Docstoc

Chevron - Reservoir Engineering Community

Document Sample
Chevron - Reservoir Engineering Community Powered By Docstoc
					  Nov-09
NOTES:

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

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



                      Total number of papers published post 2005 =             10,000

                                                                   35% of papers published categorised
                      Paper
Organisation   Source No.          Chapter


CHEVRON         SPE    98583          CO2




CHEVRON         SPE    116372         CO2

CHEVRON         IPTC   11391          CO2




CHEVRON         SPE    102968         CO2

CHEVRON         SPE    102968         CO2

CHEVRON         SPE    99548    Corporate Process


CHEVRON         SPE    112260   Corporate Process


CHEVRON         SPE    112267   Corporate Process



CHEVRON         SPE    112259   Corporate Process




CHEVRON         SPE    90213    Corporate Process



CHEVRON         SPE    110236   Corporate Process


CHEVRON         SPE    97228        EOR/IOR



CHEVRON         SPE    100089       EOR/IOR
CHEVRON   SPE    113965       EOR/IOR


CHEVRON   SPE    99656        EOR/IOR


CHEVRON   SPE    112375       EOR/IOR


CHEVRON   SPE    120205       EOR/IOR

CHEVRON   SPE    102219       EOR/IOR


CHEVRON   SPE    111512       EOR/IOR



CHEVRON   SPE    121761       EOR/IOR

CHEVRON   SPE    102352    Flow Assurance

CHEVRON   SPE    103137    Fluid description


CHEVRON   SPE    121414    Fluid Description



CHEVRON   SPE    106375    Fluid Description



CHEVRON   IPTC   12837     Fluid Description
CHEVRON    SPE   99386     Fluid Description

CHEVRON   SPE    125203    Fluid Description




CHEVRON   SPE    98743     Fluid Description

CHEVRON   SPE    114042   Formation Damage


CHEVRON   SPE    106480   Formation Damage

CHEVRON   SPE    106133   Formation Damage

CHEVRON   SPE    97990       Giant Field
CHEVRON   SPE    110099   Giant Field

CHEVRON   SPE    101307   Giant Field


CHEVRON   IPTC   11386    Giant Field

CHEVRON   SPE    102281   Giant Field

CHEVRON   SPE    102197   Giant Field

CHEVRON   SPE    102382   Giant Field


CHEVRON   SPE    99949    Giant Field


CHEVRON   SPE    102419   Giant Field


CHEVRON   SPE    120427   Giant Field

CHEVRON   SPE    114196   Heavy Oil

CHEVRON   SPE    97671    Heavy Oil

CHEVRON   SPE    122922   Heavy Oil




CHEVRON   SPE    120423   Heavy Oil

CHEVRON   SPE    93831    Heavy Oil

CHEVRON   SPE    103782   Heavy Oil



CHEVRON   SPE    84197    Heavy Oil

CHEVRON    SPE   87226    Heavy Oil
CHEVRON   IPTC   12426    Heavy Oil




CHEVRON   SPE    110492   Heavy Oil

CHEVRON   SPE    121521   Heavy Oil
CHEVRON   SPE    106908           Heavy Oil


CHEVRON   SPE    98318              HP/HT

CHEVRON   SPE    93805              HP/HT

CHEVRON   SPE    121695            HP/HT
CHEVRON   SPE    114705            HP/HT
CHEVRON   SPE    112793   Low Permeability Reservoirs



CHEVRON   SPE    101840   Low Permeability Reservoirs

CHEVRON   SPE    103865   Low Permeability Reservoirs

CHEVRON   SPE    109846   Low Permeability Reservoirs


CHEVRON   SPE    112268      Project Management

CHEVRON   SPE    107706      Project Management
CHEVRON   SPE    112921      Project Management

CHEVRON    SPE   109848      Reservoir Description
CHEVRON   IPTC    12877      Reservoir Description
CHEVRON    SPE   102435      Reservoir Description


CHEVRON   SPE    109972      Reservoir Description

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


        Capture/Storage




           Disposal                     Case Study

           Storage




       Workshop Paper                Capture/Storage

       Workshop Paper                Capture/Storage

       Chevron's i-Field                Case Study


       Chevron's i-Field              North America


Chevron's Knowledge Management



           PRODML                Production Data Standards




          SPE's RTO               Real Time Optimisation



          SPE's RTO               Real Time Optimisation


         By-passed Oil            Recovery Mechanisms



       Chemical Flooding                Surfactant
       Chemical Flooding               Surfactant selection


         Heterogeneity                Chemical Treatment


Modelling - Near Wellbore Effects      Gravity Segregation


         Steamflooding                     Wafra Field

        Well Intervention                Water Shut-off


        Well Intervention                Water Shut-off



        Well Intervention                Water Shut-off

    Modelling - Slug Tracking              Case Study

          Asphaltenes                      Screening


          Core Testing               Asphaltene Deposition



    Downhole Fluid Analysis               Asphaltenes



           Fluid Typing                NMR Interpretation
      Insitu PVT Variations             Gas Condensate

     Production Chemistry                 Asphaltenes




        Wellbore Fluids

         Scale Control                     Steamflood


       Scale Management                    Case Study

       Scale Management

           Heavy Oil                Development Optimisation
    Modelling - Fracture Characterisation          Carbonate Reservoir

      Modelling - Miscible Gas Injection           Carbonate Reservoir


     Modelling - Nat. Fractured Reservoir          Carbonate Reservoir

   Modelling - Parallel Reservoir Simulation       Greater Burgan Field

 Modelling - Probablistic Reservoir Simulation         Tengiz Field

         Primary Depletion Recovery                Carbonate Reservoir


                 Surveillence


          Waterflood Management                    Carbonate Reservoir


          Waterflood Management                  Greater Burgan Field Pilot

               Fluid Description                       Asphaltenes

Mechanism - High Mobility Ratio Waterflooding           Prediction

            Modelling - Streamline                 Technique Evaluation




            Reservoir Description                  Carbonate Reservoir

            Reservoir Description                      Mobility Data

                Sand Control



              Solution Gas Drive                    Composition Effect

              Solution Gas Drive
              State of the Nation                Carbonates - Middle East




          Waterflood Management                      Integrated Study

              Well Deliverability                  Chemical Treatment
         Well Intervention                  Water Shut off


            Stimulation                     Acid treatment

            Stimulation

      Water PH measurement             Laboratory Determination
        Well Performance                   Non-isothermal
            EOR/IOR                      Chemical Treatment



             Fracturing                    Multi-Fractures

          Horizontal Wells               Carbonate Reservoir

       Reservoir Description               Integrated Study


     Design Space Exploration                 Workflow

       Marginal Development
         Team Integration               Innovative Technology

Formation Evaluation - Heterogeneity
           Heterogeneity                       Analysis
           Heterogeneity                        NMR


        LWD Interpretation

     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


Carbon Dioxide Capture and Geological Storage: Contributing to Climate Change Solutions




Gorgon Project: Subsurface Evaluation of Carbon Dioxide Dsposal under Barrow Island

Mechanistic Studies of CO2 Sequestration




Critical Issues in CO2 Capture and Storage: Findings of the SPE Advanced Technology Workshop
(ATW) on Carbon Sequestration
Critical Issues in CO2 Capture and Storage: Findings of the SPE Advanced Technology Workshop
(ATW) on Carbon Sequestration

Implementing Chevron's i-field at the San Ardo, California, Asset


Implementation Results for Chevron's i-field in San Joaquin Valley, California


Semantic Web Technologies for Smart Oil Field Applications



Production Data Standards: The PRODML Business Case and Evolution




Real-Time Optimization: Classification and Assessment



Barriors to Implementation of Real-Time Operations Technology

Mitigating Oil Bypassed in Fractured Cores During CO2 Flooding Using WAG and Polymer Gel
Injections



Identification and Evaluation of High-Performance EOR Surfactants
Using Co-Solvents to Provide Gradients and Improve Oil Recovery During Chemical Flooding in a
Light Oil Reservoir


Transport of a pH-Sensitive Polymer in Porous Media for Novel Mobility-Control Applications


Well Stimulation and Gravity Segregation in Gas Improved Oil Recovery

Steamflood Piloting the Wafra Field Eocene Reservoir in the Partitioned Neutral Zone, Between
Saudi Arabia and Kuwait

Water Shutoff Treatments Using an Internally Catalyzed System in Boscan Field: Case Histories

Innovative Water-Shutoff Solution Enhances Oil Recovery From a West Venezuela Sandstone
Reservoir



Incremental Oil Success From Waterflood Sweep Improvement in Alaska

Pipelines Slugging and Mitigation: Case Study for Stability and Production Optimization

Screening for Potential Asphaltene Problems

Core Flood Investigation Into Asphaltene Deposition Tendencies in the Marrat Reservoir, South East
Kuwait


Asphaltene Gravitational Gradient in a Deepwater Reservoir as Determined by Downhole Fluid
Analysis



Accurate NMR Fluid Typing Using Functional T1/T2 Ratio and Fluid Component Decomposition
How Reliable Is Fluid Gradient in Gas/Condensate Reservoirs?

Verification of Asphaltene-Instability-Trend (ASIST) Predictions for Low-Molecular-Weight Alkanes



Modernization of the API Recommended Practice on Rheology and Hydraulics: Creating Easy
Access to Integrated Wellbore Fluids Engineering

Control of Silicate Scales in Steam Flood Operations

Assessment of Barite Scaling Potentials, Sulfate Removal Options, and Chemical Treating
Strategies for the Tombua-Landana Development
The Optimisation of a Scale Management and Monitoring Program for During the Production-
Decline Phase of the Life Cycle
New Method Combines Simulation and Novel Spreadsheet Tools To Enable Direct Optimization of
Expansion Decisions in a Giant Heavy-Oil Field
Fracture Characterization and Modeling Various Oil-Recovery Mechanisms for a Highly Fractured
Giant Light-Oil Carbonate Reservoir
A Multiscale Approach to Modeling Miscible Gas Injection Sweep Efficiency in a Giant Carbonate,
Light-Oil Reservoir


Realistic Modeling of Fracture Networks in a Giant Carbonate Reservoir
Full-Field Parallel Simulation Model: A Unique Tool for Reservoir Management of the Greater
Burgan Oil Field
Application of Integrated Reservoir Studies and Techniques To Estimate Oil Volumes and
Recovery—Tengiz Field, Republic of Kazakhstan

Predicting Primary Depletion Recovery of a Giant Light-Oil Carbonate Reservoir

Real-Time Field Surveillance and Well Services Management in a Large Mature Onshore Field:
Case Study

Innovative Enhancement of an Existing Peripheral Waterflood in a Large Carbonate Reservoir in the
Middle East

Lessons Learned From the First Water Flood Pilot Project in a Clastic Reservoir in the Greater
Burgan Field in Kuwait
Correlation of Cold Production Behavior with Acid/Base Number and Asphaltene Content of Heavy
Oil

High-Mobility-Ratio Waterflood Performance Prediction: Challenges and New Insights

Evaluation of Streamline Simulation Application to Heavy Oil Waterflood




Characterization of Complex Carbonate Heavy Oil Reservoir—A Case Study
Interrelationship of Temperature and Wettability on the Relative Permeability of Heavy Oil in
Diatomaceous Rocks (includes associated discussion and reply)

Design and Implementation of Retention/Filtration Media To Improve Heavy Oil Production



An Investigation of the Effect of Oil Composition on Heavy-Oil Solution Gas Drive

Heavy-Oil Solution Gas Drive in Consolidated and Unconsolidated Rock
An Overview of Heavy and Extra Heavy Oil Carbonate Reservoirs in the Middle East



Water-Injection Optimization for a Complex Fluvial Heavy-Oil Reservoir by Integrating Geological,
Seismic, and Production Data

Cost-Effective Production-Enhancement Solution for Heavy Oil
Applicability of Water Shutoff Treatment for Horizontal Wells in Heavy-Oil Reservoirs

Effective Stimulation of High-Temperature Sandstone Formations in East Venezuela With a New
Sandstone-Acidizing System
Stimulation of High-Temperature Sandstone Formations From West Africa With Chelating Agent-
Based Fluids

Laboratory Measurement of pH of Live Waters at High Temperatures and Pressures
Nonisothermal and Productivity Behavior of High Pressure Reservoirs
Developing a Chemical EOR Pilot Strategy for a Complex, Low Permeability Water Flood


Extreme Multistage Fracturing Improves Vertical Coverage and Well Performance in the Lost Hills
Field
Horizontal Drilling Application To Recover Incremental Oil in Low-Permeability Carbonate
Reservoirs, Partitioned Neutral Zone
An Integrated Study of Low Permeability Reservoir in the Bekasap Field, Central Sumatra Basin,
Indonesia


A Framework for Design Space Exploration in Oilfield Asset Development
The Frade Development Asset: How Robust Project Management Drove the Asset From
Economically Marginal to Chevron's Cornerstone Development Project in Brazil
The Role of Multi-Disciplinary Teams in Innovative Reservoir Management Projects

Formation Evaluation in Thin Sand/Shale Laminations
Static Connectivity and Heterogeneity (SCH) Analysis and Dynamic Uncertainty Estimation
NMR Petrophysics in Thin Sand/Shale Laminations

Improving LWD Image and Formation Evaluation by Utilizing Dynamically Corrected Drilling-Derived
LWD Depth and Continuous Inclination and Azimuth Measurements

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
H. Kheshgi, ExxonMobil; F. Cappelen, Statoil; A. Lee, Chevron; S.
Crookshank, API; A. Heilbrunn, CONCAWE; T. Mikus, Shell; W. Robson,
Nexen; B. Senior, BP; and T. Stileman and L. Warren, IPIECA                  Abstract Concern about global climate change an
Matthew Flett, SPE, Graeme Beacher, Jeroen Brantjes, SPE, Aaron Burt,
Chris Dauth, SPE, Fiona Koelmeyer, SPE, Robert Lawrence, Seb Leigh,
Jason McKenna, Chevron Australia Pty Ltd, Randal Gurton, William F.
Robinson IV, SPE, Chevron Energy Technology Company and Terrell
Tankersley, SPE, TengizChevroil                                              Abstract The Gorgon Project is a major LNG devel
J.M. Schembre-McCabe, SPE, and J. Kamath, SPE, Chevron Energy
Technology Company, and R. Gurton, Chevron�Australasia SBU                 Abstract Geologic sequestration of carbon dioxide

S. Imbus, Chevron Energy Technology Co.; F.M. Orr, Stanford U.; V.A.
Kuuskraa, Advanced Resources Intl. Inc.; H. Kheshgi, ExxonMobil
Research & Engineering Co.; K. Bennaceur, Schlumberger; N. Gupta,
Battelle Memorial Inst.; A. Rigg, CO2CRC; S. Hovorka, U. of Texas; and L.
Myer and S. Benson, Lawrence Berkeley Laboratory                          Abstract Carbon dioxide capture and storage (CC


J. Ouimette, SPE, Chevron Energy Technology Co., and K. Oran, Chevron
North America E&P                                                     Abstract This is a case study of an integrated “
Kenan Oran and James Brink, SPE, Chevron North America E&P
Company, and James Ouimette, SPE, Chevron Energy Technology
Company                                                               Abstract This paper summarizes results to date of
Ramakrishna Soma, Amol Bakshi, and Viktor Prasanna, University of
Southern California, and Will DaSie and Birlie Bourgeois, Chevron
Corporation                                                           Abstract In model based oil field operations engin

Dave Shipley, Chevron; Ben Weltevrede, Shell International E&P B.V.;
Alan Doniger, SPE, Energistics; Hans Eric Klumpen, SPE, Schlumberger;
and Laurence Ormerod, SPE, Weatherford International                         Abstract PRODMLâ„¢ is a set of production data s

S. Mochizuki, SPE, ExxonMobil; L.A. Saputelli, SPE, Halliburton; C.S.
Kabir, SPE, Chevron Corp.; R. Cramer, SPE, Shell; M.J. Lochmann, SPE,
Topsail Ventures; R.D. Reese, SPE, Case Services; L.K. Harms, SPE,
ConocoPhillips; C.D. Sisk, SPE, BP; J.R. Hite, SPE, Business
Fundamentals Group; and A. Escorcia, SPE, Halliburton                        Summary The Real-Time Optimization (RTO) Tec
J. Roger Hite, SPE, Business Fundamentals Group; Charles Crawley,
SPE, Chevron Energy Technology Company; David F. Deaton, SPE,
Halliburton Digital Consulting; Kemal Farid, SPE, Merrick Systems; and
Michael Sternevsky, SPE, Microsoft                                           Abstract The SPE Real Time Optimization Techni
D. Chakravarthy and V. Muralidaharan, Oxy U.S.A.; E. Putra, Kinder
Morgan CO2 Co. L.P.; D.T. Hidayati, Chevron; and D.S. Schechter, Texas
A&M U.                                                                       Abstract Fractured reservoirs have always been c
David B. Levitt, SPE, Adam C. Jackson , SPE, Christopher Heinson, SPE,
and Larry N. Britton, The University of Texas at Austin; Taimur Malik, and
Varadarajan Dwarakanath, SPE, Intera; and Gary A. Pope, SPE, The
University of Texas at Austin                                                Summary We report results for a number of prom
V. Dwarakanath, SPE, T. Chaturvedi, SPE, A.C. Jackson, SPE, Chevron;
T. Malik, SPE, A. Siregar, SPE, and P. Zhao, SPE, Chevron                    Abstract The effect of co-solvent on phase behavi
S.K. Choi, SPE, U. of Texas at Austin; Y.M. Ermel, SPE, Chevron Corp.;
and S.L. Bryant, SPE, C. Huh, SPE, and�M.M. Sharma, SPE, U. of
Texas at Austin                                                              Abstract Injection of a pH-sensitive polymer into a
M. Jamshidnezhad, Delft University of Technology; C. Chen, Chevron
Energy Technology Company; and P.�Kool and W.R. Rossen, Delft
University of Technology                                                     Abstract Models for gravity segregation in gas imp
David Barge, Falah Al-Yami, Don Uphold, Alireza Zahedi, and Art Deemer,
Saudi Arabian Chevron, Patricia E. Carreras, Chevron Energy Technology
Company                                                                      Abstract The concept of steamflooding the Wafra E
F. Mata, SPE, BJ Services de Venezuela CCPA, and S. Ali, SPE, and
Ernesto Cordova, Chevron Global Technology Services Co.                      Abstract This paper describes the results obtained
Goran Andersson, SPE, PetroBoscan; Gregg Molesworth, SPE, Chevron
Technology Company; and Belkis Gonz�lez, Salah Al-Harthy, and Eric
Lian, SPE, Schlumberger                                                      Abstract With the discovery of new fields becomin
Danielle Ohms, SPE, Jennifer McLeod, SPE, and Craig J. Graff, SPE, BP
Alaska; Harry Frampton, SPE, BP EPT; Jim C. Morgan, SPE, Jimtech;
Stephen Cheung, SPE, Chevron; and Katrina Yancey, SPE, and K.T.
Chang, SPE, Nalco                                                            Abstract Waterflood thief zones in communication
Y. Tang, SPE, Chevron Energy Technology Co., and T. Danielson, SPE,
ConocoPhillips Upstream Technology Co.                                       Abstract The ConocoPhillips Alpine facility on the
J.X. Wang, SPE, New Mexico Tech.; J.L. Creek, SPE, Chevron; and J.S.
Buckley, SPE, New Mexico Tech.                                               Abstract We present a rapid screening technique
N.H.G. Rahmani, SPE, J. Gao, SPE, and M.N. Ibrahim, SPE,
Schlumberger; S. Bou-Mikael, SPE, Chevron Corp.; and B.S. Al-Matar,
SPE, and F. Ruhaimani, SPE, Kuwait Oil Company                               Abstract Asphaltene precipitation can have profou
Oliver C. Mullins and Soraya S. Betancourt, Schlumberger-Doll Research;
Myrt E. Cribbs and Jefferson L. Creek,Chevron Energy Technology Corp.;
and Francois X. Dubost, A. Ballard Andrews, and Lalitha Venkataramanan,
Schlumberger-Doll Research                                                   Abstract The fluids in large reservoirs can be in eq
Boqin Sun1, Mark Skalinski2, Jeroen. Brantjes3, Chengbin Liu1, Gerald A.
LaTorraca4, Glenn Menard1, and Keh- Jim Dunn4 1Chevron Energy
Technology Company. 2Tengizchevroil, 3Chevron International Exploration
& Production Company, 4Chevron Consultant                                    Abstract Nuclear magnetic resonance (NMR) loggi
C.S. Kabir, SPE, Chevron ETC, and J.J. Pop, SPE, Schlumberger                Abstract Collection and analysis of gas/condensa
Jefferson L. Creek and Jianxin Wang, Chevron Energy Technology
Company, and Jill S. Buckley, New Mexico Tech                                                     when and where
                                                                             Summary Anticipating Weight Alkanes asphalten

P.A. Bern, BP Exploration; E.K. Morton, Chevron; M. Zamora, M-I Swaco;
R. May, Baker Hughes Inteq; D. Moran, Smith International; T. Hemphill,
Halliburton; L. Robinson, Consultant; I. Cooper, Schlumberger; S. Shah,
University of Oklahoma; D.V. Flores, ExxonMobil                              Summary Tailoring drilling-fluid hydraulics is one i
Darrell L. Gallup, SPE, and Charles J. Hinrichsen, SPE, Chevron Energy
Technology Company                                                           Abstract Water circulating during steam flooding to
Huey J. Chen, SPE, and Charlie J. Hinrichsen, SPE, Chevron ETC;
Christopher A. Burnside, SPE, Chevron CIEP; and Mark Widener, SPE,
Chevron ETC                                                                  Abstract This paper discusses the development o
Myles Jordan, Nalco; Ian Archibald, Chevron; Rod Farrell, Baker Petrolite;
Clare Johnston, Nalco; and Alistair Strachan, Baker Petrolite                Abstract This paper presents field results from sca
W. Terry Osterloh, SPE, Chevron Energy Technology Co., and Wendell P.
Menard, SPE, ConocoPhillips                                                  Summary Giant geologically complex heavy-oil fie
Padmakar Ayyalasomayajula, Mun-Hong Hui, Wayne Narr, Robert
Fitzmorris, and Jairam Kamath, Chevron                                       Abstract Proper fracture characterization and a go
Mun-Hong (Robin) Hui, Jairam Kamath, and Kaveh Dehghani, Chevron
Energy Technology Co., and Dennis Fischer, Chevron Intl. E&P                 Abstract Modeling sweep efficiency of miscible gas
Mun-Hong Hui, SPE, Jairam Kamath, SPE, Wayne Narr, SPE, and Bin
Gong, SPE,�Chevron Energy Technology Company, and Robert
Fitzmorris, Tengizchevroil                                                   Abstract Naturally fractured reservoirs (NFRs) acco
A.K. Ambastha, Chevron; D. Al-Matar and E. Ma, KOC; and B. Kasischke,
Chevron                                                                      Abstract The Greater Burgan field in Kuwait is the
K. Dehghani, SPE, S. Jenkins, D.J. Fischer, SPE, and M. Skalinski,
Tengizchevroil Kazakhstan                                                    Summary Recent technical studies and probabilis
P. Ayyalasomayajula, SPE, J. Kamath, SPE, K. Dehghani, SPE, and D.
Fischer, SPE, Chevron                                                        Abstract Predicting primary depletion recovery bel
L. Ormerod, SPE, Weatherford; H. Sardoff, SPE, J. Wilkinson, SPE, and B.
Erlendson, Chevron; and B. Cox, SPE, and G. Stephenson, SPE,
Weatherford                                                                  Abstract This paper describes the planning for im
A. Chawath�, SPE, J. Dolan, SPE, and R. Cullen, SPE, Chevron Intl.
E&P; J. Weston, Kuwait Santa Fe; and O. El Gendi and S. Razzak, Kuwait
Gulf Oil Co.                                                                 Abstract The Wafra Ratawi a Lower Cretaceous O
Meqdad Al-Naqi, Ibrahim Al-Kandari, Mishari Al-Qattan, and Badria A.
Rahman, Kuwait Oil Company; Sami Bou-Mikael, Chevron; and Naz H.
Gazi, Halliburton                                                            Abstract Greater Burgan in Kuwait is the second la
J. Peng, SPE, Stanford U; G-Q. Tang, Chevron; and A.R. Kovscek, SPE,
Stanford U.                                                                  Abstract So-called “foamy oil (heavy-oil solutio
Mridul Kumar, SPE, Viet Hoang, SPE, Cengiz Satik, SPE, Chevron Energy
Technology Co.; and Danny Rojas, SPE, Stanford University                    Summary This paper presents the results of a com

I. Osako, M. Kumar, V. Hoang, and G. Balasubramanian, Chevron ETC            Abstract Lack of analogs and the nature of high m
Afzal Iqbal, John Smith, Ali Reza Zahedi, Deemer Arthur, and Falah M. Al-
Yami, Saudi Arabian Chevron; W. Scott Meddaugh, SPE, Chevron Energy
Technology Company; Mansoor A. Rampurawala, SPE, Bingjian Li, and
Ihsan Gok, Schlumberger Oilfield Services; and Talal Al Enazi, Kuwait Gulf
Oil Company                                                                  Abstract The Paleocene/Eocene age 1st Eocene R
J.M. Schembre, SPE, G.-Q. Tang, SPE, and A.R. Kovscek, SPE, Stanford
U.                                                                           Summary The evaluation of thermal-recovery proc
David R. Underdown, Chevron Energy Technology Co., and Sam Hopkins,
Purolator Facet Inc.                                                         Abstract The factors that control the performance o

G.-Q. Tang,�SPE, T. Leung, SPE, and L.M. Castanier, SPE, Stanford
U.; A. Sahni, SPE, F. Gadelle,�SPE, and M. Kumar,�SPE, Chevron
Corp. E&P Technology Co.; and A.R. Kovscek, SPE, Stanford U.                 Summary This study probes experimentally the m
G.-Q. Tang, SPE, Stanford U.; A. Sahni, SPE, F. Gadelle, SPE, and M.
Kumar, SPE, Chevron Corp.; and A.R. Kovscek, SPE, Stanford U.                Summary Solution gas drive is effective to recove
John W. Buza, SPE, Chevron Corporation                                       Abstract Global heavy oil resources in carbonate
Xin Feng, China National Offshore Oil Company; Xian-Huan Wen, Chevron
International E&P Company; Bo Li and Ming Liu, China National Offshore
Oil Company; Dengen Zhou and Michael Q. Ye, Chevron International E&P
Company; and Dongmei Hou, Qinghong Yang, and Lichuan Lan, China
National Offshore Oil Company                                                Abstract BZ25-1s field in Bohai Bay China is char
Tim Gorham, SPE, Samuel E. Rodriguez, Chevron, John Wise, SPE,
Michael Ripley, SPE, and Richard J. Dyer, Enova                              ABSTRACT Heavy oil oil < 17o API accounts for
Francesco Verre and�Martin Blunt, Imperial College London, and Alan
Morrison and Tony McGarva, Chevron                                           Abstract The applicability of water shut-off treatme
S.A. Ali, SPE, and C.W. Pardo, SPE, Chevron Energy Technology Co., and
Z. Xiao, SPE, F. Tuedor, SPE, A. Boucher, SPE, S. Al Harthy, SPE, B.
Lecerf, SPE, and G. Salamat, SPE, Schlumberger                               Abstract The wells in an oil field in East Venezuel
S. Ali, SPE, E. Ermel, SPE, and J. Clarke, SPE, Chevron; M.J. Fuller, SPE,
Z. Xiao, SPE, and B. Malone, SPE, Schlumberger                               Summary Fluids based on chelating agents have
S.G. Mathews and B. Raghuraman, Schlumberger; D.W. Rosiere and W.
Wei, Chevron; and S. Colacelli and H.A. Rehman, Schlumberger                 Abstract This paper describes a new technique fo
J.F. App, Chevron Energy Technology Company                                  Abstract High pressure low permeability reservoirs
A.J.P. Fletcher and G.R. Morrison, Chevron Australia Pty. Ltd.               Abstract A screening study and subsequent chem
K.A. Hejl, SPE, A.M. Madding, SPE, and M.F. Morea, Chevron North
America E&P Co.; C.W. Glatz, SPE, and J. Luna, SPE, Halliburton; W.A.
Minner, SPE, T. Singh, SPE, and G.R. Stanley, SPE, Pinnacle
Technologies                                                                 Abstract In an attempt to improve production resp
Thanh Tran, CACT, China; David Barge, Saudi Arabian Texaco; and Stan
Ingham, Anadrill Schlumberger                                                Abstract The Ratawi Oolite carbonate reservoir in t
Yuni B. Pramudyo, Hendar S.M., Hasyim M. Nur, Mark R. Reinhold, and
Garry W. Jacobs, Chevron Pacific Indonesia                                   Abstract An integrated geological study has been

Cong Zhang, Amol Bakshi, and Viktor Prasanna, Unversity of Southern
California, and Will Da Sie and Birlie Bourgeois, Chevron Corporation        Abstract Design space exploration (DSE) is a com

J.M. Bergeron, SEG, and N. Parvez, Chevron                                   Abstract The Frade project is Chevron’s recen
Ganesh Thakur, SPE, Chevron Energy Technology Co.                            Abstract This paper documents the use of integrat
Chanh Cao Minh and Isabel Joao, Schlumberger, and Jean-Baptiste
Clavaud and Padmanabhan Sundararaman, Chevron                                Abstract Formation evaluation in thin sand-shale la
Hong Tang, SPE, Chevron and Ning Liu, SPE, Chevron                           Abstract Based on previous studies multiple SCH
C.C. Minh, Schlumberger, and P. Sundararaman, Chevron                        Abstract We use nuclear magnetic resonance (NM

G.A. Bordakov, A.V. Kostin, J. Rasmus, and D. Heliot, SPE, Schlumberger;
H. Laastad, SPE, Statoil; and E.J. Stockhausen, SPE, Chevron                 Abstract The paper illustrates the improvements in
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 a
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 inc
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
bout global climate change and the challenges and risks it poses will require sustained efforts to develop understanding and effective solut




 Project is a major LNG development to be based in Northwest Australia. Gas will be produced from several offshore gas fields located in the

questration of carbon dioxide in aquifers or in hydrocarbon reservoirs offer a promising alternative to reduce the amount of CO2 released to t




xide capture and storage (CCS) is emerging as a key technology for greenhouse gas (GHG) mitigation. The Society of Petroleum Engineers



ase study of an integrated “digital oilfield project.�The San Ardo California i-field Project is one of a number of current Chevron i-field


summarizes results to date of implementing i-field projects in selected assets in Chevron's San Joaquin Valley Business Unit (SJVBU) in Cal


 sed oil field operations engineers rely on simulations (and hence simulation models) to make important operational decisions on a daily bas



¢ is a set of production data standards initiated by 13 upstream oil and service companies with the industry standards body Energistics (then




Time Optimization (RTO) Technical Interest Group (TIG) has endeavored to clarify the value of real-time optimization projects. RTO projects



eal Time Optimization Technical Interest Group conducted a survey of its members earlier this year to learn more about the barriers to imple


eservoirs have always been considered as poor candidates for enhanced oil recovery. The fractures provide a pathway for injected fluids to



 results for a number of promising enhanced-oil-recovery (EOR) surfactants based upon a fast low-cost laboratory screening process that is
 f co-solvent on phase behavior was evaluated and an optimal surfactant/co-solvent formulation was selected based upon a combination of s


 a pH-sensitive polymer into a heterogeneous reservoir as a novel deep-penetrating mobility control method has been proposed earlier (Al-A


ravity segregation in gas improved oil recovery (IOR) indicate that the distance injected gas and water travel together before complete segre


 of steamflooding the Wafra Eocene dolomite reservoir originated in various studies conducted in the 1980’s. In 1999 a comprehensive

describes the results obtained using an Internally-Catalyzed System1 (ICS) to reduce water production in the Boscan oil field near Maracaib


covery of new fields becoming less common and the continued development of brownfields water control is becoming increasingly essentia



thief zones in communication with the rest of the reservoir are a severe and previously challenging problem. This paper gives an introduction

oPhillips Alpine facility on the Alaskan North Slope has experienced slugging problems severe enough to trip the high-high inlet separator le

 a rapid screening technique that uses a minimal amount of measured data.� Only in cases where asphaltene precipitation is predicted by


 precipitation can have profound effects on oil production during miscible flooding heavy oil recovery or even primary depletion. Even though



n large reservoirs can be in equilibrium - especially if conditions conducive to convective mixing prevail. A large vertical column of reservoir h



gnetic resonance (NMR) logging has been routinely used to measure mineralogy independent porosity irreducible water saturation and perm
and analysis of gas/condensate fluid samples present considerable challenges. That is because downhole sampling of a gas/condensate flu

  Weight Alkanes




 rilling-fluid hydraulics is one important key to the success of a drilling operation. Failure to do so can result in costly problems negatively im

ating during steam flooding to recover additional oil from reservoirs often becomes enriched in dissolved silica. As the silica concentration inc


discusses the development of a holistic water and scale management plan for a green-field development which faces a new order of scale m

presents field results from scale squeeze treatments carried out on platform and subsea horizontal wells from a oilfield in the UK sector of th

logically complex heavy-oil fields can take decades to develop so development decisions made early in the life of the field can have long-ran
 ure characterization and a good understanding of the fracture-matrix system are critical to properly predict oil recovery from naturally fracture

 eep efficiency of miscible gas injection into a giant carbonate light-oil reservoir presents technological challenges at many scales and requi


ctured reservoirs (NFRs) account for a significant fraction of the world’s petroleum reserves but pose significant challenges for reservoir

r Burgan field in Kuwait is the largest clastic oil reservoir in the world.� Reservoir simulation in this gigantic reservoir presents formidable c

chnical studies and probabilistic techniques have been integrated to build reservoir models for Tengiz field. Tengiz is one of the deepest supe

 rimary depletion recovery below the bubble point is a very difficult challenge especially for carbonate reservoirs. Accurate predictions require


 describes the planning for implementation of and results generated by a real-time field surveillance and well services management system


Ratawi a Lower Cretaceous Oolitic reservoir located in Kuwait has been on production since 1956. Production remained flat from about 40


gan in Kuwait is the second largest field and the largest clastic reservoir in the world. Discovered in 1938 the production initially came from W

 œfoamy oil (heavy-oil solution gas drive) is influenced by a number of factors including chemical and compositional characteristics of the cru

r presents the results of a comprehensive study to improve our understanding of high-mobility-ratio waterflood (HMRWF) and to improve per

logs and the nature of high mobility ratio waterflood conditions pose many difficulties for reliable performance forecasts for heavy oil waterflo




ene/Eocene age 1st Eocene Reservoir is the shallowest producing interval of Wafra Field in the Partitioned Neutral Zone (PNZ) Saudi Arabia

ation of thermal-recovery processes requires relative permeability functions as well as information about the effects of temperature on these

 hat control the performance of sand control screens that use woven metal mesh as the filter media; i.e commonly called “premium scre



 probes experimentally the mechanisms of heavy-oil solution gas drive through a series of depletion experiments employing two heavy crude

as drive is effective to recover heavy oil from some reservoirs. Characterization of the relevant recovery mechanisms however remains an o
avy oil resources in carbonate rocks have been estimated to be on the order of 1.6 trillion barrels1 of which about one-third may occur in the




ld in Bohai Bay China is characterized as a complex fluvial channelized reservoir where small meandering channels (100-300m wide and 50

 l oil < 17o API accounts for a growing percentage of the production and reserve portfolios of North American Oil Producing Companies. A k
bility of water shut-off treatment for horizontal wells in heavy oil reservoirs is analyzed in this study considering two different treatments: inorg


 n an oil field in East Venezuela have a bottomhole static temperature of approximately 230�F and varied mineralogical composition from

 ed on chelating agents have been developed for matrix stimulation of high-temperature sandstone formations. These fluids dissolve sizeable

 describes a new technique for measuring pH on live formation water samples in the laboratory at high temperature and pressure. The techni
 re low permeability reservoirs have been encountered in various parts of the world within the past few years. Commercial development of th
  study and subsequent chemical EOR application pilot strategy for a complex low-permeability waterflood is presented. Our focus has been



 pt to improve production response fracturing designs in the Lost Hills field went from a standard 3 to 6 stage design to an extreme 15 to 18 s

 Oolite carbonate reservoir in the Partitioned Neutral Zone (PNZ) is located between Kuwait and Saudi Arabia and has been a prolific oil prod

ed geological study has been performed for a large mature field at the Bekasap and Menggala formation. The primary goal of the study was


 ce exploration (DSE) is a common yet complex workflow in oilfield asset development. The “design of an oilfield refers to a set of decisio

 roject is Chevron’s recently announced (June 2006) deepwater heavy-oil sanctioned development project requiring a capital investment
 ocuments the use of integrated reservoir management concepts during the application of innovative technology to improve oil production/rec

valuation in thin sand-shale lamination seeks first to determine sand resistivity volume fraction and porosity. Afterwards saturation and volu
 evious studies multiple SCH parameters are used to quantify reservoir performance. �Static connectivity is quantified by fraction of conne
clear magnetic resonance (NMR) logging to help with the petrophysical evaluation of thin sand-shale laminations. NMR helps to 1) detect thin


 lustrates the improvements in logging while drilling (LWD) images and subsequent formation evaluation by utilizing a new methodology for d

 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

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

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
op understanding and effective solutions while at the same time meeting the growing needs of society for energy. The development and util




eral offshore gas fields located in the Greater Gorgon Area with processing facilities to be located on Barrow Island. The reservoir fluids of s

uce the amount of CO2 released to the atmosphere. Most prior work has focused on CO2 containment. However target reservoirs can have




                                                                           OnePetro
The Society of Petroleum Engineers (SPE) Applied Technology Workshop (ATW) on CO2 Sequestration (Galveston Island Texas Nov. 15-

                                                                                       OnePetro

f a number of current Chevron i-field implementation projects.�It seeks to transform how the San Ardo steamflood is operated focusing


Valley Business Unit (SJVBU) in California.� The i-field projects include collaborative environments to transform operational processes at


 operational decisions on a daily basis. Three problems that are commonly encountered in such operations are: on-demand access to inform



stry standards body Energistics (then POSC) in 2005. In November 2006 PRODML Version 1.0 was released. The focus was on production




e optimization projects. RTO projects involve three critical components: People Process and Technology.�� Understanding these com



arn more about the barriers to implementation of this technology.� Understanding the barriers better will allow us to focus on the more im


ovide a pathway for injected fluids to channel through directly from injection to production wells. The interaction between these fractures and



 laboratory screening process that is highly effective in selecting the best surfactants to use with different crude oils. Initial selection of surfac
ected based upon a combination of simulations and laboratory experiments.� The co-solvent altered phase behavior thereby necessitatin


thod has been proposed earlier (Al-Anazi and Sharma 2002b).�A polyelectrolyte that forms molecular-network microgels in solution is in


 avel together before complete segregation scales with the injection rate Q. Therefore in cases where injection pressure is limiting reducing


980’s. In 1999 a comprehensive EOR study and Eocene huff-n-puff pilot suggested that steamflooding could be a viable recovery proces

n the Boscan oil field near Maracaibo West Venezuela. This field is divided in two blocks: north and south. In the south block wells can eve


 ol is becoming increasingly essential to enhancing oil recovery. Water control operations are especially challenging in under-pressured rese



 em. This paper gives an introduction to the nature of a novel heat-activated polymer particulate. Details of a trial of this in–depth diversion

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

                                                                                     evidence
phaltene precipitation is predicted by the screening test would further experimentalOnePetro such as the measurement of onset pressure b


                                              OnePetro
 even primary depletion. Even though asphaltene precipitation and eventual deposition have been known to have strong effects on permeabi



A large vertical column of reservoir hydrocarbons offers a unique laboratory to investigate potential gravitational grading. Asphaltenes are kno



rreducible water saturation and permeability of earth formation. The T2 distribution derived from NMR logging data is often composed of sev
ole sampling of a gas/condensate fluid unlike its oil counterpart does not guarantee retrieval of single-phase fluid. The same is true for sur

                                                  OnePetro




sult in costly problems negatively impact equipment longevity and performance as well as ultimately jeopardize overall well objectives. In re

d silica. As the silica concentration increases in the water silicate minerals become supersaturated. At supersaturation conditions amorphou


 t which faces a new order of scale management challenges. Specifically this paper documents a scale risk assessment and the developme

 from a oilfield in the UK sector of the North Sea.� Downhole scale control and the resulting squeeze treatments to production wells were

 the life of the field can have long-range implications. Decision and risk analysis (D&RA) is often needed to make decisions that will maximiz
                                                                                       OnePetro OnePetro
 ict oil recovery from naturally fractured reservoirs. In this work we use an integrated analysis of image logs production logs and production

 hallenges at many scales and requires an integrated study at the core fine earth-model and coarse flow-model scales. We first perform ph


 e significant challenges for reservoir characterization and simulation. In this work we develop a novel workflow for the geologically realistic m
                                                                                      OnePetro

 antic reservoir presents formidable challenges in any modeling effort.� Its sheer size complex geology intricate surface facility network 2

 ld. Tengiz is one of the deepest supergiant oil fields in the world and is on the shore of the Caspian Sea within the Republic of Kazakhstan. K

 servoirs. Accurate predictions require sufficient laboratory data to cover the variability in response from the different rock types and laborator


 d well services management system as it was deployed in an onshore mature field in California USA.�The motivation behind the deploy


oduction remained flat from about 40 producers until 1990. The field was shut-in in 1990 during the Gulf War. An aggressive drilling program


 8 the production initially came from Wara sandstone and soon followed by other underlying Burgan clastic reservoirs. Burgan reservoir main

 mpositional characteristics of the crude oil. Measurements of the concentration of organic acid and base groups as well as asphaltene conte

 rflood (HMRWF) and to improve performance prediction. Published data on heavy-oil water-injection field projects are limited. Several succe

                                                 OnePetro
mance forecasts for heavy oil waterflood.� In many cases although numerical simulation is the method of choice for forecasting it also fac




 ed Neutral Zone (PNZ) Saudi Arabia and Kuwait. Characterization of this heavy oil reservoir is challenging due to observed variations in oil v

 t the effects of temperature on these functions. There are significant challenges encountered when estimating relative permeability from labo

 commonly called “premium screens are not generally well understood by the end user. The end user is provided a premium screen with



 eriments employing two heavy crude oils and two viscous mineral oils. Mineral oils were chosen with viscosity similar to crude oil at reservoir

 mechanisms however remains an open question. In this work we present an experimental study of the solution gas drive behavior of a 9ï¿
 ich about one-third may occur in the Middle East.� Published resources for specific fields and proprietary databases however suggest a




 ng channels (100-300m wide and 500 - >1000m long) were deposited at different geological times cross-cutting each other. There are many

 erican Oil Producing Companies. A key challenge in the production of heavy oil is that its properties provide a greater likelihood of common d
dering two different treatments: inorganic gel and relative permeability modifier (RPM). In the first part of this paper a general description of


                                                                                  OnePetro
ried mineralogical composition from interval to interval. Near-wellbore fines damage and carbonate scale damage have been reported in th

ations. These fluids dissolve sizeable amounts of calcite and clays and maintain high levels of dissolved metal in solution over time with mini

                                              OnePetro
mperature and pressure. The technique involves adding pH sensitive dyes to pressurized single phase water samples collected using a form
ears. Commercial development of these reservoirs may require high drawdowns possibly in excess of 6 000 psi. The impacts of drawdown i
od is presented. Our focus has been on developing appropriate field application options allowing flexibility of operation against a background



 tage design to an extreme 15 to 18 stage design to stimulate approximately 1000’ of net pay. The previous standard designs were beco
                                                                                 OnePetro OnePetro

rabia and has been a prolific oil producer in the area. Several billion barrels of oil from this reservoir has been produced within the PNZ. As th

n. The primary goal of the study was to developed an integrated reservoir description for targeted infill drilling and improve recovery in a low-p


of an oilfield refers to a set of decisions about aspects ranging from well locations and number to facility sizing for optimum production. Evalu

project requiring a capital investment of approximately $2.5B. The development project is located in the northern Campos Basin juxtaposed t
hnology to improve oil production/recovery in both new and mature fields. It provides a number of examples of multi-disciplinary project team

osity. Afterwards saturation and volume are simple Archie applications. Resistivity anisotropy techniques can provide estimates of sand resis
ivity is quantified by fraction of connected pore volume between wells. Static heterogeneity is defined by Dykstra-Parson Coefficient Lorenz
 inations. NMR helps to 1) detect thin beds 2) determine fluid type and if hydrocarbon is present 3) establish the hydrocarbon type and volu


 by utilizing a new methodology for depth and survey measurements correction. LWD depth measurements are often considered inaccurate

                                                  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
 gions 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

 agement (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
or energy. The development and utilization of technologies to capture and then store CO2 in underground formations offer significant poten




arrow Island. The reservoir fluids of several of the fields contain carbon dioxide (CO2) which will be extracted from the produced gases prior t

 However target reservoirs can have low permeability and are often finite and the ability to properly model the injection stage is of significan




do steamflood is operated focusing on better decision making for the asset and streamlined work processes for heat wells and water man


o transform operational processes at a basin-wide or asset level remote collaboration and visualization has been implemented to help execu


ons are: on-demand access to information integrated view of information and knowledge management. The first two problems of on-demand



 eased. The focus was on production optimization processes which could produce results implementable within a day. The domain was from




gy.�� Understanding these components will help establish a framework for determining the value of RTO projects.� In this paper the



will allow us to focus on the more important issues. The survey was in two parts.� The first asked about the overall process of getting from


eraction between these fractures and the reservoir rock matrix often determines the degree of bypassing during injection of CO2. The use o



nt crude oils. Initial selection of surfactants is based upon desirable surfactant structure. Phase-behavior screening helps to quickly identify fa
phase behavior thereby necessitating a different approach for inducing effective salinity gradients.� We present an approach where the h


ar-network microgels in solution is injected into high-permeability zones under acidic conditions.�Upon contact with reservoir rock the inje


 jection pressure is limiting reducing skin resulting from damage at the wellbore face directly increases volumetric sweep of gas in IOR. Even


ing could be a viable recovery process for the reservoir. As a result of these studies a staged development approach was incorporated to te

 uth. In the south block wells can eventually produce oil with 90% water cut due to the influence of an aquifer. The accumulated production


challenging in under-pressured reservoirs with openhole completions such as in the Boscan field in West Venezuela. Gravel-packed slotted



s of a trial of this in–depth diversion system resulting in commercially significant incremental oil from a BP Alaskan field are presented. The

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




tational grading. Asphaltenes are known to exist in crude oils as a colloidal suspension but which had not been well characterized in the labo



ogging data is often composed of several fluid components. For example T2 of clay bound water is in general less than 10ms while T2 of mo
phase fluid. The same is true for surface sampling because of incomplete surface and/or downhole separation. Given this reality the PVT a




opardize overall well objectives. In recent years the industry methods have deviated from American Petroleum Institute (API) RP13D standar

upersaturation conditions amorphous silica and metal silicates may deposit in heat exchangers. Scale deposits not only reduce heat exchan


 risk assessment and the development of a scale management plan during the front-end engineering design of the Tombua–Landana dev

 treatments to production wells were highlighted as one of the most expensive items in the production chemical budget and impacted topside

d to make decisions that will maximize the risk-adjusted economic benefit. Unfortunately in large fields D&RA can be very challenging becau
 w-model scales. We first perform phase-behavior studies and core-flood experiments to understand miscibility and sweep efficiency at the c




gy intricate surface facility network 2 200 completions and 58-years of production history with significant uncertainty represented a daunting

 within the Republic of Kazakhstan. Knowledge of the uncertainties inherent in oil recovery is a key to proper reservoir management of this im

 he different rock types and laboratory procedures and proper upscaling of laboratory data to simulation grid scales. Many recent studies hav


¿½The motivation behind the deployment of this system was simultaneously to improve efficiency and reduce operating costs in this large fi


War. An aggressive drilling program was initiated after 1992 when the field was brought back on-line followed by a 26-injector peripheral wa


 tic reservoirs. Burgan reservoir mainly consists of three reservoir units namely Wara Third and Fourth sand. The Wara Water Flood Pilot P

e groups as well as asphaltene content of crude oil are combined with data from laboratory-scale heavy-oil solution gas drive. We find that si

ld projects are limited. Several successful HMRWF projects have been reported and they show significant oil recovery at high watercut. How




 ng due to observed variations in oil viscosity heterogeneity related to complex mineralogy a possible dual porosity system and the presenc

mating relative permeability from laboratory data such as the accuracy of measurements and generalized assumptions in the interpretation t

er is provided a premium screen with a woven metal mesh with some weave type and told the sand control screen is better than the other pr



 cosity similar to crude oil at reservoir temperature. A specially designed aluminum coreholder allows visualization of gas phase evolution dur

e solution gas drive behavior of a 9�API crude oil with an initial solution gas/oil ratio (GOR) of 105 scf/STB and live-oil viscosity of 258 cp a
 tary databases however suggest a more modest STOOIP resource base of approximately 120 BBO.� Owing to its vast light oil reserves




s-cutting each other. There are many isolated small reservoir systems following channel distributions. Early production showed steep pressu

vide a greater likelihood of common damage mechanisms and result in a drop in production rates. Historically operators of heavy oil reservo
 f this paper a general description of heavy oil reservoirs behavior is given investigating the suitability of the treatment for this type of reservo




  metal in solution over time with minimal precipitation. A series of field samples from high-temperature (149�C) sandstone reservoirs in a


6 000 psi. The impacts of drawdown in this range are: 1) increases in near wellbore temperatures due to Joule-Thomson expansion of the res
 ty of operation against a background of reservoir complexity and uncertainty. Australia’s Barrow Island Windalia reservoir the nation’




 been produced within the PNZ. As the fields mature the easy produced oil in the high permeability intervals is diminished by increasing wate

 illing and improve recovery in a low-permeability reservoir. Integration of geological and petrophysical studies and reservoir performance ana


 sizing for optimum production. Evaluation of alternate designs – based extensively on reservoir simulations – corresponds to the evaluat

 northern Campos Basin juxtaposed to Petrobras’s Albacore Leste and Roncador developments. First oil for Frade is scheduled for Q1 2
 ples of multi-disciplinary project teams working together in a motivated environment to optimize the asset value. These examples demonstra

 s can provide estimates of sand resistivity and volume fraction but good results depend on the choice of the anisotropic shale point. The sam
  Dykstra-Parson Coefficient Lorenz Coefficient weighted by cell volume. �Two-phase streamline simulation is used to exam the dynamic
 ablish the hydrocarbon type and volume and finally 4) determine the permeability of the sands (as opposed to that of the sand-shale system


 ents are often considered inaccurate and therefore not as reliable for well-to-well correlations correlations to offset data acquired with wirelin




 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-based

deling 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

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

-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
und formations offer significant potential for reducing CO2 emissions. This paper is based on the outcomes of an IPIECA workshop to adva




 cted from the produced gases prior to liquefaction into LNG. The Gorgon Joint Venture participants have proposed to geologically dispose o

del the injection stage is of significant economic concern. We conducted thorough mechanistic studies of the injection stage using a detailed




esses for heat wells and water management.�The San Ardo i-field project is nearing the end of the planning and front-end engineering p


has been implemented to help execute reservoir management and major capital project targets reliably and efficiently in the field.� Succes


 The first two problems of on-demand access and information integration arise because a large number of and different kinds of simulation m



e within a day. The domain was from perforations through to start of processing on the surface.� The objective was to enable plug and pla




 RTO projects.� In this paper the Technology component is closely examined and categorized. Levels within each Technology category



out the overall process of getting from data to decisions and action.� The second focused on the usage of technical and business tools. T


ng during injection of CO2. The use of CO2 as a displacing agent through these reservoirs aggravates the problems of low sweep efficiency



 screening helps to quickly identify favorable surfactant formulations. Salinity scans are conducted to observe equilibration times microemuls
We present an approach where the hydrophilic nature of the co-solvent is used to maintain effective salinity gradients to optimize surfactant b


on contact with reservoir rock the injected fluid experiences an increase in pH due to geochemical reactions between the injected fluid and


volumetric sweep of gas in IOR. Even in the absence of damage at the wellbore face most of the injection pressure is dissipated near the we


 ent approach was incorporated to test the viability of pattern steamflooding the Eocene reservoir.� The objective was to assess key techn

quifer. The accumulated production per well can be as high as 6 (six) million barrels and typical rates range from 600 to 2 400 BFPD (barrel


 st Venezuela. Gravel-packed slotted liners and standalone premium screens are common completion methods in this field. Dual injection c



 BP Alaskan field are presented. The system of one injector and two producers was selected because of a high water oil ratio and low recov

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




ot been well characterized in the laboratory until recently. In this paper we review a gravitational gradient of asphaltenes in a reservoir and a



neral less than 10ms while T2 of movable water is above 33 ms in sandstone formation. Each fluid component can be represented by a uniq
paration. Given this reality the PVT analysis of any fluid sample with an equation-of-state (EOS) model demands that the results are verifie




 oleum Institute (API) RP13D standard practice (2003 2006). This departure has been driven primarily by the increasingly onerous demands

deposits not only reduce heat exchange efficiency due to fouling but they may plug tubes resulting in tube failure. Control of these deposits in


esign of the Tombua–Landana development in West Africa.� The complexity of scale management is compounded by the presence of m

hemical budget and impacted topside separation during treatment back production.� The development of optimized scale squeeze treatme

D&RA can be very challenging because of the large number of variables and the endless number of development and expansion scenarios t
 scibility and sweep efficiency at the core scale. We conduct detailed reservoir-condition experiments on several core samples that are carefu




nt uncertainty represented a daunting task in history-match and prediction. The quest began in 2002 with the creation of a 65-million cells’

oper reservoir management of this important oil field. Probabilistic techniques gave insights into the importance and ranking of key reservoir

 grid scales. Many recent studies have shown that laboratory- derived gas oilgas-oil relative permeability curves often depend on whether the


 educe operating costs in this large field with over 1 000 wells. The paper will describe how the business processes and supporting workflow


llowed by a 26-injector peripheral waterflood in July 1998. Production peaked in 2Q 2002. After approximately two years production dropped


sand. The Wara Water Flood Pilot Project is the first clastic waterflood pilot in Kuwait. Reservoir pressure in Wara has been falling below th

 oil solution gas drive. We find that significant asphaltene content as well as substantial acid and base numbers are indicators of whether oil i

ant oil recovery at high watercut. However the range of reported recovery is large—waterflood recoveries of approximately 1 or 2% to 20%




ual porosity system and the presence of fractures at varying scales. This case study of the 1st Eocene reservoir characterization in the stea

ed assumptions in the interpretation techniques. A novel method is used here to estimate relative permeability and capillary pressure from in-

 trol screen is better than the other premium sand control screens on the market. The end user is told that the premium sand control screen



 ualization of gas phase evolution during depletion using X-ray computed tomography (CT). In addition a visualization cell was installed at the

 STB and live-oil viscosity of 258 cp at 178�F.�Constant rate depletions are conducted in a composite core (consolidated) and a sandpa
 ½ Owing to its vast light oil reserves documentation in the public domain on Middle Eastern heavy oil accumulations is not complete but eno




arly production showed steep pressure and production decline. Quick implementation of water injection is needed to arrest the fast productio

orically operators of heavy oil reservoirs have used several options to address the common damage mechanisms of asphaltene paraffin and
 the treatment for this type of reservoir. The analysis is then applied to a real case the Captain field. Captain is a heavy oil largely homogene




149�C) sandstone reservoirs in a West African formation bear carbonate concentrations ranging from 2% to 37% (w/w). The effects of ma


 Joule-Thomson expansion of the reservoir fluids and 2) significant reductions in oil viscosity. The effects of large drawdown are evaluated w
and Windalia reservoir the nation’s largest onshore waterflood was developed in the late 1960’s. Cumulative oil production to date i




vals is diminished by increasing water cut. Considerable by-passed oil remains in the tighter and lower quality intervals. These oil reserves c

udies and reservoir performance analysis provided a rapid and effective method for developing a comprehensive reservoir description. A 3D


ations – corresponds to the evaluation of alternate development scenarios in face of uncertainty about subsurface structure and properties.

 st oil for Frade is scheduled for Q1 2009. Frade being a deep water heavy oil development project has historically been both technically an
et value. These examples demonstrate the innovative use of existing technologies to increase asset productivity: 3D/4D seismic geostatistics

f the anisotropic shale point. The same shale point should be used in the determination of sand porosity. Difficulties will arise when anisotrop
ulation is used to exam the dynamic performances and validate the SCH analysis. The impact of static modeling parameters on flow respon
sed to that of the sand-shale system). Formation evaluation in thin sand-shale laminations starts with their detection. NMR vertical resolution


ns to offset data acquired with wireline measurements and formation layer thickness determinations. The reasons for these inaccuracies gen




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) until

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 ful

 ic 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

 elop 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 evalu

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
mes of an IPIECA workshop to advance understanding of the role of CO2 capture and geologic storage and strategies to improve its perfor




e proposed to geologically dispose of the produced reservoir CO2 from the gas processed at the Barrow Island LNG plant. The CO2 injectio

of the injection stage using a detailed compositional simulator. Issues that were probed included effects of mobile and immobile oil saturation




planning and front-end engineering phases with project execution starting in 2006.�The project team created preferred alternatives for t


and efficiently in the field.� Successful asset prototypes are standardized and replicated across the business unit. The results to date demo


 of and different kinds of simulation models each modeling a different facet of the oil-field are used. An engineer is generally an expert in on



 objective was to enable plug and play integration of current upstream applications while supporting a variety of optimization processes. In 2




els within each Technology category are illustrated by use of spider diagrams which help decision makers understand the current status of o



ge of technical and business tools. This paper summarizes the results of the survey.� We found that each step in the process has consid


he problems of low sweep efficiency due to its high mobility. The microscopic displacement efficiency of CO2 is very high but the overall di



serve equilibration times microemulsion viscosity oil and water-solubilization ratios and interfacial tension (IFT). Cosurfactants and cosolve
nity gradients to optimize surfactant behavior but more importantly mitigate viscous microemulsions and reduce surfactant retention.� By u


tions between the injected fluid and carbonate and other mineral components in the rock.�The pH increase swells the polymer which dra


on pressure is dissipated near the well but most of the segregation occurs much further from the well. Therefore if injection pressure is limit


he objective was to assess key technical challenges associated with steamflooding an anhydrite and gypsum rich carbonate reservoir. Additio

ange from 600 to 2 400 BFPD (barrels of fluid per day). In order to mitigate the high water cut and water production the operator implemente


methods in this field. Dual injection combined with permanent water shutoff (WSO) gels or relative permeability modifiers to control water pro



 f a high water oil ratio and low recovery factor which was recognized as an indicator of the presence of an injection water thief zone and con

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




nt of asphaltenes in a reservoir and a simple theory is shown to apply. The corresponding downhole and laboratory analyses are consistent; a



 ponent can be represented by a unique T2 peak in a T2 distribution. The shape of the T2 peak can be predetermined by either a Gaussian o
 demands that the results are verified with independent measurements. Our analyses of many samples show that a good correspondence




 y the increasingly onerous demands of critical wells coupled with readily accessible computer power. In 2003 a task group was formed to m

 e failure. Control of these deposits in boilers and co-generation equipment is necessary to reduce down-time for mechanical cleanout. In the


 is compounded by the presence of multiple reservoirs with very different scaling potentials and by the plans for produced water reinjection.ï¿

nt of optimized scale squeeze treatments and monitoring policy has been critical to reducing the operating cost and deferred oil production of

 elopment and expansion scenarios to analyze. The time needed to complete a D&RA can become prohibitive when full-field reservoir simula
 several core samples that are carefully selected to represent the important rock types of the reservoir. A fine-scale geological model of the




h the creation of a 65-million cells’ geostatistical earth model.� The full-field simulation model of 1.6-million cells consists of six major

portance and ranking of key reservoir uncertainties. This ranking is used to reduce reservoir uncertainties and to guide reservoir managemen

y curves often depend on whether the tests were conducted using depletion drive or steady state methods. Though it may seem preferable to


s processes and supporting workflows were defined.�This is an essential step before any technology can be deployed.�The challenge


mately two years production dropped in 4Q 2003 with declines approaching 25% AED. The Ratawi Asset Management Team (AMT) investig


ure in Wara has been falling below the bubble-point in many parts of the reservoir. This would ultimately result in free gas evolving from the o

umbers are indicators of whether oil is foamy. The acid number is the amount of potassium hydroxide in mg needed to neutralize the acid gro

es of approximately 1 or 2% to 20% of original oil in place (OOIP) have been reported for similar reservoirs. Higher viscosities result in lower




reservoir characterization in the steam flood pilot area will improve our understanding of the range and distribution of formation properties wh

ability and capillary pressure from in-situ aqueous-phase saturation profiles obtained from X-ray computerized tomography (CT) scanning du

at the premium sand control screen uses such material as Dutch Dutch Twill or a Reverse Dutch Twill woven metal mesh and some cases



a visualization cell was installed at the outlet of the sandpack to monitor the flowing-gas-bubble behavior vs. pressure. Bubble behavior obser

site core (consolidated) and a sandpack (unconsolidated). The sandpack does not employ a confining pressure whereas the consolidated co
ccumulations is not complete but enough information is available to assemble a reasonable picture of the geological setting reservoir and oi




s needed to arrest the fast production decline and to stabilize reservoir pressure. While designing the water injection plan we faced a numb

chanisms of asphaltene paraffin and inorganic scale depositions as well as wettability changes in order to increase the production of their e
ptain is a heavy oil largely homogeneous reservoir exploited with horizontal wells. Due to the presence of many production wells with high wa




m 2% to 37% (w/w). The effects of matrix treatment using a chelating agent-based system on these field samples were studied using corefloo


 ts of large drawdown are evaluated with a transient single-phase thermal simulator in which the oil viscosity is modeled as both temperature
 s. Cumulative oil production to date is approximately 288 MMSTBO. Planning a chemical EOR scheme needs to address the following reser




quality intervals. These oil reserves cannot be produced efficiently and economically by vertical wells through primary or secondary methods.

 ehensive reservoir description. A 3D geocelluar model of reservoir architecture and properties distribution was made and used as a guide to


 subsurface structure and properties. The outputs of DSE influence many decisions in the development phase of an oilfield as well as operat

s historically been both technically and economically challenged. The inherent subsurface and surface complexities alone might have shelved
ductivity: 3D/4D seismic geostatistics characterization/simulation horizontal drilling technology and improved oil recovery (IOR)/enhanced o

 . Difficulties will arise when anisotropy is not caused by sand-shale laminations when no sand-shale point exists or when the nearby thick s
modeling parameters on flow responses is studied. Geological factors include net-to-gross (NTG) interbed connectivity intrabed heterogene
heir detection. NMR vertical resolution is mainly controlled by the antenna aperture that is in the case of a high-resolution antenna 6 in. or 1


 e reasons for these inaccuracies generally originate from the traditional practice that LWD depth is purposely made equal to the driller’s




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
ribed 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 links

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


 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
 and strategies to improve its performance and prospects. It considers CO2 capture and geological storage as a potential option for reducin




w Island LNG plant. The CO2 injection project was extensively documented and subjected to public comment as part of the Gorgon Project E

of mobile and immobile oil saturations damage due to geochemical reactions stimulation and presence of neighboring injectors. Total mob




m created preferred alternatives for transforming 21 work processes.�Decision support software would be integrated with improved instru


 siness unit. The results to date demonstrate business value and take-up of the technology and processes by oilfield operations.� Introduc


 engineer is generally an expert in one aspect of oil-field modeling and trained to use a few tools; therefore accessing information captured



 riety of optimization processes. In 2007 the PRODML community now expanded to 23 companies worked on extensions addressing produ




 rs understand the current status of operations and the future RTO status. The perception of uncertain value has been one of the critical issu



 each step in the process has considerable major and minor barriers to overcome.� The most difficult steps were in the areas of business


f CO2 is very high but the overall displacement efficiency is often hindered by its high mobility that is largely the results of viscosity and den



ion (IFT). Cosurfactants and cosolvents are included to minimize gels liquid crystals and macroemulsions and to promote rapid equilibration
 reduce surfactant retention.� By using a combination of laboratory experiments and simulations to match co-solvent behavior in UTCHEM


 crease swells the polymer which drastically increases the apparent viscosity of the polymer “solution significantly lowering the mobility


 herefore if injection pressure is limited increasing mobility near the injection well has a large impact on Q with a direct benefit in delaying g


psum rich carbonate reservoir. Additional challenges were the lack of fresh water available for steam generation high concentrations of hydro

  production the operator implemented in 1998 a water shut-off (WSO) program. In 2003 the ICS was introduced as part of this program. Th


meability modifiers to control water production in these completions has traditionally produced inconsistent results. This method can fail to cha



 an injection water thief zone and confirmed by study of a previous injection survey. The area around the wells is bounded by faults so the sy

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




 laboratory analyses are consistent; asphaltenes exist in these crude oils in nanoaggregates. The corresponding asphaltene gradients provid



 redetermined by either a Gaussian or B-Spline function. Recently we have developed a “Fluid Component Decomposition (FCD) method
es show that a good correspondence exists between the PVT-derived gradient and that obtained from wellbore-flow modeling of production-




 n 2003 a task group was formed to modernize the existing API recommended practice (RP) bulletin on rheology and hydraulics. It comprised

 -time for mechanical cleanout. In the present study at a steam flooded field steam boiler and co-generation tube deposits consisted of opal


 ans for produced water reinjection.� The objective of the study was to define a complete scale management plan which incorporates flex

 g cost and deferred oil production of this asset as the produced water cut rose.� Scale squeeze treatments have been optimised over the

 ibitive when full-field reservoir simulation is the main tool for forecasting primary production and well count with one simulation taking many
A fine-scale geological model of the reservoir with about 2000 layers is then built. Factors that could impact sweep at the fine scale such as




1.6-million cells consists of six major oil reservoirs (Wara Mauddud 3SU 3SM 3SL and 4S) with 145 faults.� These faults are major con

s and to guide reservoir management activities. A structured Monte Carlo Technique has been used to construct several thousand static mo

ds. Though it may seem preferable to use laboratory data from depletion drive derived laboratory dataexperiments for modeling solution gas


y can be deployed.�The challenges of data management included not only the automatic handling of very large quantities of real-time da


et Management Team (AMT) investigated the causes of the decline and observed the following: Reservoir pressure decline near the cresta


result in free gas evolving from the oil and significant loss in reserve recovery. This pilot was designed with the objective to obtaininformation

 mg needed to neutralize the acid groups in 1 g of crude oil whereas the base number is the amount of potassium hydroxide in mg that is re

oirs. Higher viscosities result in lower recovery. Mechanistic studies using fine-scale simulations show that the viscosity (or mobility) ratio prim




istribution of formation properties which is critical for management of the current pilot project. This study presents several aspects of an inte

erized tomography (CT) scanning during high-temperature imbibition experiments. Relative permeability and capillary pressure functions are

woven metal mesh and some cases the manufacturer will promote the benefit of multiple layers of woven metal mesh filter media in the san



 vs. pressure. Bubble behavior observed at the outlet corroborates CT measurements of in-situ gas saturation vs. pressure. Both depletion r

ressure whereas the consolidated core does. The evolution of in-situ gas saturation vs. pressure is monitored in the sandpack using X-ray c
 e geological setting reservoir and oil quality issues and the status of cold and EOR production in the region.� Productive heavy oil carbon




ater injection plan we faced a number of challenges such as high mobility ratio (oil viscosity of ~200 cp) strong heterogeneity poor reservo

r to increase the production of their existing wells. However these options are generally limited to costly and resource consuming methods su
of many production wells with high water cut it has been considered a candidate for a water shut-off pilot project. Six different scenarios in a




 samples were studied using coreflood and slurry reactor experiments. Linear coreflood test data show dramatic increases in the formation p


osity is modeled as both temperature and pressure dependent and Joule-Thomson expansion of the reservoir fluids is considered. Results in
 needs to address the following reservoir and production characteristics: Highly heterogeneous very fine grained bioturbated argillaceous s




ough primary or secondary methods. Without different techniques of drilling and completion most of the oil in the low permeability intervals w

on was made and used as a guide to further development. This model delineates distinct trends of estuarine sand ridge and margin facies


phase of an oilfield as well as operational decisions in a producing asset. In this work we design and implement a generic framework to sup

omplexities alone might have shelved the development of this asset - particularly in the early evaluation period. Moreover the fiscal and polit
proved oil recovery (IOR)/enhanced oil recovery (EOR) techniques — dumpflooding peripheral/pattern floods water/gas injection CO2/mis

 int exists or when the nearby thick sand-shale is not representative of the sand-shale in the laminations. In producing fields that have underg
bed connectivity intrabed heterogeneity and reservoir log cutoff. Intrabed heterogeneity is usually misrepresented due to maximum entropy a
  a high-resolution antenna 6 in. or 15 cm. Within that distance NMR tools will cumulatively measure all layers of shales and all layers of san


osely made equal to the driller’s depth which is a static pipe length measurement made by tape at surface. There is almost always a di




 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

 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. Due

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. Sever

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
orage as a potential option for reducing future emissions of Greenhouse Gases (GHGs) from the extraction of resources the production and




 ment as part of the Gorgon Project Environmental Impact Assessment Process. Following this process the WA Environmental Protection Au

e of neighboring injectors. Total mobility plots signal effects of relative permeability curves on injectivity trends during the injection phase and




uld be integrated with improved instrumentation workflow automation and data architecture to enable more reliable and efficient field operat


es by oilfield operations.� Introduction The major producing assets of Chevron’s SJVBU are shown in red in Figure 1.� SJVBU pro


ore accessing information captured in models that do not lie in an engineer’s area of expertise is not easy. Moreover since these mode



rked on extensions addressing production reporting the use of a common “flow network model and into “smart wells. This paper a




alue has been one of the critical issues in adopting RTO systems in our industry. Therefore case histories are reviewed to demonstrate the i



 steps were in the areas of business analysis recommendations / decisions and taking action.� These are areas where management can


argely the results of viscosity and density contrasts between the CO2 phase and the reservoir oil and brine phases. In this study we perform



ons and to promote rapid equilibration to low-viscosity microemulsions. Branched alcohol propoxy sulfates (APS) internal olefin sulfonates a
atch co-solvent behavior in UTCHEM Using an understanding into co-solvent partitioning was developed such that the optimal conditions of


on significantly lowering the mobility of water in the high-permeability zone.�For the controlled application of this novel process the mech


 Q with a direct benefit in delaying gravity segregation. There is also a relatively small increase in gravity segregation in the near-well region


neration high concentrations of hydrogen sulfide gas and higher reservoir pressures compared to most active steamfloods. ��The stag

ntroduced as part of this program. The ICS is solids-free and internally activated. It is used for permanent zone plugging and lost circulation


nt results. This method can fail to change the well production profile and possibly damage oil-producing layers. This paper will discuss the de



 wells is bounded by faults so the system can be considered to be isolated from surrounding wells and operations. The position of the therm

to combination of its low flow rate overly-sized pipeline ID and unfavorable pipeline profile.� Flow pattern transition exists at the low spots




ponding asphaltene gradients provide a stringent and new method to test reservoir connectivity (as opposed to compartmentalization) which



ponent Decomposition (FCD) method that uses a set of predetermined T2 peaks as base function to perform T2 inversion with CPMG echo t
 ellbore-flow modeling of production-test data. Older generation formation testers those prior to 1990 although yielding comparable results




rheology and hydraulics. It comprised a cross-functional team of operators suppliers and academics that set an aggressive target to moder

ation tube deposits consisted of opal-A pectolite aegerine clinamphibole serpentine-like minerals iron oxide corrosion products and apatit


gement plan which incorporates flexibility for future unknowns and minimizes the total cost of scale management without over-capitalization

tments have been optimised over the years with the aid of detailed reservoir simulation indicating water rates along the production wells bein

unt with one simulation taking many hours or days to complete. This paper describes two new methods developed to overcome these challe
pact sweep at the fine scale such as the Todd-Longstaff mixing parameter and vertical-to-horizontal permeability ratio are investigated. A fl




aults.� These faults are major conduits allowing fluid migration between reservoirs.� This paper describes the history-matching process

construct several thousand static models of Tengiz field. Construction of Monte-Carlo models is fast and allows the impact of key uncertainti

periments for modeling solution gas drive recovery these tests are complex and there is concern using data from tests conducted at pressu


 very large quantities of real-time data but also the management of inventory and the integration of field-level data with corporate-level dat


voir pressure decline near the crestal and the southern regions of the field Voidage Replacement Ratio (VRR) < 1.0 Water breakthrough es


with the objective to obtaininformation in the areas of: Long-Term Injectivity Reservoir Connectivity Water Breakthrough Time and Direction

 potassium hydroxide in mg that is required to neutralize the titrant used in an acid titration of 1g of crude oil. The partitioning of acid and bas

hat the viscosity (or mobility) ratio primarily controls oil recovery response and that the recovery is lower at higher viscosity ratios. Further vis




 y presents several aspects of an integrated approach to characterize the 1st Eocene reservoir. The approach includes the quantification and

 and capillary pressure functions are interpreted simultaneously including possible nonequilibrium effects. Results obtained show a systema

en metal mesh filter media in the sand control screen to control the sand. All this information is interesting but the end user really does not un



uration vs. pressure. Both depletion rate and oil composition affect the size of mobile bubbles. At a high depletion rate (0.035 PV/hr) a foam-

nitored in the sandpack using X-ray computed tomography. The two different porous media allow us to develop a mechanistic perspective wh
gion.� Productive heavy oil carbonate fields can be grouped into two categories: 1) low matrix permeability fracture dependent and 2) mat




 ) strong heterogeneity poor reservoir connectivity complex channel geometry and irregular well patterns. A workflow integrating geologica

and resource consuming methods such as cyclic steam injection and workover rig based liner or perforation washes. A cost effective alterna
t project. Six different scenarios in a simulation study were considered with the reservoir properties of Captain in order to test the effectivene




dramatic increases in the formation permeability after treatment with the chelating agent-based fluid. The improvement in permeability is asc


ervoir fluids is considered. Results indicate near wellbore temperature increases of 4 to 24 �F for drawdowns between 2 000 to 10 000 ps
e grained bioturbated argillaceous sandstone high in glauconite; High porosity (0.28) but low permeability (5 mD with 20 mD+ streaks); Pr




oil in the low permeability intervals will be left unrecovered. A combination of horizontal drilling with geosteering tools and technology for pre

arine sand ridge and margin facies throughout the field that reflect paleogeography.� Additionally reservoir properties and saturations we


plement a generic framework to support DSE workflows in oilfield asset development. Our framework provides tools and services to allow ra

period. Moreover the fiscal and political landscape in Brazil has proven to be less than predictable further providing additional obstacles to p
floods water/gas injection CO2/miscible gas and steamflooding. Adopting an integrated team approach is important because of the advan

. In producing fields that have undergone several waterfloods water resistivity is often unknown in the swept thick sands and might not be re
presented due to maximum entropy assumption stationary assumption of geostatistics and upscaling. The intrabed heterogeneity is modele
layers of shales and all layers of sands regardless of their individual thicknesses. Because NMR relaxation time in shales is much faster than


surface. There is almost always a difference between the actual measured depth (MD) of the LWD sensor downhole and this static pipe me




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 a

ecast. 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 g

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
 tion of resources the production and use of fuels and the generation of electricity. In doing so it examines: roles CO2 capture and geologic




 the WA Environmental Protection Authority found that the environmental risks associated with the CO2 injection project were acceptable and

trends during the injection phase and help identify injectivity-damaging curves. Finally most studies on CO2 injection for disposal purposes




more reliable and efficient field operation and execution of reservoir management targets.�The project is integrated in two ways.�First


own in red in Figure 1.� SJVBU production in 2007 averaged over 220 000 barrels per day from approximately 15 000 producing wells.�


ot easy. Moreover since these models are created by different processes and people the same information is represented differently across



  into “smart wells. This paper authored by experienced members of the PRODML community explains the evolution from a concept to




 es are reviewed to demonstrate the impact of RTO projects. To assist RTO project promotion further we list lessons learned suggest a jus



 e are areas where management can have the greatest impact through improved work processes governance and procedures.� The resu


 ne phases. In this study we performed CO2 injection experiments with different injection rates and utilized X-ray CT to determine the satur



es (APS) internal olefin sulfonates and branched alpha olefin sulfonates (AOS) have been identified as good EOR surfactants using this scr
d such that the optimal conditions of ultra-low interfacial tensions are maintained for a longer duration during chemical flooding.� We dem


ation of this novel process the mechanisms for each of its three sub-processes need to be understood: (1) dependence of polymer viscosit


y segregation in the near-well region. An analytical model for gravity segregation in homogeneous reservoirs can be extended to a case whe


 active steamfloods. ��The staged approach called for a single pattern steamflood test followed by a larger multi-pattern pilot. As a resu

nt zone plugging and lost circulation control delivered into the matrix of the targeted zone. Laboratory evaluations were conducted to determ


 ayers. This paper will discuss the development implementation and results of an innovative solution for water shutoff that was engineered



operations. The position of the thermal front in the reservoir tracer transit times injection rates and inter-well separations indicated that the s

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




osed to compartmentalization) which is key to the efficient economic development for many deepwater projects. � Introduction In the pa



form T2 inversion with CPMG echo trains. The FCD method significantly reduces the computation time for NMR data inversion especially fo
although yielding comparable results had larger error bars owing to system limitations in repeatability of both pressure and depth measurem




at set an aggressive target to modernize the existing standard within 2 years. The focus was to develop simple yet accurate methods that c

 oxide corrosion products and apatite. Iron in the silicate minerals appears to derive from transporting incompletely oxygen scavenged circu


nagement without over-capitalization. The Tombua-Landana field will produce from multiple reservoirs that incorporate several distinct forma

rates along the production wells being input into scale squeeze design software.� The requirement to extend treatment life while minimisin

 developed to overcome these challenges for a specific depletion-drive heavy-oil reservoir: a method for optimally populating a model with hu
meability ratio are investigated. A flow-based nonuniform approach is used to coarsen the fine-grid models by a factor of thirty. The upscal




 scribes the history-matching process used in detail along with the value that has been added through prediction cases run with this model to

d allows the impact of key uncertainties to be explored. Static reservoir uncertainties investigated include wireline log calibration structural el

data from tests conducted at pressure depletion rates much higher than that in the field. More significantly such tests are expensive and it is


 d-level data with corporate-level data.�Historical data had to be brought into and made compatible with the new system.�The techno


 (VRR) < 1.0 Water breakthrough especially in the first ring of wells inside the peripheral injection loop Poor conformance due to high perme


ater Breakthrough Time and Direction Water-Cut Development Productivity Operational Experience The Wara pilot pattern is of inverted s

e oil. The partitioning of acid and base groups between the asphaltene fraction and deasphalted oil is also studied. Organic acid and base gro

 at higher viscosity ratios. Further viscous fingers dominate high-viscosity-ratio floods and mobile water can significantly reduce recovery. F




roach includes the quantification and distribution of the evaporite minerals and porosity analysis of a possible dual porosity system and eva

ts. Results obtained show a systematic shift toward increased water-wettability with increasing temperature for diatomite reservoir core. The

g but the end user really does not understand the significance of the information. This paper presents the results of a study to evaluate the



depletion rate (0.035 PV/hr) a foam-like flow of relatively small pore-sized bubbles dominates the gas and oil production of both crude oils. C

 evelop a mechanistic perspective whereby the effects of depletion rate and overburden pressure on heavy-oil solution gas drive are investiga
ability fracture dependent and 2) matrix permeability dependent production. Fracture enhanced low matrix permeability production is domina




ns. A workflow integrating geological well log seismic and dynamic production data was developed to optimize water injection plan for this f

 tion washes. A cost effective alternative production enhancement process to these types of well interventions has been implemented in the
aptain in order to test the effectiveness of the treatment on production wells. These are typical producer/injector configurations found in a he




e improvement in permeability is ascribed to the removal of carbonate minerals and soluble clays without secondary metal precipitation. Slu


wdowns between 2 000 to 10 000 psia due to Joule-Thomson expansion of the reservoir oil and connate water. Furthermore if oil viscosity is
ility (5 mD with 20 mD+ streaks); Production and injection necessarily stimulated by induced fractures Highly saline and hard brine; Large




 steering tools and technology for precise lateral placement in the low permeability reservoirs in addition to a low fluid loss drilling fluid system

 servoir properties and saturations were geostatistically populated within the model.� Horizontal wells were chosen as the preferred altern


rovides tools and services to allow rapid specification and evaluation of multiple design candidates using multiple realizations. The framewor

er providing additional obstacles to project success. After merging with Texaco in 2001 Chevron realized that a different approach would be
ch is important because of the advanced level of expertise required in making large-scale primary secondary and tertiary projects successfu

wept thick sands and might not be representative of the water in the unswept thin sands. As discussed previously NMR offers useful insight
he intrabed heterogeneity is modeled by Vdp based permeability multiplier. The flow responses of these modeling factors are examined by a
on time in shales is much faster than in the productive sands thin sand-shale laminations appear on NMR logs with the characteristic bimod


sor downhole and this static pipe measurement because downhole the drillpipe is subject to an environment that is not representative of the




 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
 ies (e.g. permeability field which may be nonuniform) and time-varying properties (e.g. pressure and saturation field).�As such it is a wel

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 fo

                                                                                                                                 Introduction
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

 or 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

 or 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
nes: roles CO2 capture and geologic storage may play over the next century extending from the current assessment of this technology fami




 injection project were acceptable and recommended that CO2 injection must proceed as an integral component of the Gorgon Project. The

CO2 injection for disposal purposes assume that the reservoir has an infinite capacity for CO2 storage condition that is unlikely to be met by




 t is integrated in two ways.�First integration occurs across the asset management value chain from reservoir through production optimiz


 ximately 15 000 producing wells.� Approximately 83% of the production was heavy 10% light and 7% gas.� The heavy oil is generally


tion is represented differently across models. A unified view of the models and their simulations is desirable for decision making and thus th



 ains the evolution from a concept to “do something about production data into a well-defined series of interoperable services with a defin




we list lessons learned suggest a justification process and present a simple example of an economic-evaluation process. Introduction Indu



 nance and procedures.� The results also show there is considerable need for improved commercial technical and business analysis tools


 ized X-ray CT to determine the saturation distribution along the core and measure oil bypassed during CO2 process in fractured cores. We



 good EOR surfactants using this screening process. These surfactants are available at a low cost and are compatible with both polymers an
uring chemical flooding.� We demonstrated that by adding the appropriate co-solvent and the correct amount of electrolyte in the chase so


 : (1) dependence of polymer viscosity on ionic (pH) conditions in the reservoir; (2) geochemical characterization of pH change in the rock; a


voirs can be extended to a case where permeability is stimulated within a cylindrical region inside a larger cylindrical reservoir. The effect of t


 a larger multi-pattern pilot. As a result of this strategy a single pattern steamflood test was implemented in 2006. The design and initial per

valuations were conducted to determine effects on the hard setting of ICS resulting from the contact between ICS and other fluids deployed


or water shutoff that was engineered for the complex completion methods mentioned. The solution involves three key stages; the temporary i



-well separations indicated that the slowest reacting of the three commercial grades available was most appropriate for the trial. The treatme

stem once gas blows out and system pressure drops the pipeline inlet gas increases velocity and picks up a new hydrodynamic slug.� Th




projects. � Introduction In the past a presumption of fluid homogeneity in the reservoir prevailed. In part this assumption was made bec



for NMR data inversion especially for multi-dimensional data sets from oil well measurements without sacrificing the smoothness and accur
f both pressure and depth measurements.� We developed a yield-temperature correlation to fill in the information void for reservoirs tha




 simple yet accurate methods that could be implemented readily with basic spread-sheeting skills. This paper describes improvements mad

ncompletely oxygen scavenged circulating water to the boilers and co-generation unit in carbon steel pipe. Increasing the concentration of ox


hat incorporate several distinct formation waters with barium content as high as 800 mg/l and will require seawater injection for reservoir pre

 extend treatment life while minimising the deferred oil was one of the critical factors in selecting improved scale inhibitor chemistry.� The

 optimally populating a model with hundreds of horizontal wells and a method to optimize expansion decisions quickly and directly. The utilit
odels by a factor of thirty. The upscaled absolute permeabilities (k*) are computed for the coarse models. We then generate upscaled relative




 ediction cases run with this model to date. A tiered history-matching approach was used based on field gathering center (GC) GC-sand an

e wireline log calibration structural elevation geostatistical parameters (such as variogram length) water saturation and location of the boun

tly such tests are expensive and it is not practical to conduct many depletion tests. We used mercury injection porosity permeability CT sc


with the new system.�The technologies required for this project included the software systems themselves but also the integration of the


Poor conformance due to high permeability streaks resulting in water breakthrough in wells inside the first ring of producers The Ratawi AM


 he Wara pilot pattern is of inverted seven spot with one injector six producers and one water source and was designed to inject 5 000 to 10

o studied. Organic acid and base groups are clearly present in the asphaltene fraction. We investigate the lifetime of single foam films of cru

r can significantly reduce recovery. Field-scale simulation results indicate that heterogeneity plays a more important role for a HMRWF than c




ssible dual porosity system and evaluation of permeability using a new porosity partitioning technique. Data used in this study includes conv

ure for diatomite reservoir core. The measured changes in relative permeability are linked to the effect of temperature on the adhesion of oil-

he results of a study to evaluate the effect of different woven metal mesh weaves on the performance; i.e. dirt holding capacity and plugging



nd oil production of both crude oils. Conversely at a low depletion rate (0.0030 PV/hr) foam-like flow is not observed in the less viscous crud

avy-oil solution gas drive are investigated. The results are striking. They show that the overburden pressure offsets partially the pore-pressure
 rix permeability production is dominant and occurs in Oman Iran Iraq Syria Turkey and Egypt and includes producing fields such as Qarn




optimize water injection plan for this field. Following the workflow the optimal water injection design for platforms D and E areas was develop

 ntions has been implemented in the Midway Sunset heavy oil field (Kern County California). This alternative production enhancement proce
/injector configurations found in a heavy oil field exploited with horizontal wells. The aim is to analyze different water production mecha




ut secondary metal precipitation. Slurry reactor tests elucidated the kinetics of mineral dissolution in mechanically ground field samples. Trea


e water. Furthermore if oil viscosity is not modeled as pressure dependent productivity indices will be under predicted and analysis of well tes
 Highly saline and hard brine; Large waterflood pattern volumes (10 MMbbl at 20 acre well spacing).� Despite 40 years of production invo




 to a low fluid loss drilling fluid system have resulted in significant incremental oil recovery that would not be produced by existing or additiona

 were chosen as the preferred alternative to provide maximum exposure of reservoir layers and improve production and ultimate recovery co


g multiple realizations. The framework also supports hierarchical DSE workflows that allow users to first explore a large design space using p

ed that a different approach would be required to assess the true value of the Frade asset and initiated a systematic and standardized asset
ndary and tertiary projects successful from both a technical and an economic point of view. Opportunities for improving recovery through syn

 previously NMR offers useful insights into the petrophysics of thin sand-shale laminations. Typically 1D high-resolution data is acquired to e
e modeling factors are examined by a D-optimal design. The study is applied to a shallow marine reservoir in the South Africa. The study indi
MR logs with the characteristic bimodal relaxation distribution. The thin laminations are often below the resolution of conventional logs that h


ment that is not representative of the derrick such as varying drilling mechanical conditions and temperature changes. We demonstrate the




 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

e of reservoir performance profiles for each well was the in-house Eclipseâ„¢ reservoir simulation models. The production profiles for each w

                       Introduction The push towards “digital oilfields has highlighted the need for efficient decision support systems t
t 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 improved

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
t assessment of this technology family; risk management to ensure safe and




mponent of the Gorgon Project. The target formation for geological disposal of this carb

condition that is unlikely to be met by real-world projects. T




 reservoir through production optimization to day-to-day steamflood and


% gas.� The heavy oil is generally recovered through thermal operations while the


able for decision making and thus the necessity for information integratio



of interoperable services with a defined future path.� A practical approach to the implementation of a




valuation process. Introduction Industry case histories demonstrate many types of ben



technical and business analysis tools Introduction The digital oilfield is the subject of a


CO2 process in fractured cores. We improved the CO2 sweep



are compatible with both polymers and alkali such as sodium
amount of electrolyte in the chase solutions we could maintain Winsor type II


erization of pH change in the rock; and (3) polymer microgel transp


er cylindrical reservoir. The effect of this stimul


d in 2006. The design and initial performance of the small scale test (SST) si

ween ICS and other fluids deployed on well construction


ves three key stages; the temporary isolation of the producing layers the perm



 appropriate for the trial. The treatment was designed u

 up a new hydrodynamic slug.� This slug moves through the road




part this assumption was made because dynamic calculatio



acrificing the smoothness and accuracy of the inverted distributions. It also allows direct fluid ty
he information void for reservoirs that fall within the bounds of measu




s paper describes improvements made to the existing procedures and pro

e. Increasing the concentration of oxygen scavenger and EDT


e seawater injection for reservoir pressure maintenance from day one. Scaling tendency pr

ed scale inhibitor chemistry.� The field data from these wells will be

cisions quickly and directly. The utility of these tools has not been determined f
s. We then generate upscaled relative permeability curves ( )




  gathering center (GC) GC-sand and key well-level observa

r saturation and location of the boundary between facies

njection porosity permeability CT scans and thin section


 selves but also the integration of these with remote intelligent field s


st ring of producers The Ratawi AMT concluded that a significant portion o


nd was designed to inject 5 000 to 10 000 bwpd into a sing

he lifetime of single foam films of crude-oil and asphaltene sol

e important role for a HMRWF than conventional waterfloods.




Data used in this study includes conventional open-hole we

of temperature on the adhesion of oil-coated fines to rock surfaces and ul

.e. dirt holding capacity and plugging tendency of media commonly used in san



not observed in the less viscous crude oil; however foam-like f

ure offsets partially the pore-pressure decline. This compaction in turn modif
udes producing fields such as Qarn Alam in Oman and Issaran and Bakr-Amer i




platforms D and E areas was developed and quickly implemented wi

ative production enhancement process is based on a combination of candidate
fferent water production mecha




chanically ground field samples. Treatment with acidic chelant fluids gener


 der predicted and analysis of well tests will result in estimated skin values
  Despite 40 years of production involving water flooding well-work and chan




 be produced by existing or additional vertic

e production and ultimate recovery compared to conventional vertical


explore a large design space using proxy models and selectively refine t

a systematic and standardized asset valuation process for Frade as part of its
s for improving recovery through synergistic activities among team members a

 high-resolution data is acquired to estimate sand volume f
oir in the South Africa. The study indicates that SCH study is particularly useful
resolution of conventional logs that have a typical vertical


ature changes. We demonstrate the applications of the method which allows dynami




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

 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

				
DOCUMENT INFO
Shared By:
Categories:
Tags:
Stats:
views:0
posted:5/1/2013
language:Unknown
pages:195