing data from different perspectives are presented in a methodica
 occurrence and diagnosis.� The new data-driven workflow requires a tool to support a review by exception" process through the automat

 clude pure methane (CH4) nitrogen (N2) and carbon dioxide (CO2) as well as N2 and CO2 binary mixtures. The coal pack was initially dry

of horizontal- and multilateral-well configurations and their potential benefits. In this study horizontal and several multilateral drilling patterns



 kets. New facilities for gas lift operation entails the installation of a compressor liquid knock out equipment pipelines manifold configuratio


eability contrast. At the outset a value-of-information exercise suggested probing downhole sensing and completion issues in a stacked-res

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

on-Darcy flow on the fluid flow towards slotted-liners must be considered in well completion design process. This paper presents a compreh

ges of unconsolidated reservoirs. Thus sustaining the ability to pump frac packs in these challenging environments is a priority. With conve



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




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

tones requires fracture stimulation to enhance wellbore-to-reservoir connectivity. The use of surface microseismic monitors without borehole



e definitive work and present specific details only to illustrate the technology. Purpose: to inform the general readership of recent advances i

 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


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


e. The reservoir has many producing zones with high-quality rock properties. Intelligent well systems which consist of interval control valves

duction depletion shuts-in restarts and finally stop flowing periods the gas well experienced liquid load-up involving unstable operation cond


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

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


ve been perforated using conventional methods fracture stimulated to increase production and later completed with electro-submersible pu



ctric line limitation the options available for deploying the guns are limited to wireline tractor and e-coiled tubing since most through tubing p
 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

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




on of solids into a common separation facility. In many offshore completions particularly sub-sea or multi-zone completions it is often difficu

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


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-




an 1%. Many different methods such as hydraulic fracturing dry gas injection and solvent injection have been proposed and implemented to

age from polymer residuals were the main drawbacks. A never ending quest for efficiency and higher production rates called for different opti



ute analysis to constrain pressure transient test interpretation leads to better understanding of reservoir heterogeneities and boundaries and


 ong horizontal well has been drilled in an area interpreted to have high fracture density.� A comprehensive test program including flowing

s possible. Current analysis methods yield only the effective permeability for the dominant flowing phase and the “total mobility of all phas
 specification development and implementation of the online production optimisation software used in this project.� This software was pro

er the Alpine expansion called for an additional two pipelines (CD-3 and CD-4) to be brought into Alpine inlet separator.� Slugging mecha


nted for single dual and triple lateral wells from heavy oil fields located in Venezuela and Canada.�All wells exhibit a characteristic exten

mps (ESPs) were selected as the most economic artificial lift method to develop the field based on the reliability flexibility and robustness to
 the reaction front which is very localized and accurate depiction of diffusion which is one of the main transport mechanisms. We evaluate a s
ed steam that remains in the vapor phase in the SAGD steam chamber and condenses along the walls of the steam chamber. Thus the solv
lication of new technologies to be exploited economically. At present thermal processes like steam flooding and cyclic steam stimulation (CS
ive reservoir have a bottom hole static temperature of 315�F (157�C). The wells are typically long horizontals (2 300 - 3 400 ft) with ope
nt pore geometries natural fractures bituminous zones and multilateral fluvial channel sandstones in broad lenses. Core data is sparsely av
damage zone fractures and faults into reservoir simulation models in this study we utilize the principles of dynamic rupture propagation from
ons such as anisotropy calculations require azimuthally sensitive measurements.� This paper discusses a newly developed propagation
 m real time data acquisition facilitates a reformation of the way horizontal wells are planned and drilled. This paper shows a well where the in
day in operators’ minds the intangible benefits gained by real-time acquisition of these critical data are often neglected. Incorporating fo

nsive reservoir characterization. This paper illustrates how Qatar Petroleum with contractual assistance from PGS Total and Beicip-Franlab
ow simulation.� Mini-models of porosity and permeability are constructed and flow simulated in order to establish representative relationsh

 The process specifically involved first generating a series of unconstrained production options which then considered drilling reach and anti


ng. Typical completions include sand-control devices such as gravel packs and fracture packs inside 9 5/8-in casing with zones separated b

emperatures between and along the horizontal well pair so that any development of the steam chamber can be predicted. This paper propos
 M2 are investigated for multiphase flow in porous media. The first-stage preconditioner M1 is approximated from Ausing four different solu
ces.� Nevertheless there is still a long way to transit to be able to reduce the gap between achieving maximum robustness and parallel ef

  that is developed using a finite element method in this research. An elastic constitutive model is applied to represent deformation behaviors
 ng and lift-gas-distribution pipeline networks separators compressors and pumps. The model is applicable to most gas lifted fields and will
  based on a global-local procedure that makes use of the global solution used in the grid-determination step. The overall procedure is succe
sometimes volumetric flow rate along the wellbore. To fully realize the value of these intelligent completions there is a need for a systematic
the physical model experiments to demonstrate the various modes of operability of GAGD its applicability to fractured reservoirs the effect o
 isting of two parallel glass plates confining a sandpack has been used to visually discern the mechanisms operative in the GAGD process. T
ine the impacts on fluid flow from different types of fractures at various wettability conditions. A general-purpose commercial core analysis si
  had delivered almost 50 billion barrels of oil equivalent to markets in Europe and the United States. Alaska’s North Slope started prod
 ations public companies and government agencies fostered the development of technology for unconventional natural gas exploration and e
ometimes volumetric flow rate along the wellbore. To fully realize the value of these intelligent completions there is a need for a systematic d

 ing material balance concept of Agarwal-Gardner (1999) was extended to dry coalbed methane (CBM)�reservoirs by Clarkson et al. (200
n. Several analytical models have been developed to predict changes in coal permeability as a function of stress and sorption. Most models
 al. (2006)] and others [ex. Gerami et al. (2007)] have demonstrated how new techniques such as the flowing material balance (FMB) and pr
  these phases in some degree this paper focuses on the third the pilot testing phase – that which normally takes place after reconnaissan
o characterize using conventional methods.� For example in a typical HSC well there are often > 10 seams to complete which may exhib
 plaining well performance in these areas has required the examination of a mechanism whereby coal permeability increases over time. Field
  an adjusted system compressibility function similar to that proposed by Bumb and McKee (1988) to account for adsorbed gas. These modif
 nal rock matrix quality these reservoirs generally require both natural and induced fracture networks to enable economic recovery of the hyd
 ulation but is neither practical nor necessary for resource assessment across large areas. A methodology for resource assessment is deve
 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
 the overall lift efficiency. In 2006 ConocoPhillips conducted a study to design a gas lift system for the Surmont SAGD development that wou
003 it became apparent that the original well design would not achieve the 1.1 Bcf/D production target because of well construction problem
  based on the reservoir characterization. Well performance had proven to be economic in this Jurassic marine sandstone without hydraulic
 s was analyzed. This paper presents the results of a study focused on increasing the understanding of productivity drivers using a database
nd clean out wellbores. Snubbing operations can be costly in terms of investment and time. Annular fracs have been applied in the industry a
ned by reservoir properties geologic setting rock mechanics development plan and completion design. In this paper we will review the uniq
ere monitored by fixed probes placed normal to the expected plane of propagation. Fracture tip arrivals were captured by the fixed pressure p
mall acid volume is required to economically obtain the desired broad reservoir access. We have developed a model to predict the placemen
 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


n conditions are satisfied the sand rate is reasonably stable. This paper clarifies nine forms of post-failure stabilization. Subsequently field m
mples in the low to intermediate strength range for defining the stress-strain relationship (or material laws) rock failure and yield criteria and
 cased perforated well may have lower productivity (as characterized by a positive skin factor) relative to the equivalent openhole completion
 temperature. Yet another concern in acid fracturing in long carbonate intervals is attaining the necessary diversion to ensure that multiple s
ocking on gas relative permeability. A chemical treatment was developed to reduce the damage caused by condensate and water blocking. T
 orizontal wellbores heat return rates and losses to the vertical section above the target formation. This paper proposes a new technique to




s acquired in complex rock/fluid models. The general pore-scale framework considered in this paper is based on NMR random walks for mul

 tes of oil recovery and optimized reservoir management requires good estimates of the reservoir permeability.� In the Tengiz field a gian


 raining images MPS enables the modeling of complex curvilinear structures (e.g. sinuous channels) in a much more geologically realistic w


e dominant over the interfacial forces. New steady-state relative permeability data have been measured over a wide range of capillary numbe



xico uncovering a large concentration variation of asphaltenes. These asphaltene nanoparticles are shown to be colloidally suspended in the

es the complicated thermodynamic and transport properties of a near-critical fluid. Two-phase-flow tests were performed across a range of p

 recovery potential at negligible pressure gradient. Numerous imbibition tests show that oil recovery from diatomite is accelerated and enhan

 ralogy pore structure and physical properties of material collected before and after the experiments. One set of reservoir samples consist o



 n the backdrop of potential loss of well deliverability owing to condensate banking in the well vicinity or from pure depletion standpoint when


of the Marrat E is dominated by a forty-foot thick largely dolomitized interval with 15-20% porosity and 20-100 mD permeability. The upper z


assical experimental design method was applied and reasonable P10 P50 and P90 reservoir simulation models were designed. Next we lo
elow the gas/oil contact (GOC). Once the well waters out the well is recompleted in the gas zone. Completion occurs either at the crest for a

 ages.��� We present a comprehensive portable flexible and extensible FM framework completely decoupled from surface and su




dry climates where easily accessible sources of freshwater are limited large volumes of freshwater are being used for non-potable uses s
 subsurface disposal alternatives of produced water management using examples from Chevron Thailand’s greater B8/32 operating are


ral locations of clean sandstone reservoirs. As a result a comprehensive portfolio of prospects has been built for a robust development prog

as that contains high CO2 concentrations greater than 75%. This is observed in both dissolved gas and in gas caps in various blocks of the f




 porosity and 10-100 mD permeability. Productive intervals in the Marrat A and C zones average 15-20% porosity and 0.5-2 mD permeability

 ymers and gels have been used extensively in field applications to suppress excess water production and improve oil productivity.� Field e
cribed frequency (e.g. quarterly) until the total well ‘budget’ for the field is exhausted and eventual termination of wells as they reach p

ations to address this issue. However these methods either are impractical for the production optimization problem or require complicated m

 hus gradient-based methods have not found much applicability to this problem and most existing algorithms applied to this problem are sto

 rates on reservoir pressures under various injection and production scenarios is of immense benefit. The method presented in this paper

pact on pressure-drop computation in wellbores producing steam-water gas-condensate and gas-oil mixtures. Computational results show t

e spatial locations though time. This error analysis can easily identify locations or times with high errors. During manual history matching with

he permeability field. Both of these procedures are technically appropriate only for random fields (e.g. permeability) characterized by two-poi


 ertise in simulation development. Here we apply the simultaneous perturbation stochastic approximation (SPSA) method to history match m

e reservoir description. Methods based on�Monte Carlo Simulation (MCS) are widely used. This is driven by the generality and simplicity o




e pressure if available to calibrate the model against a specific reservoir. Thereafter the model is used for predictions. We focused on three
o demonstrate CRMs capabilities in different settings: a tank representation of a field its ability to determine connectivity between the produc


the surfactant in Type III near the optimum salinity. Salinity gradient design is a robust design since it can compensate for heterogeneity and

ass equilibrium equations for component mole fractions saturation temperature and pressure using the Newton-Raphson method. External

 and speed. Here we describe an efficient natural-variable-based general formulation approach which handles general partitioning of phase-




wave and S-wave velocities and impedances dynamic and static Young’s moduli and dynamic and static Poisson’s ratios. Example




model (IPM) is to predict the reservoir performance while honoring mechanical design constraints of the surface network. The integrated pro


and downhole data were available. The accuracy of the heat-transfer calculations improved with a variable-earth-temperature model and a n
of the relative permeability curve can be obtained from a well under voidage rate control in a solution gas drive system. For a well under pres

d study. Our approach allows us to do away with the simplifying assumptions of the dual-porosity (DP) conceptualization traditionally employe

tions. The ensemble-level upscaling approach aims to achieve agreement between the fine- and coarse-scale flow models at the ensemble


. These conditions indicate that MPFA formulations which lead to smaller flux stencils are desirable for grids with high aspect ratio or severe

 model that allows the estimation of oil rate production forecasts and reserves for existing or proposed new wells.� In addition relative per

 the mathematical model of these multiphase multicomponent systems. The comparisons demonstrate that SPU schemes may fail to pred
echanical and non-Darcy skin and average pressure. Second with these known parameters use an analytic tool to describe the deliverabilit

l-field Wara simulation model.� The 23-million cells geological model was scaled-up to 4 million cells for flow simulation.� Four pseudo



alculation is proposed and an analytical solution is derived on the basis of some realistic assumptions. The analytical solution can be used to

 is an intuitive while fundamental approach to address this problem. Sensitivity analysis is based on a theory with which the functioning of a c

 cash flows. These forecasts take full account of facilities constraints and uncertainties in reservoir and operational parameters through link

esis tool. The actual optimization is performed using a commercially available solver. For an oilfield with about 75 wells the tool requires on


 reservoirs are needed to be developed in order to provide enough gas for a particular project. A significant drawback of this modelling appro
 with an aquifer in transient phase (unsteady-state) and producing under a certain production schedule can plot as a straight-line on a p/z plo

ns in terms of reduced uncertainty and increased probable net present value (NPV). Unlike previous approaches well-placement optimizatio



l resources it now appears possible to apply systematic approaches for efficiently optimizing reservoir performance. In previous work we inc


he conceptual geologic model is maintained and that any history-matching-related artifacts are avoided. Creating reservoir models that matc



 appearing in the flow model. In this work a systematic upscaling procedure is presented to construct a dual-porosity dual-permeability mo


s. In this work we extend these formulations to generate full dual-porosity dual-permeability MSR models and additionally introduce the use

dstones. A 3-D thermo-poroelastic model that accounts for the effect of convective heat transfer is developed in this study. Transient couple

proved history match when input into a reservoir simulation model. An ANN was developed to improve the history match with a ‘small’

eters which are then used to generate N numeric Injector-Producer-Relationship (IPR) values for the N producer-injector pairs. The IPR valu

that this is incorrect. With a correct implementation of the RML method within a Bayesian framework we show that RML does an adequate j
pe signifies the pseudosteady-state (PSS) flow period whereas the negative slope implies infinite-acting (IA) flow. Constant-rate production



eliable and sustainable performance. Table 1 presents a list of operating constraints and this paper includes examples regarding the applic

ere are many factors surface and subsurface that affect the reliability and accuracy of production forecasts. All these factors are not single-

r algorithms for managing a variety of field processes. In this study three field processes are considered. First average pressure within a res




-to-date. In this paper we apply the EnKF for continuously updating an ensemble of permeability models to match real-time multiphase prod




onal system using data from two reservoir analogs: the shallow seismic dataset from the Mahakam Fan and outcrop data from the Brushy C

iate workflows are used.� The reservoirs studied include a Permian-age carbonate reservoir in New Mexico an Upper Miocene deepw


 experimental design workflows and the different methods of generating response surface models for reservoir simulation studies there is a

aturation). To compute the fine-scale flow field two sets of basis functions - dual and primal - are constructed. The dual basis functions whic
rated data such as breakthrough times. To increase robustness of simulators especially for adverse mobility ratio flows that arise in gas inje

ifornia. All models included an initial primary depletion zone of 6 ft within 60 ft of net pay. Up to twenty-five 2.5-acre patterns were included in

esentation of the fluxes across control volume faces. These fluxes are then interpolated to define the velocity field within each control volume

 ited to two-phase water-oil flow under incompressible or slightly compressible conditions. We propose an approach to history matching thr


 ly expanded the scope and applicability of streamline-based history matching in particular for three phase flow. In our previous work we cal



able history matched models which have multiple combinations of model parameters is required to obtain a probabilistic view of the reservo

f this study 3 new horizontal wells were being planned and new gas sales agreements were being considered.� We developed a dynam

ned. In this work we extend this approach to 3D systems and introduce and evaluate procedures to decrease the computational demands of

2006). Upscaling of multi-phase flow entails a detailed flow information in the underlying fine scale. We apply adaptive prolongation and restr

bank at the water/oil interface is evaluated at every timestep thereby allowing continuous update of the ‘external pressure’ in Hall’

exacerbates the prediction problem. This study explores the possibility of using simplified approaches to compute bottomhole pressure (BHP


water-cut have also adversely affected production. The objective of this simulation study of wellbore transient flow is to understand past prod

ation methods for various required thermal parameters such as the Joule-Thompson coefficient and fluid expansivity. The approach taken i


ods. Frictional and kinetic heads are estimated using the simple homogeneous modeling approach. We present a comparative study involvin

 feasibility of open horizontal well completions hydraulic fracturing design and sanding onset prediction also warranted rock mechanics anal




s. Since in a producing horizontal well fluid inflowing temperature is not affected by elevational geothermal temperature changes the primary

he model input parameters and the predicted results. A probability distribution of the fault reactivation maximum reservoir pressure provides

re available. The first two statistical moments of the dependent variable (pressure) are conditioned on all available information directly. An ite

ormholes were observed to break through to the end of the cores an order of magnitude more rapidly than occurs in more homogeneous core



ydrocarbon phase in a two-phase system. We propose a new model of trapping and waterflood relative permeability which is applicable for
 gas production vaporization concentrates solids in the brine that will precipitate into the formation when sufficiently concentrated. This pape

d their locations to facilitate building next generation earth and flow-simulation models. The geological assessment involved mapping fault or


Several contexts of oilfield integration and their role in Digital Oilfield of the Future (DOFF) initiatives are identified. We discuss the results of

n the Gulf's deepwater1 and ultra deepwater2. Following on from the successes of an aggressive deepwater exploration campaign in the Gul

perability deliverability and system performance. This paper focuses on two key aspects of the flow assurance plan for subsea gas develop




gth and the effective production fracture length. Ineffective fracture clean-up is often cited as a likely culprit.   The main results presented in


so has been an enabler for heavy-oil developments [American Petroleum Inst. (API) gravity < 20� y > 0.934] in Brazil and the North Sea t


ble for specific circumstances since Darcy proposed the simple and useful Darcy’s law in 1856. As a consequence various correlations f
  producer reservoir-wide and facility-related will be communicated. New near-wellbore and reservoir in-depth treatments will be particularly


e obtains this information by monitoring at the wellbore. Such approaches require significant time and water-cut development to determine ho



pwater asset to demonstrate the simulator’s capabilities. In this example we matched the bottomhole pressure (BHP) and pressure/tem

ront movements detect crossflow and fluid migration assist in reservoir simulation studies etc. After a PLT is run subsequent workover is


 rtainty normally creeps into assigned well rates. This study provides a methodology wherein both the total and individual layer rates can be c


 assist in reservoir simulation studies etc. Subsequent workover operation following a PLT run is frequently performed aiming at reducing w


ont movements detect crossflow and fluid migration assist in reservoir simulation studies etc. After a PLT is run subsequent workover is r

r reliable and accurate identification of transient break points (to separate transients into relevant subsections) and investigating the impact



 urements was a risk that should be mitigated providing a major opportunity to add value. Historical experience has shown that the diamete


e test algorithms were then developed with significantly more accurate estimation of the oil saturation from a centralized-detector C/O tool in

ectives are presented in a methodical way on the following bases: field block pattern and wells. A novel diagnostic plot is presented to ass
 eption" process through the automated identification and prioritization of exception wells. The primary benefit of incorporating the surveillanc

xtures. The coal pack was initially dry and free of gas then saturated by each test gas at a series of increasing pore pressures and a constan

d several multilateral drilling patterns for CBM reservoirs are studied. The reservoir parameters that have been studied include gas content p



ment pipelines manifold configuration and associated piping etc. In many cases gas lift sourcing might require completely fresh construction


d completion issues in a stacked-reservoir situation. The ultimate objective of this study was to ascertain economic completion strategy so th

 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

ess. This paper presents a comprehensive semi-analytical model for estimating the productivity of horizontal wells completed with slotted lin

nvironments is a priority. With conventional frac pack fluids these greater depths and higher bottomhole pressures often would result in the



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




estigation of fracture clean-up mechanisms. This investigation was undertaken under a Joint Industry Project (JIP) active since the year 2002

 roseismic monitors without borehole equipment in downhole configurations represents a relatively new and untested technology for hydraulic



 eral readership of recent advances in various areas of petroleum engineering. Introduction Predicting and assuring well deliverability often

 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


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


hich consist of interval control valves (ICVs) and many sensors will be used to monitor analyze and control (MAC) injection and production

up involving unstable operation conditions and changing reservoir deliverability. The conventional steady-state based liquid load-up predictio


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

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


ompleted with electro-submersible pumps (ESPs). To effectively meet the operator’s needs for a method that would help optimize well p



 d tubing since most through tubing perforation are done in real time. Apart from space constraint at the wellsite and cumbersome logistics th
 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

 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




 ti-zone completions it is often difficult and expensive to determine which well or specific completion interval has failed most times requiring

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


 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




  been proposed and implemented to stimulate such wells. However all of these methods offer short-lived stimulation and are sometimes not

oduction rates called for different options. One of those options was the recently developed CO2 viscoelastic surfactant (VES) fluid system. It



 heterogeneities and boundaries and is the central theme of this paper.� Additionally seismic data can guide the design of pressure trans


ensive test program including flowing and static pressure surveys modified isochronal test two buildup tests and FloScan Imager (FSI) log

  and the “total mobility of all phases. The new method uses the surface flow rates and fluid properties of the flowing phases and the sam
his project.� This software was provided and developed by EPS Ltd a Weatherford company in collaboration with COPNo. Specification

 inlet separator.� Slugging mechanism and instability analysis were performed. The instability is due to combination of its low flow rate ov


 ll wells exhibit a characteristic extended transient linear flow regime followed by an exponential decline.�Similar results were obtained wh

 eliability flexibility and robustness to produce wells with high flow rates and lift heavy oil in an offshore environment. The first ESP installatio
 nsport mechanisms. We evaluate a simulation model for the displacement of carbon dioxide in a simultaneous injection of carbon dioxide an
of the steam chamber. Thus the solvent will have enough time to dissolve/disperse in the bitumen in the mobile zone before steam condensa
ding and cyclic steam stimulation (CSS) are being used extensively for the recovery of moderately viscous heavy oil from sand stone reservo
horizontals (2 300 - 3 400 ft) with openhole completions utilizing stand-alone screens through the producing interval. The reservoir section is
 oad lenses. Core data is sparsely available. Most importantly there are no structural features that may construe trapping mechanisms. In vie
 of dynamic rupture propagation from earthquake seismology to predict the nature of fractured/damage zones associated with reservoir scale
usses a newly developed propagation resistivity tool that is designed to be azimuthally sensitive for use in geosteering and formation evaluati
 This paper shows a well where the information was extracted and included in the decision making process to an extent that sets a new indus
 are often neglected. Incorporating formation pressure testing into the drilling process on the other hand creates challenges to perform mea

 from PGS Total and Beicip-Franlab has applied advanced reservoir characterization techniques to constrain petrophysical property distribu
 to establish representative relationships/correlations at the grid block scale used in SAGD flow simulation. �The mini-models are construc

 en considered drilling reach and anti-collision limitations and finally had the appropriate facilities and regional evacuation constraints impose


5/8-in casing with zones separated by packers and produced commingled through sliding sleeve doors (SSDs). In the past few years more a

can be predicted. This paper proposes a new analytical model to predict the temperature fronts and heating efficiency between and along th
mated from Ausing four different solution methods: (1) constrained pressure residuals (CPR) (2) lower block Gauss-Seidel (3) upper block G
maximum robustness and parallel efficiency of these solvers in a wide range of problems that the oil industry is currently pursuing on. A new

d to represent deformation behaviors of rocks in the geomechanics model. Porosity is selected as the coupling parameter between two coupl
 able to most gas lifted fields and will be particularly beneficial when applied to those with complex production systems and those where com
 step. The overall procedure is successfully applied to a complex channelized reservoir model involving changing well conditions. The griddin
ons there is a need for a systematic data analysis process to improve our understanding of reservoir and production conditions using the acq
 ty to fractured reservoirs the effect of oil viscosity and a comparison of its performance with WAG and CGI processes. A Hele-Shaw type m
 ms operative in the GAGD process. The model was also designed to adopt different vertical well configurations. The model experiments hav
purpose commercial core analysis simulator was used to simulate the flood experiments and to perform a parameter sensitivity study. The re
Alaska’s North Slope started producing oil at about the same time as the United Kingdom North Sea in the mid to late 1970’s. Alask
entional natural gas exploration and exploitation. As those technologies in geology geophysics drilling completion and production have ma
 ns there is a need for a systematic data analysis process to improve our understanding of reservoir and production conditions using the acq

¿½reservoirs by Clarkson et al. (2007a) and Gerami et al. (2007) and to 2-phase (gas and water) CBM wells by Clarkson et al. (2007b).�
of stress and sorption. Most models however utilize an empirical method for estimating sorption-induced strain. Recently a theoretical mod
owing material balance (FMB) and production type curves may be adapted to account for CBM storage mechanisms (i.e. adsorption) but to
 mally takes place after reconnaissance but before final appraisal. A step-wise phased CBM prospect assessment process allows us to: ga
 seams to complete which may exhibit strong contrasts in initial pressure gas content thickness and permeability.� Further the lateral co
ermeability increases over time. Field data and pressure transient analysis (PTA) for Fairway wells have revealed that coal permeability does
count for adsorbed gas. These modified material balance solutions allow for type curves" (rate or pressure solutions) to be used in a convent
 enable economic recovery of the hydrocarbon. Rock types in this class include shale and coalbed methane (CBM.) The term shale is a catch
ogy for resource assessment is developed from a geostatistical study on the Surmont lease. The uncertainty in more than 30 correlated varia
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
  urmont SAGD development that would allow better control of lift gas into the production string and in late 2007 the wells completed with gas
  ecause of well construction problems. Three wells on the remotely located wellhead platform were abandoned because of wellbore instabilit
  marine sandstone without hydraulic fracturing until drilling the CD2-37 well in 2003. The poor reservoir quality found in the southwestern edg
 productivity drivers using a database on well productivity related to different completions stimulations and production options. The database
s have been applied in the industry as an alternative completion strategy. However previously documented annular jobs have been small siz
 . In this paper we will review the unique advantages and disadvantages of horizontal openhole completions in the Colville River field. Three
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).
 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
  ls. To help ensure high rate long life completions the producing zones are frac-packed. The average perforated interval during the initial co


re stabilization. Subsequently field methods to deal with sand problems with uncertain sand rate predictions are proposed. Introduction Per
 s) rock failure and yield criteria and other non-linear rock parameters required for numerical modeling analysis; (3) perform a series of form
o the equivalent openhole completion because of two factors: the convergence of the flow to the perforations and the blockage of the flow by
ary diversion to ensure that multiple sets of perforations are adequately stimulated. Because of their high solubility and highly fractured/vugu
 by condensate and water blocking. The treatment is composed of a fluorinated material delivered in a unique and optimized glycol-alcohol s
s paper proposes a new technique to estimate cooling time and formation thermal diffusivity by using thermal transient analysis (TTA) along t




 ased on NMR random walks for multiphase fluid diffusion and relaxations combined with Kovscek’s pore-scale model for two-phase flu

eability.� In the Tengiz field a giant carbonate reservoir in western Kazakhstan a method has recently been developed to calculate appar


 a much more geologically realistic way than traditional two-point statistics (variogram-based) techniques. However in the original MPS imple


over a wide range of capillary numbers including very high values corresponding to the near-well region.� These measurements have bee



wn to be colloidally suspended in the crude oil in agreement with recent laboratory results and settle preferentially lower in the oil column in a

  were performed across a range of pressures and flow rates to simulate reservoir conditions from initial production through depletion. A sing

m diatomite is accelerated and enhanced at elevated temperature mainly due to a systematic shift toward greater water. Comparison of resul

ne set of reservoir samples consist of relatively clean calcite-rich opal-A and opal-CT diatomites. Samples from the other reservoir are clay-r



 rom pure depletion standpoint when the well penetrates a small-fault block. Distinguishing the reason for premature rate decline has a profo


 0-100 mD permeability. The upper zones contribute 10-20% of the production from thin intervals with 12-15% porosity and 2-5 mD permeab


n models were designed. Next we looked upon the development plan by performing a second round of design of experiment runs with unco
pletion occurs either at the crest for a small gas-cap reservoir or at the GOC inducing reverse cone for reservoirs with thick-gas columns. A

letely decoupled from surface and subsurface simulators. The framework has a clearly defined interface for simulators and external FM algo




  being used for non-potable uses such as by the agricultural and industrial sectors. This paper discusses the growing need for produced w
nd’s greater B8/32 operating area. Introduction The foundation of a robust produced water management strategy lies in the ability to acc


n built for a robust development program. Horizontal wells were utilized to improve oil recovery in shaly sands and to reduce water coning in

 in gas caps in various blocks of the field. Well documented production data have indicated variations in CO2 concentration in different areas




% porosity and 0.5-2 mD permeability. The current estimated original oil in place is about 500 million bbls. A volumetric uncertainty look-back

nd improve oil productivity.� Field experience has demonstrated that candidate-well selection is critical to the success of gel-polymer treatm
 l termination of wells as they reach prescribed abandonment criteria.� This method in general results in an irregular well placement patte

 on problem or require complicated modifications to the forward-model equations (the simulator). Therefore the usual approach is to formula

 ithms applied to this problem are stochastic in nature such as genetic algorithms simulated annealing and stochastic perturbation methods

The method presented in this paper was developed and used by a team of Engineers managing the Meren field waterflood project to diagno

xtures. Computational results show that this dimensionless liquid-film thickness is most likely less than 0.06 in annular flow. For such values

 During manual history matching with ESA the efforts are placed on removing the highest errors. In this automatic history matching experime

ermeability) characterized by two-point geostatistics (multi-Gaussian random fields). Realistic systems are much better described by multipoi


n (SPSA) method to history match multiphase flow production data. SPSA which has recently attracted considerable international attention in

iven by the generality and simplicity of MCS. As a black-box approach only pre/post-processing of conventional flow simulations is needed.




 for predictions. We focused on three different control volumes for CRMs: the volume of the entire field the drainage volume of each produc
mine connectivity between the producers and injectors and understanding flood efficiencies for the entire or a portion of a field. Significant in


 n compensate for heterogeneity and reservoir uncertainties and guarantees the surfactant in Type III for a longer time compared to other de

e Newton-Raphson method. External heat sources and sinks are included in source terms to model the energy interaction with over-burden a

 andles general partitioning of phase-component consumes no extra memory and only has a small amount of CPU overhead. This general




 static Poisson’s ratios. Examples illustrate how to use the petroelastic model to facilitate the integratation of 4D seismic and reservoir flo




e surface network. The integrated production model construction process consists of five steps which are framing modeling static quality ch


ble-earth-temperature model and a newly developed numerical-differentiation scheme. This approach improved the calculated wellbore fluid
s drive system. For a well under pressure control in a solution gas drive reservoir however we show that the decline is exponential and obta

 onceptualization traditionally employed to model naturally fractured reservoirs (NFRs). Using a fracture characterization procedure that is ba

 -scale flow models at the ensemble level rather than realization-by-realization agreement as is the intent of existing upscaling techniques. F


grids with high aspect ratio or severe skewness and for media with strong anisotropy or strong heterogeneity. The ideas were recently pursue

 ew wells.� In addition relative permeability curves can be generated based on the resultant fractional flow curve.� A comparison with r

e that SPU schemes may fail to predict the formation of the mobile liquid bank at the leading edge of the displacement unless an impractical
alytic tool to describe the deliverability potential for a well or a group of wells including reservoir uncertainty and/or operational constraints. T

 for flow simulation.� Four pseudo layers were added to the simulation model to allow fluid migration via faults from the lower reservoirs.ï¿



he analytical solution can be used to generate the temperature profile in a horizontal injection well for any assumed distribution of injection pr

eory with which the functioning of a closed system is derived by analyzing the derivatives of the output with respect to each input combination

 operational parameters through links to decision risk analysis software. This paper describes the novel approach used and model applicatio

h about 75 wells the tool requires only a few seconds to read the model information and produce the forecast. The time required to generate


 ant drawback of this modelling approach is the simplification introduced when a single tank model (Material balance method) is being used i
can plot as a straight-line on a p/z plot masking the existence of an active aquifer and causing a significant overestimation in gas reserves. T

proaches well-placement optimization is coupled with recursive probabilistic history-matching steps through the use of the pseudohistory con



 erformance. In previous work we incorporated adjoint-based optimal control procedures into a general-purpose simulator that allows the eff


 Creating reservoir models that match all types of data are likely to have more prediction power than methods in which some data are not ho



a dual-porosity dual-permeability model from detailed discrete fracture characterizations. The technique referred to as a multiple subregion


els and additionally introduce the use of global single-phase flow information in the computation of the upscaled interblock transmissibilities r

eloped in this study. Transient coupled pore pressure and temperature equations for non-isothermal conditions are developed based on cons

he history match with a ‘small’ number of simulation runs for a reservoir that produced oil gas and water for a period of ten years. Du

producer-injector pairs. The IPR values allow one to assess how well an injector influences the producer. This same model and an EKF wer

e show that RML does an adequate job of sampling the a posteriori distribution for the PUNQ problem. In particular the true predicted oil pro
g (IA) flow. Constant-rate production exhibits infinite slope whereas constant-pressure production produces zero slope. Mathematical justifi



ludes examples regarding the application of some of the constraints.� This table also includes consideration for the type of surveillance th

asts. All these factors are not single-valued and would generally have a band of uncertainty around them. The challenge therefore is how to

d. First average pressure within a reservoir region is maintained by adjusting the voidage replacement ratio between a group of injectors and




s to match real-time multiphase production data. We improve the previous EnKF by adding a confirming option (i.e. the flow equations are r




 and outcrop data from the Brushy Canyon Formation of West Texas. Shallow seismic data from the Mahakam Fan area shows a high-reso

w Mexico an Upper Miocene deepwater clastic reservoir in California and an Eocene-age shallow water clastic reservoir in Venezuela.�T


 servoir simulation studies there is also a growing need to share practical examples of the lessons learned in constructing experimental desi

ucted. The dual basis functions which are associated with the dual coarse grid are used to calculate the coarse scale transmissibilities. The
obility ratio flows that arise in gas injection and other EOR processes it is therefore of much interest to design truly multi-D schemes for trans

ve 2.5-acre patterns were included in the study. Results show that finely gridded models accurately capture near-vertical steam override an

 ocity field within each control volume which is then used to trace the streamlines. Existing methods for the interpolation of the velocity field a

e an approach to history matching three-phase flow using a novel compressible streamline formulation and streamline-derived analytic sens


 se flow. In our previous work we calibrated geologic models to production data by matching the water-cut and gas/oil ratio using the general



ain a probabilistic view of the reservoir performance. Once a suite of models that all match history has been obtained they are calibrated for

 sidered.� We developed a dynamic workflow to create a range of probabilistic simulation models to forecast dry-gas production under sev

 rease the computational demands of the method. This includes the use of purely local upscaling calculations for the initial estimation of coars

apply adaptive prolongation and restriction operators for flow and transport equations in constructing an approximate fine scale solution. This

 ‘external pressure’ in Hall’s formulation. We show that Hall’s formulation is a particular case of the proposed approach. Seve

o compute bottomhole pressure (BHP) from wellhead pressure (WHP) measured rates gravity of producing fluids and tubular dimensions.


nsient flow is to understand past production performance and to find ways to mitigate adverse well behavior.� Simulation showed that low

 d expansivity. The approach taken in this study entails dividing the wellbore into many sections of uniform thermal properties and deviation a


 present a comparative study involving the new model as well as those that are based on physical principles also known as semimechanistic

 also warranted rock mechanics analyses. To make sound decisions on those issues building a well-calibrated geomechanical model was cr




mal temperature changes the primary temperature differences for each phase (oil water and gas) are caused by frictional effects. While ga

 aximum reservoir pressure provides a better means to calculate a risk weighted Expected Net Present Value for management to make bette

 ll available information directly. An iterative inversion scheme is used to integrate the pressure data into the conditional statistical moment eq

an occurs in more homogeneous cores highlighting the necessity of understanding the flow and transport in vuggy carbonates. The fact that



 permeability which is applicable for the entire range of rock wettability conditions. The proposed formulation overcomes some of the limitatio
n sufficiently concentrated. This paper reports on a combined experimental and theoretical analysis on the vaporization portion of this problem

ssessment involved mapping fault orientations from seismic and analyzing image logs and cores for fractures. Fracture trends are in the NE


 identified. We discuss the results of our study and compare the results with those from other studies conducted by the SPE and also by two

 ater exploration campaign in the Gulf of Mexico a series of major discoveries were rapidly appraised and moved to development (Fig. 1). T

 surance plan for subsea gas developments the strategies for managing hydrates and the wax deposition.� Hydrate management strateg




lprit.   The main results presented in this paper were obtained using a modified conductivity cell to allow polymer concentration via leakoff a


> 0.934] in Brazil and the North Sea that otherwise would have been uneconomical. This article discusses where the industry started how te


 consequence various correlations for PI or IPR calculation have been proposed from simple analytical solutions to rigorous numerical form
n-depth treatments will be particularly detailed.� There will be discussions on Best Practices/ Lessons Learnt to improve the success rates


ater-cut development to determine how the reservoir and water-flood is performing and provide little spatial information as to how the water-fl



ole pressure (BHP) and pressure/temperature monitored about midpoint of the flow string during a multirate-test sequence lasting approxima

 PLT is run subsequent workover is routinely performed aiming at reducing water production while maintain or even increase oil and/or gas p


tal and individual layer rates can be computed independently with DTS completion tubular and other related data. To do the entire suite of


ently performed aiming at reducing water production while maintaining/increasing oil and/or gas production. Unfortunately in practice mixing


PLT is run subsequent workover is routinely performed aiming at reducing water production while maintain or even increase oil and/or gas p

ctions) and investigating the impact of continuous downhole rate data in analyzing well tests. We tested four different algorithms one based



erience has shown that the diameter of invasion can be greater than twenty inches by the time a well is logged with wireline which is beyond


om a centralized-detector C/O tool in water-filled boreholes; results reported here are primarily for this tool. The C/O technique is also being

el diagnostic plot is presented to assess well performance and identify problem wells for the field. Results from the application of these prac
 enefit of incorporating the surveillance tool in an integrated workflow is to shorten decision time and improve the quality of the decision throu

easing pore pressures and a constant effective stress until steady state. Thus the amount of adsorption varied while the effective stress was

e been studied include gas content permeability and desorption characteristics. Net present value (NPV) has been used as the yard stick fo



require completely fresh construction of entire facilities which will involve project development management costs infrastructure cost and s


n economic completion strategy so that depletion of reservoirs occurs evenly at the project’s termination. Single-well compositional simu

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

ontal wells completed with slotted liners. The semi-analytical model is obtained by coupling the reservoir flow and wellbore flow equations. Th

e pressures often would result in the need for surface treating pressures that exceed the limits of current surface equipment and tubulars. Su



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




oject (JIP) active since the year 2002. The data discussed builds on the initial results published in early 2006 which indicated that the polyme

and untested technology for hydraulic fracture diagnostics. Analysis of the surface microseismic data was carried out for five (5) hydraulic fra



 and assuring well deliverability often are important concerns when developing gas-condensate reservoirs. Many gas-condensate projects ar

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


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


ntrol (MAC) injection and production at the zonal level. Analysis of sensor data will allow operations to estimate well capacity and calculate m

y-state based liquid load-up prediction approach and nodal analysis are insufficient to answer what happens when the well shuts in restarts a


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

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


ethod that would help optimize well productivity and at the same time be cost effective without compromising the results of the operation an



wellsite and cumbersome logistics the main set back with the e-coil is its unavailability while the tractor has high operational cost. This pape
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

skins for the high-angle OHGP gas wells and finally to develop a recommendation for the optimized design. A comprehensive semi-analytic




 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

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


 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




 d stimulation and are sometimes not profitable. New experimental core flooding data using chemical treatments show that the steady-state g

astic surfactant (VES) fluid system. It has recently been employed to eliminate the disadvantages of the traditional polymer-based fluid. This



an guide the design of pressure transient tests especially the test duration to evaluate key seismic anomalies.� Other data such as produc


tests and FloScan Imager (FSI) log has been carried out to evaluate this well. The material discussed in this paper provides a good basis f

es of the flowing phases and the same relative permeability relations used in characterizing the reservoir and predicting its future performanc
boration with COPNo. Specification of the system started in 2005 based on years of prior experience with network production modelling too

to combination of its low flow rate overly-sized pipeline ID and unfavorable pipeline profile.� Flow pattern transition exists at the low spots


.�Similar results were obtained whether the analyses were performed on single dual or triple lateral wells.�Interference between later

 nvironment. The first ESP installations were challenged with high free gas and excessive sand production resulting in operational issues an
aneous injection of carbon dioxide and elemental sodium in a heavy oil reservoir. The main objective of using sodium in this process is the hi
 mobile zone before steam condensation occurs. Because the solvent blends with the bitumen it significantly lowers (up to 5 fold) the oil visc
us heavy oil from sand stone reservoirs. Another thermal process SAGD (steam assisted gravity drainage) is being used for the recovery of
cing interval. The reservoir section is drilled with a water-based Drill-in-Fluid (DIF) consisting of polymer and CaCO3 particles and displaced t
construe trapping mechanisms. In view of these challenges a permeability model was developed primarily for the Travis Peak Formation of R
zones associated with reservoir scale faults. We include geomechanical constraints in our reservoir model and propose a workflow to more r
n geosteering and formation evaluation while drilling. It uses the tilted antenna concept to produce directionally sensitive measurements that
ess to an extent that sets a new industry standard. Applying an accurate 3D rotary steerable system with openhole sidetrack capabilities incre
  creates challenges to perform measurements in a timely manner as well as the need for continuous circulation while testing to ensure wellb

nstrain petrophysical property distribution using elastic inversion products and therein reducing uncertainty in a reservoir model. Following de
on. �The mini-models are constructed on a by-facies basis honoring the spatial variability within each category. �The uncorrected mini-m

gional evacuation constraints imposed. To achieve this history-matched numerical reservoir models were first run within the framework of an


(SSDs). In the past few years more and more horizontal wells have been drilled and completed with expandable sand screens and premium

 ating efficiency between and along the horizontal well pair during the SAGD circulation phase. By using the exponential integral solution for r
block Gauss-Seidel (3) upper block Gauss-Seidel and (4) one iteration of block Gauss-Seidel. The pressure block solution in each of these
 ustry is currently pursuing on. A new generation of solvers seems to require capabilities to recapture part of the masked physics that is over

 upling parameter between two coupled models. The unknowns located on nodes and block-centers in the two models are evaluated using a
uction systems and those where compressors are a constraint on total-system performance. The output from the optimization model princip
changing well conditions. The gridding and upscaling procedures presented here may also be suitable for use with other types of structured o
 d production conditions using the acquired data and to make decisions for well performance optimization. We have successfully developed
CGI processes. A Hele-Shaw type model - consisting of two parallel glass plates (23 x 13 x � in size) with � gap between them filled wi
urations. The model experiments have shown that GAGD is a viable process for secondary and tertiary oil recovery. Oil recovery in the immis
  a parameter sensitivity study. The results demonstrated how capillary continuity across open fractures may be obtained when wetting phase
a in the mid to late 1970’s. Alaska North Slope (ANS) and UK North Sea oil production rates were approximately equal in 1980 but UK
 completion and production have matured and the price for natural has increased the development of unconventional natural gas has been
d production conditions using the acquired data and to make decisions for well performance optimization. We have successfully developed a

wells by Clarkson et al. (2007b).� The present study further enhances the flowing material balance for dry CBM reservoirs by presenting a
 d strain. Recently a theoretical model for sorption-induced strain was developed and applied to single-component adsorption/strain experim
mechanisms (i.e. adsorption) but to date the focus has been on relatively simple CBM reservoir behavior such as single-phase (gas) reser
assessment process allows us to: gain local knowledge early at low cost; progressively acquire appropriate data to systematically assess the
ermeability.� Further the lateral continuities of the individual seams vary and are often not correlatable from well-to-well.� Recently ad
  revealed that coal permeability does increase over time and is an exponential function of reservoir pressure depletion. While evidence for p
 re solutions) to be used in a conventional analysis manner. The significant challenge in the application of production data analysis for shale
ane (CBM.) The term shale is a catchall for any rock consisting of extremely small framework particles with minute pores charged with hydro
ainty in more than 30 correlated variables is calculated on a dense 2D grid using all available information including wells seismic and geolog
 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
e 2007 the wells completed with gas lift were placed on production. This paper will cover the data collection effort and analysis completed to
ndoned because of wellbore instability. Without the production contribution from these wells the first year’s production target would not b
 quality found in the southwestern edge of the field required stimulation to produce at economic rates. A hydraulic fracture treatment was perf
nd production options. The database contains 56 wells from 4 different assets and 750 acid and proppant treatments in 663 perforated interv
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
 ons in the Colville River field. Three key parameters were critical to the success of horizontal openhole completions and could be applied br
sure region close to the fracture tip). The controlled laboratory experiments showed planar fracture propagation trends as expected from thre
 uent effect of the acid in creating wormholes overcoming damage effects and stimulating productivity. The model tracks the interface betwe
erforated interval during the initial completion program was 310 ft with a maximum perforated interval of 571 ft. The typical production casing


 ions are proposed. Introduction Perforation cavities are enlarged with sand production. The cavities become contiguous and form larger ca
 analysis; (3) perform a series of formation failure and sanding potential analysis for a variety of possible well completion design scenarios us
 tions and the blockage of the flow by the wellbore itself. Because of the orientation of a horizontal well relative to the anisotropic permeability
  h solubility and highly fractured/vugular nature carbonate reservoirs in the Permian Basin show excellent response to acid fracturing treatme
 nique and optimized glycol-alcohol solvent mixture. The chemical treatment alters the wettability of water-wet sandstone to neutral wet and in
ermal transient analysis (TTA) along the horizontal wellbore under a steam heating process. A novel concept of a heating ring is also introduc




s pore-scale model for two-phase fluid saturation and wettability alteration. We use standard 2D NMR methods to interpret synthetic data set

ly been developed to calculate apparent permeability (APERM) based on flow rate from production (PLT) logs.� Incorporation of this flow


s. However in the original MPS implementation all multiple-point statistics moments computed from the training image are exported to the r


� These measurements have been made on several reservoir rocks as well as outcrop rocks and over a range of temperature pressure



ferentially lower in the oil column in accord with the Boltzmann distribution. Relevant fluid features in this case the asphaltene concentration

 production through depletion. A single-phase multirate experiment was also performed to assess inertial or non-Darcy effects. Correlations

d greater water. Comparison of results for cores from different diatomite reservoirs appears to indicate that dissolution of calcium-bearing mi

 es from the other reservoir are clay-rich opal-A diatomites. The hot alkaline fluids produced porosity channels in samples from both reservo



 r premature rate decline has a profound bearing on project economics and asset management. This talk attempts to address various issues


2-15% porosity and 2-5 mD permeability. A two stage design of experiments (DoE) based workflow was used to evaluate and optimize prima


 design of experiment runs with uncontrollable uncertainties and decisions as factors. The goal was to validate that the previously selected m
 reservoirs with thick-gas columns. Alternatively one can skip the initial oil completion where gas disposition is a nonissue. Gravity-stable flo

 for simulators and external FM algorithms. Any black-box simulator or algorithm may become a part of the system by simply adhering to the




ses the growing need for produced water reuse highlights reuse options and gaps and specifically presents Constructed Treatment Wetlan
ement strategy lies in the ability to accurately forecast future water production. Using historical water production data from existing platforms


sands and to reduce water coning in thin remaining oil columns. Horizontal drilling best practices were applied during well planning and drillin

 CO2 concentration in different areas of the field. Conventional fluid modeling could not explain the formation of gas caps at dissimilar structu




s. A volumetric uncertainty look-back (1998-2007) has allowed a historical assessment to be made for porosity and water saturation (Sw) un

l to the success of gel-polymer treatments. To date most candidate-well selections are based on anecdotal screening guidelines which ofte
s in an irregular well placement pattern as it attempts to conform to both time-invariant reservoir properties (e.g. permeability field which ma

ore the usual approach is to formulate this problem as a constrained nonlinear-programming (NLP) problem in which the constraints are cal

 and stochastic perturbation methods. These methods are usually quite inefficient requiring hundreds of simulations and thus may have limite

ren field waterflood project to diagnose pressure response anomalies and provide estimates of injection targets to achieve any expected pre

0.06 in annular flow. For such values of thin-film thickness the computed friction factor is only slightly higher than that estimated with a smoo

 automatic history matching experiment the same systematic approach was found when the convergence efficiencies were high. In this exp

re much better described by multipoint geostatistics which is capable of representing key geological structures such as channels. History ma


considerable international attention in a variety of disciplines can be easily combined with any reservoir simulator to do automatic history ma

 entional flow simulations is needed. To achieve reasonable accuracy in estimating the statistical moments of flow performance predictions h




 the drainage volume of each producer and a drainage volume between each injector/producer pair. Unlike the numerical simulation approa
e or a portion of a field. Significant insights about the flood performance over a short period can be gained by estimating fractions of injected


r a longer time compared to other designs. A comprehensive surfactant phase behavior model is required to take into account the salinity gra

energy interaction with over-burden and under-burden rocks.� The solution procedure and the treatment of phase transition to achieve sta

ount of CPU overhead. This general formulation approach was developed as part of a next generation reservoir simulation project (DeBaun e




 tation of 4D seismic and reservoir flow modeling. Introduction Time-lapse (4D) seismic is a comparison of two 3D seismic surveys over the




 e framing modeling static quality check initialization and dynamic quality check followed by forecasting. An IPM was built for Jack and use


mproved the calculated wellbore fluid-temperature profile which in turn increased the accuracy of pressure calculations at both bottomhole
at the decline is exponential and obtain an expression for the permeability. The results were applied to data from solution gas drive simulation

 characterization procedure that is based on fracture measurements from wells we stochastically generate a network of hundreds of discrete

 nt of existing upscaling techniques. For this purpose flow-based upscaling calculations are combined with a statistical procedure based on a


neity. The ideas were recently pursued in [2] where the L-method was introduced for general media in 2D. For homogeneous media and unif

  flow curve.� A comparison with relative permeability curves obtained from special core analysis can be made to provide increased confid

 displacement unless an impractical number of gridblocks is used in the simulations. In contrast the high-order FD simulator is demonstrate
 nty and/or operational constraints. This paper presents a simple methodology for establishing reservoir parameters and predicting a well’

via faults from the lower reservoirs.� The new model has 100 m x 100 m areal cells and individual layers with an average thickness of 6 ft.



 y assumed distribution of injection profile along the length of the well including injection profile that is uniform skewed toward the heel or the

with respect to each input combination. For the injector-producer relationship identification problem we use sensitivity analysis to determine th

  approach used and model application. Given the presence of multiple reservoir models multiple PVT descriptions three-phase flow and

recast. The time required to generate the forecast output in the desired format depends on the duration of forecasting the size of the field a


erial balance method) is being used instead of a fine grid simulation model. The material balance method assumes every well contacts all hyd
ant overestimation in gas reserves. The authors in this paper simulate synthetic cases of gas reservoir/aquifer models using a forward mode

ugh the use of the pseudohistory concept. The pseudohistory is defined as the probable (future) response of the reservoir that is generated b



purpose simulator that allows the efficient long term maximization of NPV by optimally controlling well settings with time (similar developmen


 thods in which some data are not honored.� The first part of the paper reviews the details of the PPM and the next part of this paper des



  referred to as a multiple subregion (MSR) model represents an extension of an earlier method that did not account for gravitational effects


pscaled interblock transmissibilities required by the method. The resulting models are used for waterflood simulations and more interestingly

nditions are developed based on conservation laws. Thermal effects are generated by the temperature imbalance between the drilling fluid a

 d water for a period of ten years. Due to a lack of specific protocols for this type of study the trial and error process was utilized to establish

r. This same model and an EKF were first used in Liu et al [5]. The modified EKF used in this paper avoids problems that can arise when pr

n particular the true predicted oil production lies within the band of predictions generated with the RML method and is not biased. We also a
uces zero slope. Mathematical justifications for these diagnostic signatures are presented. During PSS flow wells belonging to the same co



 eration for the type of surveillance that is needed to apply the constraints.� Discussion within the paper shows that the most relevant type

m. The challenge therefore is how to generate production forecasts in the face of these uncertainties. Previous production forecasts have bee

atio between a group of injectors and producers. Second control systems are used for the prevention of gas/water coning for single and mul




 option (i.e. the flow equations are re-solved from the previous assimilating step to the current step using the updated current permeability m




ahakam Fan area shows a high-resolution deepwater channel-levee system consisting of 10 migrating channels. Using an experimental des

er clastic reservoir in Venezuela.�Two dimensional cross section models of the deepwater clastic reservoir showed that cumulative produ


 ed in constructing experimental designs and using response surface models to interrogate the experimental design outcomes. After extens

e coarse scale transmissibilities. The fine-scale pressure field is computed from the coarse grid pressure via superposition of the dual basis
esign truly multi-D schemes for transport that remove or at least strongly reduce the sensitivity to grid design. We present a new upwind bi

pture near-vertical steam override and oil drainage by gravity with a near-horizontal steam/oil interface. High injection pressures observed in

he interpolation of the velocity field and integration of the streamlines do not preserve the accuracy of the fluxes computed by MPFA discreti

and streamline-derived analytic sensitivities. First we utilize a generalized streamline model to account for compressible flow by introducing


ut and gas/oil ratio using the generalized travel time inversion (GTTI) technique. For field applications however the highly non-monotonic pr



een obtained they are calibrated for predicting the future performance and assessment of uncertainty and risk associated with a particular de

orecast dry-gas production under several production scenarios in the Chuchupa field.�Recent seismic re-interpretation a new stratigraph

tions for the initial estimation of coarse-scale transmissibilities and the use of reduced border regions during the iterations. This is shown to d

approximate fine scale solution. This new method eliminates inaccuracy associated with the traditional upscaling method which relies on pre

ase of the proposed approach. Several simulated and field examples demonstrate the value of reformulated Hall analysis. Because Hall form

cing fluids and tubular dimensions. BHP computations on three independent data sets comprising 167 gas/condensate-well tests suggest th


vior.� Simulation showed that low ESP efficiency could be related to down-hole slugging. GOR was the most significant factor for slugging

rm thermal properties and deviation angle. The governing differential equation is solved for each section with fluid temperature from the prio


ples also known as semimechanistic models. These models include those of Ansari et al Gomez et al. and OLGA. Two other widely used e

 brated geomechanical model was critical. In this study we reviewed the drilling completion logging and production information from severa




aused by frictional effects. While gas production usually causes a temperature decrease water entry results in either warming or cooling of

Value for management to make better decisions on steam flooding and to anticipate potential consequences. In this study a geomechanical

the conditional statistical moment equations (CSMEs). That is the available information is used to condition or improve the estimates of the

rt in vuggy carbonates. The fact that acid channeled through the vugular cores following the path of the vug system was underlined with com



ation overcomes some of the limitations of existing trapping and relative permeability models. The new model is validated by means of pore-n
he vaporization portion of this problem for dry gas injection. Experiments have been performed previously to determine the rate of water vap

ctures. Fracture trends are in the NE and SW quadrants and fractures are mineralized toward the south and west of the field. Pressure falloff


onducted by the SPE and also by two integrated oil companies (IOCs). We address the goal of “reducing time to decision and show how

nd moved to development (Fig. 1). This paper will give a high level review of some of the recent development challenges for the deepwater a

on.� Hydrate management strategy must focus on preventing blockages versus preventing hydrate formation.� To this end the enginee




w polymer concentration via leakoff and measurements of flow initiation gradients. The paper will discuss the experimental set-up and som


es where the industry started how technology has evolved and the lessons learned that are being applied to increase the application envelo


 solutions to rigorous numerical formulations in the literature. As horizontal or multilateral wells have been occupying an ever-increasing sha
 Learnt to improve the success rates and mention of challenges ahead.


 ial information as to how the water-flood is affected by faults preferential pathways and structural variation. 4D seismic methods represent a



ate-test sequence lasting approximately 60 hours. Calculations show that thermal effects are exacerbated by increasing flow rate and increa

 tain or even increase oil and/or gas production from the well. Unfortunately mixing results have been obtained through workover operations


elated data. To do the entire suite of calculations a wellbore model handling steady fluid flow and unsteady-state heat transfer estimates a p


on. Unfortunately in practice mixing results have been obtained through workover operations designed based on PLTs due to poor logging


 ain or even increase oil and/or gas production from the well. Unfortunately mixing results have been obtained through workover operations

d four different algorithms one based on the stationary Harr wavelet transform method and others based on nonwavelet approaches such as



 logged with wireline which is beyond the limits of investigation for density and neutron tools rendering the interpretation of fluid types ambigu


ool. The C/O technique is also being tested in producers using the corresponding focused tool; we include an example of a successful test of

ults from the application of these practices in a pilot area are shared indicating that the nominal decline rate improved from 33 to 18% per ye
 rove the quality of the decision through an automated process.� Other benefits include timelier proactive problem identification better use

 varied while the effective stress was held constant. Results show that (i) permeability decreases with an increase of pore pressure at fixed in

V) has been used as the yard stick for comparing different drilling configurations. Configurations that have been investigated are single- dual



ment costs infrastructure cost and space limitation especially in the case of offshore locations. In the Southern Offshore Area of Chevron op


tion. Single-well compositional simulations formed the backbone for our evaluation of three completion options. Each reservoir was characte

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

 flow and wellbore flow equations. The model includes the additional pressure drops due to mechanical skin and non-Darcy effect. Additiona

 surface equipment and tubulars. Surface treating pressure can be calculated using the equation: Ps = BHTP + Pfric – Phyd …………â



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




2006 which indicated that the polymer concentrates only in the filter cake and that flow along the fracture encounters significant yield stress w

 s carried out for five (5) hydraulic fracture stages to: (1) determine the applicability of the surface microseismic approach in the absence of a



 rs. Many gas-condensate projects are in deep hot low-permeability reservoirs for which well costs are a significant part of the project econo

presented as a function of liquid relative permeability and liquid saturation. In our measurements the wetting state is varied by the treatment


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


stimate well capacity and calculate measure actual flow rates. Decisions for operational control will be made based on the data analysis the

ens when the well shuts in restarts and eventually dies. To address the intrinsically transient multi-phase flow problems a combined study o


 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

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


mising the results of the operation an improvement over traditional tubing-conveyed perforating (TCP) was required. A propellant-assisted (P



 has high operational cost. This paper outlines the successful perforation of horizontal wells in the Niger Delta while addressing the operation
 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

sign. A comprehensive semi-analytical model was developed based on modification of the horizontal well model. The additional pressure dro




 edy be evaluated. One GOM producer engaged the services of a proppant supplier to determine whether a suite of proppants/gravel could

 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


 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




 atments show that the steady-state gas and condensate relative permeability in both outcrop and reservoir sandstones can be increased by

 traditional polymer-based fluid. This VES-CO2 fluid system combines the benefits of viscoelastic surfactant-based fluid—such as low forma



malies.� Other data such as production history core data formation evaluation from well logs analog information on channel geometry etc


 in this paper provides a good basis for evaluating long-term production potential of horizontal wells exploiting tight and thin reservoirs with re

 and predicting its future performance. The method has been verified by comparing the results from analyzing several synthetic tests that we
 ith network production modelling tools in the Ekofisk area to simulate and optimise production from the reservoir to the export meter. The sy

tern transition exists at the low spots and liquid accumulates and blocks the flow. In the low pressure system once gas blows out and system


wells.�Interference between laterals was not observed.       Introduction The application of horizontal and multilateral wells is gaining mom

 on resulting in operational issues and a number of failures. Even in this hostile environment production peaked at 37 800 BOPD during Nov
using sodium in this process is the highly exothermic reaction of sodium with the in-situ water that results in the liberation of heat that in turn
 antly lowers (up to 5 fold) the oil viscosity. This process has the potential to accelerate recovery with less steam requirement per barrel of oil
ge) is being used for the recovery of higher viscosity heavy oil and bitumen from oil sand. Some of these processes are apparently very succ
and CaCO3 particles and displaced to a solids-free DIF prior to running the screens. Typically acid is used to degrade water-based DIF filte
ily for the Travis Peak Formation of Robertson and Leon counties where it has produced 96 BCF of gas and 0.54 MMbbl of oil. A permeabil
 el and propose a workflow to more routinely incorporate damage zones into reservoir simulation models. The model we propose calculates
ionally sensitive measurements that are lacking in traditional LWD propagation tools. This paper also discusses the theory and the developm
 openhole sidetrack capabilities increase well design flexibility and the ability to act on the real-time LWD data. The bottom hole assembly us
 culation while testing to ensure wellbore safety. Formation testing at Bohai Bay is difficult because of the unconsolidated formations and all

 ty in a reservoir model. Following detailed rock typing core and log analysis from approximately 5400 feet of core and from 26 wells and log
 category. �The uncorrected mini-model flow results lead to a too-narrow range of permeability. �Geostatistical scaling laws are applied

re first run within the framework of an infill well-location optimization software package. Then drilling constraints were imposed with drilling p


pandable sand screens and premium screens. Most of the wells produce 10 000 to 15 000 BFPD using electrical submersible pumps (ESPs)

 the exponential integral solution for radial heating in a long cylinder and superposition in space for multi-heating sources the proposed mode
ssure block solution in each of these different schemes is calculated using the Algebraic Multi Grid (AMG) method. The inverse of the saturat
 rt of the masked physics that is overlooked by strictly algebraic procedures in order to retrieve part of the loss efficiency and furthermore to

he two models are evaluated using an area weighting technique The proposed model has been implemented on the Linux PC clusters for so
 t from the optimization model principally comprises recommended values for individual-well gas lift injection rates separator pressures com
or use with other types of structured or unstructured grid systems. Introduction Modern geological and geostatistical tools provide highly deta
n. We have successfully developed a model to predict well flowing pressure and temperature (i.e. the forward model) and applied an invers
  with � gap between them filled with Ottawa silica sand - has been used in all experiments with a perforated plastic tube serving as the ho
oil recovery. Oil recovery in the immiscible secondary mode was as high as 83% IOIP and the oil recovery in the immiscible tertiary mode was
may be obtained when wetting phase bridges were established. A viscous component over the open fractures was provided when the wetting
approximately equal in 1980 but UK North Sea oil production has exceeded that of the Alaska ANS by more than 40% in recent years. The
 nconventional natural gas has been blossoming for last decade globally. Without question it is certain that the development of unconventio
 . We have successfully developed a model to predict well flowing pressure and temperature (i.e. the forward model) and applied inversion

r dry CBM reservoirs by presenting a p/z* implementation of the concept. This application �while accounting for the distinguishing charact
 omponent adsorption/strain experimental data. The new model was developed from basic thermodynamic principles and is more predictive
 ior such as single-phase (gas) reservoirs with static effective permeability. The major contribution of the current work is the adaptation of m
ate data to systematically assess the geological situation and reservoir conditions; define and attempt to fill knowledge gaps that represent ri
 e from well-to-well.� Recently advances in production data analysis (PDA) methodologies have been made for CBM wells; techniques de
 sure depletion. While evidence for pressure dependent permeability in CBM reservoirs has been presented in the literature before this work
of production data analysis for shale gas systems is to determine what the parameter values (analysis results) represent within the context o
with minute pores charged with hydrocarbon and includes carbonate and quartz-rich rocks. Another type of unconventional reservoir is stacke
n including wells seismic and geologic trends. The correlation structure between the variables is modeled under a multivariate Gaussian mo
 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
 ion effort and analysis completed to determine the efficiency of the two types of gas lift nozzles used in the completions the methodology for
 r’s production target would not be met. To meet the production targets a complete well redesign was undertaken. First the tubing was u
hydraulic fracture treatment was performed resulting in a 200% production increase. Over the past three years a stimulation program has ev
nt treatments in 663 perforated intervals. It was found that the absolute total production per interval is similar for all assets; however the draw
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
 completions and could be applied broadly in other situations. Using these three criteria other major North Slope reservoirs were evaluated to
 agation trends as expected from three-dimensional modeling. Introduction Since the inception of the hydraulic fracturing technique as a me
 The model tracks the interface between the acid and the completion fluid in the wellbore models transient flow in the reservoir during acid in
 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


come contiguous and form larger cavities around a cased hole. Finally they form irregular cavities as shown in Fig.1. � Fig.1 Cavity grow
well completion design scenarios using 3-D finite element technique for rock structure coupled with well production and fluid flow simulation.
elative to the anisotropic permeability field perforation skin models for vertical wells that consider these effects notably the Karakas and Tar
nt response to acid fracturing treatments. However inadequate diversion can leave substantial portions of the reservoir untreated. Different a
r-wet sandstone to neutral wet and increases the gas relative permeability. The increase in gas relative permeability was quantified by comp
cept of a heating ring is also introduced to measure the heat storage in the heated bitumen at the time of testing. Heating ring can be consid




 ethods to interpret synthetic data sets for diverse petrophysical configurations including two-phase saturations with different oil grades mixe

 ) logs.� Incorporation of this flow calibrated apparent permeability into the static geologic earth model offers an elegant solution to the lon


e training image are exported to the reservoir model without processing which allows simulating only categorical or discretized variables. This


er a range of temperature pressure connate water saturation and hydrocarbon composition typical of gas-condensate reservoirs. PVT data



s case the asphaltene concentration gradient are then integrated in a geologic model and used to predict crude oil properties and DFA logs

 l or non-Darcy effects. Correlations were developed to represent both the gas and condensate relative permeabilities as a function of capill

hat dissolution of calcium-bearing minerals tends to retard fines production and delay changes in core wettability. Longterm corefloods exam

annels in samples from both reservoir types. These small channels (10 mm to 2 mm in diameter) form initially at the inlet and grow slowly tow



lk attempts to address various issues starting with well productivity and considering various completion options to modeling the coupled rese


 used to evaluate and optimize primary reservoir development. Reservoir uncertainties affecting volume and connectivity were assessed in th


validate that the previously selected models reasonably represented P10 P50 and P90 oil recoveries and net present value after including
sition is a nonissue. Gravity-stable flooding is required to maximize reserves. Extensive flow simulations in multiple history-matched models

 the system by simply adhering to the FM interface which is discussed in this paper. The FM framework capabilities are demonstrated on se




sents Constructed Treatment Wetlands (CTW) as a technology for the treatment of produced water and the facilitation of water reuse. The C
duction data from existing platforms future drilling activities and impact of artificial lift we can generate forecasts of produced water. Current


pplied during well planning and drilling executions such as optimum well designs specific LWD/MWD tool selections low fluid loss drilling flu

ation of gas caps at dissimilar structural positions nor could it explain the existence of oil legs at pressures below the apparent (predicted) bu




porosity and water saturation (Sw) uncertainty. This look-back based assessment of porosity and Sw uncertainty allows the impact of increas

 otal screening guidelines which often results in inconsistent treatment outcomes. With only pretreatment well data as input parameters the
ties (e.g. permeability field which may be nonuniform) and time-varying properties (e.g. pressure and saturation field).�As such it is a we

blem in which the constraints are calculated explicitly after the dynamic system is solved. The most popular of this category of methods for o

 simulations and thus may have limited application to large-scale simulation models with many wells. We propose a novel continuous appro

 targets to achieve any expected pressure response for the project reservoirs without the use of numerical models. It uses the slopes of the c

gher than that estimated with a smooth-channel assumption. When the homogeneous model is used to compute pressure gradient by ignorin

ce efficiencies were high. In this experiment a simple parametric search routine was used to compare the performance of a data weighted (

uctures such as channels. History matching algorithms that are able to reproduce realistic geology provide enhanced predictive capacity and


simulator to do automatic history matching. The SPSA method uses stochastic simultaneous perturbation of all parameters to generate a do

nts of flow performance predictions however large numbers of realizations are usually necessary. Here we use an alterative direct approac




like the numerical simulation approach the CRMs use only production/injection data to predict performance which provides simplicity and s
ed by estimating fractions of injected fluid being directed from an injector to various producers and the time taken for an injection signal to re


ed to take into account the salinity gradient design with all possible phase transitions. The development discussed in this paper enables accu

ent of phase transition to achieve stable non-linear iterations are discussed. The simulator is verified by comparing results from problem No.

eservoir simulation project (DeBaun et al. 2005) for “next generation is the ability to accommodate fluid models currently used in reservo




n of two 3D seismic surveys over the same spatial region at different points in time. Seismic attributes such as P-wave and S-wave velocities




g. An IPM was built for Jack and used as the primary forecasting method for (1) evaluation of artificial lift alternatives (gas lift sea floor boos


sure calculations at both bottomhole and wellhead. The proposed simulator accurately mimics afterflow during surface shut-in by computing
ata from solution gas drive simulation models and are presented. Application to field data is also presented. Introduction Decline curve anal

ate a network of hundreds of discrete fractures for a large sector (17 mi � 1.4 mi � 1.1 mi). A novel semi-automatic gridding technique is

ith a statistical procedure based on a cluster analysis. This approach allows us to compute numerically the upscaled two-phase flow function


D. For homogeneous media and uniform grid this method has four-point flux stencils and seven-point cell stencils in two dimensions. The re

 be made to provide increased confidence. In order to develop an fw (water cut) versus Sw (prevailing water saturation) relationship from his

h-order FD simulator is demonstrated to accurately predict the liquid bank at much lower grid resolution providing for a more efficient simula
 parameters and predicting a well’s future deliverability potential. Field examples show that computing reservoir parameters from buildup

ers with an average thickness of 6 ft. �Overall this new model has 18 times refinement compared to the previous model for the Wara rese



niform skewed toward the heel or the toe or exhibits some discontinuity (e.g. leakoff into a high permeability streak or fracture). This paper

se sensitivity analysis to determine the injector-producer relationships by varying the injection rates i.e. the inputs to a trained neural networ

 descriptions three-phase flow and a variety of well types from infill to ‘new field’ the best source of reservoir performance profiles f

                                                                                                                                  Introductio
 of forecasting the size of the field and whether the output is to be produced as a text file or a Microsoft Excel spreadsheet. 1.	


d assumes every well contacts all hydrocarbons and that geological heterogeneity is not a factor in recovery. It is necessary to know how reli
aquifer models using a forward model and an inverse model that were programmed in visual basic to show that the combination of certain ra

se of the reservoir that is generated by a probabilistic forecasting model. To test the results of the proposed approach an example reservoir



ettings with time (similar developments have also been reported by others). Furthermore our recent extensions namely a new “approxim


M and the next part of this paper describes the additional work that is required to history-match real reservoirs using this method. Then a geo



d not account for gravitational effects. The subregions (or subgrid) are constructed for each coarse block using the iso-pressure curves obtai


 d simulations and more interestingly for compositional simulations of first-contactmiscible gas injection. In a series of flow simulations invol

 mbalance between the drilling fluid and drilled formations and increase as the temperature imbalance increases. Cooling the formation is fo

 ror process was utilized to establish guidelines and suggestions. The neural network was developed by using an inverse solution method to

oids problems that can arise when processing real data and provides additional information that is useful for future research. Our modified E

 method and is not biased. We also apply the ensemble Kalman Filter (EnKF) method to the PUNQ data set and show that this method also
 flow wells belonging to the same container will exhibit the same slope. Differences in slope are an indication of reservoir compartmentaliz



 er shows that the most relevant types of operating constraints are often not being used and also addresses appropriate operating limits for c

evious production forecasts have been generated using deterministic values for these uncertainties at their end points – 3 forecasts. This m

 gas/water coning for single and multiple wells. Finally the average temperature within a reservoir region is maintained at a critical value by c




ng the updated current permeability models). By doing so we ensure that the updated static and dynamic parameters are always consistent w




 hannels. Using an experimental design framework and a series of three increasingly complex models we investigated the effect of nine diffe

 ervoir showed that cumulative production and water breakthrough times were essentially the same for models using the two major stratigra


ental design outcomes. After extensively applying these concepts for over 18 months in identifying the major sub-surface uncertainties expl

e via superposition of the dual basis functions. Having a locally conservative fine scale velocity field is essential for accurate solution of the sa
design. We present a new upwind biased truly multi-D family of schemes for multi-phase transport capable of handling counter-current flow a

High injection pressures observed in many prior simulations are primarily a result of confined reservoir models. Steam-zone pressures and te

 e fluxes computed by MPFA discretizations. Here we propose a method for the reconstruction of the velocity field with high-order accuracy f

for compressible flow by introducing an ‘effective density’ of total fluids along streamlines. This density term rigorously captures chan


 owever the highly non-monotonic profile of the gas/oil ratio data often presents a challenge to this technique. In this work we present a trans



nd risk associated with a particular development plan. In this paper we demonstrate a structured approach to history matching uncertainty a

 c re-interpretation a new stratigraphic study and a revision of the petrophysical model resulted in new probabilistic static models for the fiel

uring the iterations. This is shown to decrease the computational requirements of the reduced procedure significantly relative to the full metho

 pscaling method which relies on prescribed inaccurate boundary conditions in computing upscaled variables. The new upscaling algorithm is

ated Hall analysis. Because Hall formulation involves an integral the resultant signature by nature is insensitive in revealing clues about su

gas/condensate-well tests suggest that the no-slip homogeneous model applies quite well. Statistical results show the homogeneous model


he most significant factor for slugging and increasing water cut made slugging worse. The sinusoidal wellbore trajectory was studied to optim

  with fluid temperature from the prior section as the boundary condition. This piecewise approach makes the model versatile allowing step-


  and OLGA. Two other widely used empirical models Hagedorn and Brown and PE- 2 are also included. The main ingredient of this study e

d production information from several wells across the field. We found that (1) The Kotabatak field has a general maximum horizontal stress




 sults in either warming or cooling of the wellbore. Warmer water entry is a result of water flow from a warmer aquifer below the producing zo

nces. In this study a geomechanical model was established for the Batang Field Central Sumatra Indonesia. Using the geomechanical mo

ition or improve the estimates of the first two moments of permeability pressure and velocity directly. This is different from Monte Carlo (M

 vug system was underlined with computerized tomography scans of the cores before and after acid injection. This observation proposes tha



model is validated by means of pore-network simulation of primary drainage and waterflooding. We study the dependence of trapped (residua
 ly to determine the rate of water vaporization from Berea core samples at uniform initial water saturation (Zuluaga and Monsalve 2003). The

and west of the field. Pressure falloff tests on some peripheral injectors indicate partially sealing faults. Most of these wells lie on seismic-sca


cing time to decision and show how even the most basic data-integration gaps can slow decisions with great economic impact. In informatio

pment challenges for the deepwater and ultra deepwater fields in the GoM and will explain how these challenges were addressed and how th

rmation.� To this end the engineer must evaluate flow conditions system geometry and production profiles in addition to temperature an




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


ed to increase the application envelope and reliability of this completion method.�The review covers advances in openhole-drilling techniq


en occupying an ever-increasing share of hydrocarbon production since the 1980s more accurate PI or IPR estimation has been emerging a



ion. 4D seismic methods represent a powerful tool to assist reservoir management. This work describes the planning implementation of an



ed by increasing flow rate and increasing gauge distance from the perforations. Second we performed a detailed uncertainty analysis with e

btained through workover operations designed based on PLT due to poor logging procedure unreasonable PL tool selection poorly execute


ady-state heat transfer estimates a production rate given wellhead pressure and temperature. The same model is then used to compute the


 based on PLTs due to poor logging procedure unreasonable PL tool selection poorly executed surveys inappropriate interpretation etc. I


tained through workover operations designed based on PLT due to poor logging procedure unreasonable PL tool selection poorly execute

d on nonwavelet approaches such as Savitzky-Golay Smoothing Filters and a novel pattern recognition approach called the Segmentation Me



he interpretation of fluid types ambiguous in most hydrocarbon bearing sands in this basin. To reduce this uncertainty comprehensive wirelin


 e an example of a successful test of the tool in an unperforated well. The paper identifies further development needed to use C/O technique

 ate improved from 33 to 18% per year without any infill drilling. The change in the decline rate is attributed primarily to effective waterflood m
tive problem identification better use of the practitioner's time (focus on analysis rather than identification) elimination of repetitive data gath

n increase of pore pressure at fixed injection gas composition and (ii) permeability change is a function of the injected gas composition. As th

e been investigated are single- dual- tri- and quadlateral wells along with fishbone (also known as pinnate) wells. In these configurations th



outhern Offshore Area of Chevron operations several wells have quit and require some kind of support to flow to surface. Artificial lift (gas lif


options. Each reservoir was characterized by history matching drillstem tests (DSTs). Experimental design (ED) reduced the large number o

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

 skin and non-Darcy effect. Additionally the model could handle non-uniform flux non-uniform skin distribution and selective completion with

BHTP + Pfric – Phyd …………………….. (1) Ps = surface pressure BHTP = bottomhole treating pressure Pfrict = friction pressure P



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




e encounters significant yield stress when the filter cake cumulative thickness dominates the width of the fracture. The new results presente

 eismic approach in the absence of an offset observation well; and (2) characterize fracture height azimuth length and symmetry with respe



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

etting state is varied by the treatment with a fluorochemical compound. Then the effect of wettability on the high-velocity coefficient in two-ph


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


 ade based on the data analysis the results of which will be used to optimize overall field performance and maximize financial returns. In this

e flow problems a combined study of completion inflow analysis and wellbore dynamic simulation was performed. The analysis indicates th


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

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


 as required. A propellant-assisted (PA) perforating method that could optimize well productivity while maintaining stringent health safety and



Delta while addressing the operational issues encountered. The first case history is Addax ORW-11H a horizontal well planned to have the
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

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




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

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


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




 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

tant-based fluid—such as low formation damage superior proppant transport and low friction pressures—with carbon dioxide advantages



information on channel geometry etc. is also important in getting a better understanding of reservoir description. While we briefly discuss all


oiting tight and thin reservoirs with reservoir pressures close to the bubble-point pressure. Test data interpretation highlights successful dev

lyzing several synthetic tests that were produced by a numerical simulator with the input values. Use of the method with field data is also des
 reservoir to the export meter. The system is designed to fully utilise the OOC’s continuous measurement and recording systems throug

stem once gas blows out and system pressure drops the pipeline inlet gas increases velocity and picks up a new hydrodynamic slug.� Th


and multilateral wells is gaining momentum worldwide due to their ability to drain reservoirs more effectively.�This advantage is even mo

n peaked at 37 800 BOPD during November 2003 before declining as a consequence of reservoir pressure depletion. Moreover the lower re
s in the liberation of heat that in turn reduces the oil viscosity. Another important advantage of this process is the formation of sodium hydrox
 s steam requirement per barrel of oil produced. The important factors that control the performance of the ES-SAGD process are the solvent
e processes are apparently very successful with ultimate recovery over 80%. Application of thermal processes to the carbonates poses a dif
used to degrade water-based DIF filtercake and remove CaCO3 contained in the filtercake. The use of a common acid was not an option for
  and 0.54 MMbbl of oil. A permeability model was developed by integrating core and log data using the Adaptive Neuro Fuzzy Logic Inferenc
s. The model we propose calculates the extent of the damage zone along the fault plane by estimating the stress perturbation associated with
scusses the theory and the development of this tool as well as the experimentation and numerical modeling data used to characterize its azi
D data. The bottom hole assembly used consisted not only the standard LWD services such as gamma ray propagation resistivity density n
 e unconsolidated formations and all aspects associated with this type of environment such as borehole stability hole washouts sanding wh

eet of core and from 26 wells and logs from 90 well penetrations the team observed that there was considerable heterogeneity in this “h
 eostatistical scaling laws are applied to correct the permeability values. This paper presents a permeability modeling procedure with applica

nstraints were imposed with drilling planning software and facility constraints were included via a surface coupling system for multiple-reservo


electrical submersible pumps (ESPs). In these commingled completions the water cut rises from a few percent to 80% to 90% within the firs

 heating sources the proposed model can be used to predict these temperature profiles provided that the steam temperatures or pressures
G) method. The inverse of the saturation (or more generally the nonpressure) blocks are approximated using Line Successive Over Relaxati
e loss efficiency and furthermore to obtain insights that make them adaptable to different reservoir situations. In this work we show that this

ented on the Linux PC clusters for solving 2D compositional reservoir problems considering geomechanics effects. These results indicate tha
 tion rates separator pressures compressor discharge pressures and compressor use. Field results are presented in this paper to demonst
geostatistical tools provide highly detailed descriptions of the spatial variation of reservoir properties resulting in fine-grid models consisting o
orward model) and applied an inversion method to detect water and gas entry into�wellbore using synthetic data generated by the forward
 orated plastic tube serving as the horizontal production well placed at the bottom of the model. Vertical tubes were placed at different depths
  y in the immiscible tertiary mode was 54% ROIP. The model has also shown that the gas injection depth may not have an influence on oil re
ctures was provided when the wetting preference between the injected fluid and the rock surface allowed the formation of stable wetting phas
more than 40% in recent years. The UK North Sea and ANS share similar areal sizes and other similarities but differ in several key areas in
that the development of unconventional natural gas in China will be blossoming in the coming decades. However there are significant challe
 rward model) and applied inversion method to detect water and gas entry into wellbore using the synthetic data generated by the forward mo

ounting for the distinguishing characteristics of a CBM reservoir �uses the industry-standard practice of p/z material balance to calculate o
mic principles and is more predictive than the empirically-based approaches. In this paper the theoretical model is expanded to incorporate m
 e current work is the adaptation of modern PDA techniques (by use of modified material balance time/pseudotime and pseudopressure defin
  fill knowledge gaps that represent risk and uncertainty; increasingly understand the distributions of key parameters that control reserves de
n made for CBM wells; techniques developed for tight gas and conventional oil and gas reservoirs have been adapted by incorporating som
nted in the literature before this work seeks to compare the magnitude and functional form in two different reservoir units. In the high produc
esults) represent within the context of the inherent complexity of these systems. In this work we propose a slight (but substantive) modificatio
 of unconventional reservoir is stacked pay units exhibiting somewhat better pore characteristics than in the case outlined above but with the
ed under a multivariate Gaussian model. The local distributions of uncertainty have been checked with cross validation and with more than 1
zone oil fields around the world to increase oil production rate while reducing water production rate and lifting costs. Introduction Kuparuk Fi
the completions the methodology for optimization of SAGD gas lift systems and recommendations for future improvement. Background Sur
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
  years a stimulation program has evolved with improvements in candidate selection performance and predictability. Future plans include co
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
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
 th Slope reservoirs were evaluated to determine their potential for horizontal-openhole-completion applications. Focus areas in this evaluatio
ydraulic fracturing technique as a means to improve productivity of oil and gas wells the hydraulic fracturing community has determined certa
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
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


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
 production and fluid flow simulation.� The types of completion design analyzed include cased hole completion using conventional perfora
effects notably the Karakas and Tariq model (1991) are not directly applicable to perforated horizontal completions. Using appropriate varia
of the reservoir untreated. Different acid systems have been developed to counter the problems in acid fracture stimulations. Chemical and m
 permeability was quantified by comparing the gas relative permeabilities before and after treatment. Improvements in the gas relative perme
f testing. Heating ring can be considered analogous to a drainage area in a conventional pressure transient analysis. The proposed cooling




 rations with different oil grades mixed wettability or carbonate pore heterogeneity. Results from our study indicate that for both water-wet a

l offers an elegant solution to the long-standing problem of how to best incorporate dynamic PLT data into a reservoir model.� A reservoir


egorical or discretized variables. This implementation is appropriate with clastic reservoirs for which typically depositional facies are simulat


as-condensate reservoirs. PVT data of gas-condensate fluids can be used to predict the ratio of the gas to the condensate relative permeabi



ct crude oil properties and DFA logs for all hydraulically connected sections of the reservoir. Predicted and newly acquired DFA log data mat

 permeabilities as a function of capillary number. A nearly 20-fold increase in gas relative permeability was observed from the low- to high-ca

ettability. Longterm corefloods examine the ability of diatomite to sustain thermal operations. Core permeabilities following significant volume

nitially at the inlet and grow slowly toward the outlet as experiments progressed. Fines mobilization and perhaps hydraulic action during force



options to modeling the coupled reservoir/wellbore/surface network system. In particular we explore how uncertainties in volumetrics and ca


 and connectivity were assessed in the first stage of the workflow. The second stage of the workflow focused on dynamic uncertainties. The


nd net present value after including decisions in the design. The validation worked out properly reinforcing the confidence in the model sele
 in multiple history-matched models have shown that the proposed strategy improves recovery significantly. Two field examples are present

k capabilities are demonstrated on several examples involving diversified production strategies and multiple surface/subsurface simulators. O




d the facilitation of water reuse. The Chevron/Cawelo water reuse project and demonstration CTW located in California’s San Joaquin V
orecasts of produced water. Currently in B8/32 asset we produce about 68 000 bbl/day of water and an additional 20 000 bbl/day of water i


ool selections low fluid loss drilling fluids real-time geosteering data monitoring and the cleaning of the pay zone during completions were ap

res below the apparent (predicted) bubble point pressure. A fluid characterization model was performed in the El Trapial field in order to imp




certainty allows the impact of increasing quantity of data changing analytical workflows and updating interpretations to be examined. Based

nt well data as input parameters the neural networks developed in this work can accurately predict the post-treatment cumulative oil product
aturation field).�As such it is a well placement strategy governed purely by reservoir drainage objectives rather than infrastructure conside

ular of this category of methods for optimal control problems has been the penalty-function method and its variants which are however extr

e propose a novel continuous approximation to the original discrete-parameter well placement problem such that gradients can be calculate

cal models. It uses the slopes of the cumulative net voidage curve and the measured change in pressure response to define reservoir specifi

compute pressure gradient by ignoring the wavy-liquid film on frictional pressure drop good agreement is achieved with field data and with th

he performance of a data weighted (DW-L2) to an equal weighted (EW-L2) objective function. The data weighted objective function tended t

de enhanced predictive capacity and are therefore more suitable for use with field optimization. In this work we apply a new parameterization


on of all parameters to generate a down hill search direction at each iteration. The theoretical basis for this probabilistic perturbation is that th

  we use an alterative direct approach for model calibration and uncertainty quantification. Specifically we describe a Statistical Moment Equ




ance which provides simplicity and speed of calculation. Once the CRM is calibrated with historical production/injection data we use an opti
 me taken for an injection signal to reach a producer. Injector-to-producer connectivity may be inferred directly during the course of error mini


 discussed in this paper enables accurate modeling and optimization of chemical flooding designs for realistic field-scale projects where a sal

 comparing results from problem No. 3 of the Fourth SPE Comparative Solution Projects� and a cyclic steam injection case with other com

 luid models currently used in reservoir simulation as well as models that will be developed in the future. With this general formulation approa




uch as P-wave and S-wave velocities and impedances are obtained from each 3D seismic survey. In some cases changes in seismic attribu




 t alternatives (gas lift sea floor boosting and electric submersible pumps) (2) identifying key artificial lift design parameters using Experimen


 during surface shut-in by computing the velocity profile at each timestep and its consequent impact on temperature and density profiles in th
 ted. Introduction Decline curve analysis has been in use for several years within the oil industry but limited to reserves estimation and future

 semi-automatic gridding technique is developed to create a high-quality unstructured grid that conforms to discrete fractures and wells while

 he upscaled two-phase flow functions for only a small fraction of the coarse blocks. For the majority of blocks these functions are estimated


ell stencils in two dimensions. The reduced stencils appear as a consequence of adapting the method to the closest neighboring cells. Here

water saturation) relationship from historical production data a simplified material balance algorithm and the Corey equation are solved simul

 providing for a more efficient simulation approach. In 2D displacement calculations with gravity included the CPU requirement of the SPU s
ng reservoir parameters from buildup and drawdown data and establishing the deliverability relation instills confidence in analysis. We also s

 the previous model for the Wara reservoir.� Thus this model is suitable for evaluating PMP infill drilling and pattern waterflood.� This p



ability streak or fracture). This paper also presents comparison of temperature profiles obtained with the analytical solution given in this pape

 the inputs to a trained neural network model of the oilfield and analyzing the outputs i.e. the production rates.� With our approach we

ce of reservoir performance profiles for each well was the in-house Eclipseâ„¢ reservoir simulation models. The production profiles for each

                         Introduction The push towards “digital oilfields has highlighted the need for efficient decision support systems
 ft Excel spreadsheet. 1.	


very. It is necessary to know how reliable are final gas and condensate recovery factors and gas condensate and water production profiles p
ow that the combination of certain rate schedules and the unsteady state nature of aquifers can cause a straight-line p/z plot in waterdrive ga

sed approach an example reservoir was investigated with multiple realizations all of which match the same production history. The results o



ensions namely a new “approximate feasible direction algorithm enabled the treatment of nonlinear path inequality constraints efficientl


rvoirs using this method. Then a geological description of the reservoir case study is provided and the procedure to build 3D reservoir mode



k using the iso-pressure curves obtained from local pressure solutions of a discrete fracture model over the block. The subregions thus acco


 . In a series of flow simulations involving both connected and disconnected fracture systems it is shown that the MSR method provides resu

ncreases. Cooling the formation is found to be helpful in lowering collapse pressure resulting in a more stable borehole. However it is also fo

 using an inverse solution method to formulate the training and testing data. Normalization of the data simplified the neural network improve

 l for future research. Our modified EKF is applied to real data from a section of an oil field. A validation strategy for the estimated IPR values

set and show that this method also gives a reasonable quantification of the uncertainty in performance predictions with an uncertainty range
dication of reservoir compartmentalization lateral or vertical.�Equally important we provide mathematical proof of why different wells in a



ses appropriate operating limits for completions with sand control.� Completion selection and design influence operating constraints.�

 eir end points – 3 forecasts. This method however does not test the possible interactions between uncertainties which would lead to multi

n is maintained at a critical value by controlling flow into the formation so as to operate with the desired mobility of heavy-oil.� Traditional P




c parameters are always consistent with the flow equations at the current step. However it also creates some inconsistency between the sta




we investigated the effect of nine different geologic factors on several different measures of the flow behavior. Our results show that as expe

models using the two major stratigraphic picks as for models constrained by 12 detailed stratigraphic picks.�Three dimensional streamlin


major sub-surface uncertainties explaining observed production performance and in prescribing additional development options for fifteen re

ssential for accurate solution of the saturation equations (i.e. transport). The primal basis functions which are associated with the primal coa
 ble of handling counter-current flow arising from gravity. The proposed family of schemes has four attractive properties: applicability within a

models. Steam-zone pressures and temperatures are similar to those typically observed in the field when the model is unconfined (i.e. the m

 locity field with high-order accuracy from the fluxes provided by MPFA discretization schemes. This reconstruction relies on a correspondenc

density term rigorously captures changes in fluid volumes with pressure and is easily traced along streamlines. A density-dependent source


nique. In this work we present a transformation of the field production data that makes it more amenable to GTTI. Further we generalize the



ach to history matching uncertainty assessment and probabilistic forecasting for mature assets through application of global optimization me

probabilistic static models for the field.� While these static models were being built a parallel numerical simulation study was conducted

 significantly relative to the full methodology while impacting the accuracy very little. The performance of the adaptive local-global upscaling

ables. The new upscaling algorithm is validated for two-phase incompressible flow in two dimensional porous media with heterogeneous per

 sensitive in revealing clues about subtle changes that may occur during formation fracturing or plugging. We observed that the derivative of

 sults show the homogeneous model compares quite favorably with mechanistic two-phase-flow models. However the main advantage of the


 lbore trajectory was studied to optimize ESP operating conditions. It was found that reducing sinusoidal amplitude by half and flattening the h

es the model versatile allowing step-by-step calculation of fluid temperature for the entire wellbore. We present simple thermodynamically so


 d. The main ingredient of this study entails the use of a small but reliable dataset wherein calibrated PVT properties minimizes uncertainty fr

a general maximum horizontal stress orientation of NESW. However there could be localized stress orientation variations depending on stru




armer aquifer below the producing zone (water coning). In contrast produced water can be cooler than produced oil because of differences in

onesia. Using the geomechanical model first a fault seal analysis was performed and indicated that all faults were sealed in sands under init

This is different from Monte Carlo (MC) -based geostatistical inversion techniques where conditioning on dynamic data is performed for one

ection. This observation proposes that local pressure drops created by vugs are more dominant in determining the wormhole flow path than t



y the dependence of trapped (residual) hydrocarbon saturation and waterflood relative permeability on several fluid/rock properties most not
n (Zuluaga and Monsalve 2003). These experiments were performed by injecting dry methane into core samples that contained immobile wa

Most of these wells lie on seismic-scale faults mapped in the reservoir. Some wells show fractured-reservoir production characteristics and r


 great economic impact. In information management and decision-making the mondegreen “data commute is the biggest problem area.

allenges were addressed and how the Company plans to address even more demanding challenges in the future.

 rofiles in addition to temperature and pressure conditions.� In particular a realistic water production profile during field life is needed to fr




able data.�The results highlight the crucial role played by the filter cake and present new data that would significantly change the commo


 dvances in openhole-drilling techniques that eliminate hole tortuosity gravel-pack fluids that can reduce rig time and enhance well productiv


IPR estimation has been emerging as an important issue in the petroleum industry.11 The correlations become more and more complicated



 the planning implementation of an early 4D program for the Enfield water-flood and history matching process. Pre-development feasibility w



a detailed uncertainty analysis with experimental design. Variables included in this analysis were perforation-to-gauge distance permeability

able PL tool selection poorly executed surveys inappropriate interpretation etc. With the existence of two or three phase flow in a well the


e model is then used to compute the flow profile based on measured DTS data across the producing intervals. The model rigorously account


 s inappropriate interpretation etc. In the presence of multiphase flow in a well interpretation of production logs becomes critical for achievi


ble PL tool selection poorly executed surveys inappropriate interpretation etc. With the existence of two or three phase flow in a well the in

approach called the Segmentation Method.� These four methods were developed for accurate and reliable identification of break points us



is uncertainty comprehensive wireline formation pressure programs have been run to assess hydrocarbon gradients but because sands are


pment needed to use C/O techniques especially the focused tool optimally in either monitor or producer wells in diatomite. Introduction The

ed primarily to effective waterflood management with a methodical approach employing an integrated multifunctional team. Although the su
 n) elimination of repetitive data gathering and reformatting tasks consistency and repeatability of evaluation and better knowledge manage

of the injected gas composition. As the concentration of CO2 in the injection gas increases the permeability of the coal decreases. Pure CO2

nate) wells. In these configurations the total length of horizontal wells and the spacing between laterals (SBL) have been studied. It was dete



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


 gn (ED) reduced the large number of simulation runs to a manageable few for probabilistic forecasting. Comparison of three options sugges

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

 bution and selective completion with blank pipes. Both oil well and gas wells are evaluated. For gas wells the standard pseudo-functions ar

g pressure Pfrict = friction pressure Phyd = hydrostatic pressure The equation shows that an increase in hydrostatic pressure results in a re



 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




e fracture. The new results presented here demonstrate successful strategies that mitigate the effects of excessive filter cake thickness. Exp

uth length and symmetry with respect to rock properties. Hydraulic fracture stimulations to date at SR have encompassed limited entry “



s can be impaired by the formation of a condensate bank once the bottomhole pressure drops below the dewpoint. This paper outlines the fiv

 he high-velocity coefficient in two-phase flow is investigated. Results show that when the liquid is strongly wetting the high-velocity coefficien


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


nd maximize financial returns. In this study a strategy was developed to maximize Agbami’s full-field rate capacity in three production p

performed. The analysis indicates that the well’s productivity had been substantially reduced. Before shut-in the surface pipeline system


 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.

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


aintaining stringent health safety and environmental standards was proposed. The propellant-assisted perforating method uses standard per



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
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

he near-wellbore zones of drilling damage mud-cake gravel packs and the sand screen. This investigation indicates that the non-Darcy eff




ompletion interval. In the event of proppant production to surface (mechanical failure) the surface samples would be analyzed to directly det

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


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




¿½F). Spectroscopic data show that the sandstone surface remains modified by the chemical even after flooding the core with large volume

s—with carbon dioxide advantages of enhanced cleanup and better hydrostatic pressure. This fluid was recently selected for the fracturing



cription. While we briefly discuss all relevant data the focus of this paper is primarily on integrating seismic amplitude response with pressur


erpretation highlights successful development of inflow and tubing performance relationships bubble-point pressure estimation as well as qu

the method with field data is also described. The new method could be applied wherever values of absolute permeability or fluids saturation
ement and recording systems throughout the entire production and process network. This pr

 up a new hydrodynamic slug.� This slug moves through the road


ively.�This advantage is even more pronounced in tight gas or

 ure depletion. Moreover the lower reservoir pressure increased the f
 ss is the formation of sodium hydroxide that reduces the interfacial
he ES-SAGD process are the solvent type concentration operating pressure and the
cesses to the carbonates poses a different challenge. In general therma
a common acid was not an option for this development because of the
 Adaptive Neuro Fuzzy Logic Inference System (ANFIS) that combines the
he stress perturbation associated with dynamic rupture propagation.
eling data used to characterize its azimuthal capabili
ray propagation resistivity density neutron porosity and LWD gamma ray
  stability hole washouts sanding while testing or lost seals. This pap

siderable heterogeneity in this “hard well data and that distri
 ility modeling procedure with application to the Surmont Lease in Nort

 coupling system for multiple-reservoir models. Uncertai


percent to 80% to 90% within the first 2 years of production. Typically sidetrac

he steam temperatures or pressures are known during the circulation peri
using Line Successive Over Relaxation (LSOR). The second stage preconditi
 tions. In this work we show that this physical information

 cs effects. These results indicate that the geomechanics-coupled compositional reservoi
e presented in this paper to demonstrate how implementing the optimizer’s recomm
ulting in fine-grid models consisting of 107 to 108 gridbloc
nthetic data generated by the forward model (i.e. the inversion model). It is conclu
 ubes were placed at different depths in the model to serve as gas inject
h may not have an influence on oil recovery as long as there is vertical commun
d the formation of stable wetting phase bridges. The combination of high sp
 ties but differ in several key areas including government policy. This paper examines
 However there are significant challenges and hurdles to overcome before that happens.
etic data generated by the forward model (i.e. the inversion model) in the previous

 of p/z material balance to calculate original-gas-in-place. �As with the Agar
 l model is expanded to incorporate multi-component adsorption models that are more
seudotime and pseudopressure definitions) to analyze producing wells completed in
 parameters that control reserves deliverability and value and; stage
  been adapted by incorporating some CBM reservoir properties.� For examp
ent reservoir units. In the high productivity Fairway well data monitored and gath
 a slight (but substantive) modification to material balance time and apply
 the case outlined above but with the individual units tending to be lent
 ross validation and with more than 100 new wells drilled during the last two
 lifting costs. Introduction Kuparuk Field (Fig.1) is the second largest oil field lo
uture improvement. Background Surmont an in-situ oil sands pro
   pre-drilled liners and openhole packers were selected instead of the conv
predictability. Future plans include continuing to stimulate candidate well
e performance of the wells in most assets dropped st
 bstitute to fracturing down casing and subsequent snubbing operations. Three t
cations. Focus areas in this evaluation include in-situ reservoi
 ring community has determined certain containment mecha
 depth of penetration of acid as a function of the acid v
ely. The 6-1/2 in. drift diameter allows using common size screen


st be meshed as shown in Fig.2 requiring 100-500 meshes aro
ompletion using conventional perforations or s
completions. Using appropriate variable transformations
fracture stimulations. Chemical and mechanica
provements in the gas relative permeability by a factor of about 2 were
ient analysis. The proposed cooling time and formation thermal diffusivit




udy indicate that for both water-wet and mixed-wet rocks T 2 (transverse relaxa

 to a reservoir model.� A reservoir model recently built using A


 ically depositional facies are simulated first using MPS then


 to the condensate relative permeability and this simplifies the measurements and model



nd newly acquired DFA log data matched for the first produc

 as observed from the low- to high-capillary-number flow regim

 eabilities following significant volumes of high temperature fluid inje

perhaps hydraulic action during forced imbibition form the channels. Silica diss



w uncertainties in volumetrics and capital and operating


used on dynamic uncertainties. The results of the workflow defined the P10 P50 a


 ing the confidence in the model selection. Finally the polynomial
 ntly. Two field examples are presented to demonstrate t

 iple surface/subsurface simulators. One real field case that requires advance/compl




ated in California’s San Joaquin Valley is presented in order to highl
n additional 20 000 bbl/day of water is expected from new projects and artifici


pay zone during completions were applied to maximize res

d in the El Trapial field in order to improve the unde




 erpretations to be examined. Based on the standard deviation or range of the

post-treatment cumulative oil production of the well one month after treat
 es rather than infrastructure considerations which may favor a mo

 its variants which are however extremely inefficient. All ot

 such that gradients can be calculated on the approximate problem and gradi

e response to define reservoir specific relationships between injection and pre

 is achieved with field data and with the predictions of a semimechanisti

 weighted objective function tended to reduce the highest errors first. Resu

 ork we apply a new parameterization referred to as a kernel


his probabilistic perturbation is that the expectation of the search dir

we describe a Statistical Moment Equations (SME) framework for both th




duction/injection data we use an optimization technique to maximize
rectly during the course of error minimization. Because


alistic field-scale projects where a salinity gradient exis

c steam injection case with other commercial simulators. We also demonstrate the p

 With this general formulation approach we can model most reservoir physics with a




me cases changes in seismic attributes over time can be detected and related to re




 design parameters using Experimental Design and (3) su


emperature and density profiles in the wellbore. Surrounding formation temp
ted to reserves estimation and future well/reservoir

s to discrete fractures and wells while incorporati

 locks these functions are estimated statistically on the basis


 the closest neighboring cells. Here we extend the ideas for discretizati

 the Corey equation are solved simultaneously.� A number of it

d the CPU requirement of the SPU scheme was found to be more than 50 times lar
lls confidence in analysis. We also show that the traditional l

ng and pattern waterflood.� This paper however focuses on PM



 analytical solution given in this paper and those

n rates.� With our approach we first

els. The production profiles for each well are represen

or efficient decision support systems that enable the in


nsate and water production profiles predicted by a material balance model. I
 straight-line p/z plot in waterdrive gas reservoirs. The authors

ame production history. The results of this study showed that subsequent we



r path inequality constraints efficiently and accurately unlike any exist


procedure to build 3D reservoir models that are only conditioned to



the block. The subregions thus account for the fracture distributi


n that the MSR method provides results of reasonable accuracy

stable borehole. However it is also found that a formation is more

mplified the neural network improved its effectiveness

strategy for the estimated IPR values is developed in terms of “pr

 predictions with an uncertainty range similar to the one obtained with RML. In
atical proof of why different wells in a multiwell res



 influence operating constraints.� Examples within the paper illustrate methods to determine a

certainties which would lead to multiple production forecasts

mobility of heavy-oil.� Traditional Proportional




some inconsistency between the static and dynamic parameters at the previous




avior. Our results show that as expected different geologic factors influence diff

icks.�Three dimensional streamline simulation was used to demonstra


al development options for fifteen reservoirs situated in four different

ch are associated with the primal coarse grid
ctive properties: applicability within a variety o

n the model is unconfined (i.e. the model area is greater th

onstruction relies on a correspondence between the MPFA fluxes an

mlines. A density-dependent source term in the saturation eq


 to GTTI. Further we generalize the approach to incorporate bottom-



 application of global optimization methods. This work involves appl

rical simulation study was conducted to determine the range of OGI

f the adaptive local-global upscaling technique is evaluated for

orous media with heterogeneous permeabilities. It is demonstrated that th

 . We observed that the derivative of modified-Hall integral obtained ana

 However the main advantage of the simplified model is that its recalibration with fiel


amplitude by half and flattening the heel-end entrance angle from 79 d

present simple thermodynamically sound approaches for estimating t


 T properties minimizes uncertainty from this important source. Statistical a

entation variations depending on structure complexity near a spe




produced oil because of differences in the thermal properties of these fluids.

aults were sealed in sands under initial stress and pore pre

n dynamic data is performed for one realization of the permeability

mining the wormhole flow path than the chemical reactions occurring at the pore level. Fol



everal fluid/rock properties most notably the wettability and the in
 samples that contained immobile water to represent water vaporiz

rvoir production characteristics and rate-transient analysis


ommute is the biggest problem area. The data commute absorbs over half the time



 profile during field life is needed to frame a workable hydrate management strategy.




 ould significantly change the common industry pra


  rig time and enhance well productivity and improvements in downhole tools tha


become more and more complicated and rigorous in order to accurately describe



 rocess. Pre-development feasibility work indicated that Enfield had rock



ation-to-gauge distance permeability geothermal gradient flow rate fluid viscosity t

wo or three phase flow in a well the interpretation of produ


ervals. The model rigorously accounts for various thermal prope


 tion logs becomes critical for achieving successful estimate


wo or three phase flow in a well the interpretation of produc

 liable identification of break points using both pressure and rate data. The new methods



bon gradients but because sands are thin and permeabilities are


 r wells in diatomite. Introduction The Belridge Diatomite in

multifunctional team. Although the suggested techniqu
ation and better knowledge management. Developed in San Jo

 ility of the coal decreases. Pure CO2 leads to the greatest permea

 SBL) have been studied. It was determined that in t



m the wells reviewed in this case. However the in


Comparison of three options suggested that all of them nearly produced

boundary measurements to place this first MRC w

lls the standard pseudo-functions are used. Detailed discussion

n hydrostatic pressure results in a reduction in surface pressure. Th



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




f excessive filter cake thickness. Experimental dat

have encompassed limited entry “waterfrac treatment techniques. The



 dewpoint. This paper outlines the five steps—appropriate l

ly wetting the high-velocity coefficient increases


-fluid flow along a wellbore. In particular the dependence


 ld rate capacity in three production phases; ramp-up pl

e shut-in the surface pipeline system induced unstable production


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

 al/reservoir simulator GMRS� which predicts cavity geome


 erforating method uses standard perforating components and procedures thus



g the hole to target depth (TD) a 6-in. h
of its greater well-intervention capability less-complex seawater-injection-system desi

nvolve sophisticated prediction techniques themselves. Continuous sand rate

ation indicates that the non-Darcy effect could significantly affect the product




les would be analyzed to directly determine which interval had fai

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

 frequency and type of workovers the amount and size of produc


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

 oelastic diverting acid system with a significant increase i




r flooding the core with large volumes of gas. A relative permeability model

s recently selected for the fracturing treatments on three wells. Initial prod



mic amplitude response with pressure transient


int pressure estimation as well as quantification o

olute permeability or fluids saturations are used in predicting we

								
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