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Heriot watt - SPE Papers - Reservoir Engineering - Reservoir

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Heriot watt - SPE Papers - Reservoir Engineering - Reservoir 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
Heriot Watt University    SPE   124711          CO2
Heriot Watt University    SPE   121170        EOR/IOR
Heriot Watt University    SPE    99546        EOR/IOR
Heriot Watt University    SPE    88813    Flow Assurance
Heriot Watt University    SPE    86983    Flow Assurance
Heriot Watt University    SPE   110833    Flow Assurance
Heriot Watt University    SPE    99884    Fluid Description
Heriot Watt University    SPE   123423    Fluid Description
Heriot Watt University    SPE   100393    Fluid Description
Heriot Watt University    SPE   125203    Fluid Description
Heriot Watt University    SPE    88559    Fluid Description
Heriot Watt University    SPE    94067    Fluid Description
Heriot Watt University    SPE   115742   Formation Damage
Heriot Watt University    SPE   122267   Formation Damage
Heriot Watt University    SPE    98110   Formation Damage
Heriot Watt University    SPE    74666   Formation Damage
Heriot Watt University    SPE   100517   Formation Damage
Heriot Watt University    SPE   105189   Formation Damage
Heriot Watt University    SPE   115195   Formation Damage
Heriot Watt University    SPE   114058   Formation Damage
Heriot Watt University    SPE    98096   Formation Damage
Heriot Watt University    SPE   100480   Formation Damage
Heriot Watt University    SPE    87445   Formation Damage
Heriot Watt University    SPE   112538   Formation Damage
Heriot Watt University    SPE   114082   Formation Damage
Heriot Watt University    SPE   113595   Formation Damage
Heriot Watt University    SPE   100521   Formation Damage
Heriot Watt University    SPE   113926   Formation Damage
Heriot Watt University    SPE   121456   Formation Damage
Heriot Watt University    SPE   100518   Formation Damage
Heriot Watt University    SPE   114108   Formation Damage
Heriot Watt University    SPE   100515   Formation Damage
Heriot Watt University    SPE    86472   Formation Damage
Heriot Watt University    SPE   100112   Formation Damage
Heriot Watt University    SPE   112537   Formation Damage
Heriot Watt University    SPE   106422   Formation Damage
Heriot Watt University    SPE   107884   Formation Damage
Heriot Watt University    SPE   112500   Formation Damage
Heriot Watt University    SPE   114105   Formation Damage
Heriot Watt University    SPE   121376   Formation Damage
Heriot Watt University    SPE   121856   Formation Damage
Heriot Watt University    SPE    92663   Formation Damage
Heriot Watt University    SPE    96741   Formation Damage
Heriot Watt University    SPE   100520   Formation Damage
Heriot Watt University    SPE   100611   Formation Damage
Heriot Watt University    SPE   106133   Formation Damage
Heriot Watt University    SPE   113212   Formation Damage
Heriot Watt University    SPE   114075   Formation Damage
Heriot Watt University    SPE   121679   Formation Damage
Heriot Watt University    SPE   121857       Formation Damage
Heriot Watt University    SPE                Formation Damage
Heriot Watt University    SPE   114085       Formation Damage
Heriot Watt University    SPE   114106       Formation Damage
Heriot Watt University    SPE    98774       Formation Damage
Heriot Watt University    SPE   100516       Formation Damage
Heriot Watt University   IPTC    12804          Giant Field
Heriot Watt University    SPE    99949          Giant Field
Heriot Watt University    SPE   107163           Heavy Oil
Heriot Watt University    SPE   117479           Heavy Oil
Heriot Watt University    SPE   113409           Heavy Oil
Heriot Watt University    SPE   113234           Heavy Oil
Heriot Watt University    SPE    98337            HP/HT
Heriot Watt University    SPE   121113   Low Permeability Reservoirs
Heriot Watt University    SPE   120088   Low Permeability Reservoirs
Heriot Watt University    SPE   105800      Reservoir Description
Heriot Watt University    SPE   107263      Reservoir Description
Heriot Watt University    SPE    83960      Reservoir Description
Heriot Watt University    SPE   107142      Reservoir Description
Heriot Watt University    SPE   126088      Reservoir Description
Heriot Watt University    SPE    98875     Reservoir Development
Heriot Watt University    SPE   110207     Reservoir Development
Heriot Watt University    SPE   116659     Reservoir Management
Heriot Watt University    SPE   111102     Reservoir Management
Heriot Watt University    SPE   107197     Reservoir Management
Heriot Watt University    SPE   107171     Reservoir Management
Heriot Watt University    SPE   104608     Reservoir Management
Heriot Watt University    SPE   115744     Reservoir Management
Heriot Watt University    SPE   102903     Reservoir Management
Heriot Watt University    SPE    99877     Reservoir Management
Heriot Watt University    SPE    94173       Reservoir Modelling
Heriot Watt University    SPE   100295       Reservoir Modelling
Heriot Watt University    SPE   119139       Reservoir Modelling
Heriot Watt University    SPE   121193       Reservoir Modelling
Heriot Watt University    SPE   121210       Reservoir Modelling
Heriot Watt University    SPE   113557       Reservoir Modelling
Heriot Watt University    SPE   102135       Reservoir Modelling
Heriot Watt University    SPE   119030       Reservoir Modelling
Heriot Watt University    SPE   106229       Reservoir Modelling
Heriot Watt University    SPE   121054       Reservoir Modelling
Heriot Watt University    SPE   107147       Reservoir Modelling
Heriot Watt University    SPE   117421       Reservoir Modelling
Heriot Watt University    SPE   122651       Reservoir Modelling
Heriot Watt University    SPE   100223       Reservoir Modelling
Heriot Watt University    SPE   100497       Reservoir Modelling
Heriot Watt University    SPE    94072       Reservoir Modelling
Heriot Watt University    SPE   113594       Reservoir Modelling
Heriot Watt University    SPE   114772       Reservoir Modelling
Heriot Watt University    SPE    95322       Reservoir Modelling
Heriot Watt University    SPE   113597       Reservoir Modelling
Heriot Watt University    SPE   121109       Reservoir Modelling
Heriot Watt University    SPE   107485       Reservoir Modelling
Heriot Watt University    SPE    99920      Reservoir Modelling
Heriot Watt University    SPE   118924      Reservoir Modelling
Heriot Watt University    SPE   106620      Reservoir Modelling
Heriot Watt University    SPE   100953      Reservoir Modelling
Heriot Watt University    SPE   100345      Reservoir Modelling
Heriot Watt University    SPE   106679      Reservoir Modelling
Heriot Watt University    SPE    89992      Reservoir Modelling
Heriot Watt University    SPE   116008      Reservoir Modelling
Heriot Watt University    SPE   107556      Reservoir Modelling
Heriot Watt University    SPE   113864      Reservoir Modelling
Heriot Watt University    SPE   128363      Reservoir Modelling
Heriot Watt University    SPE   119605      Reservoir Modelling
Heriot Watt University    SPE   104347      Reservoir Modelling
Heriot Watt University    SPE   117229      Reservoir Modelling
Heriot Watt University    SPE   103760      Reservoir Modelling
Heriot Watt University    SPE   113394    Reservoir Performance
Heriot Watt University    SPE   107164    Reservoir Performance
Heriot Watt University    SPE   128607    Reservoir Performance
Heriot Watt University    SPE   120894    Reservoir Performance
Heriot Watt University    SPE    92887    Reservoir Performance
Heriot Watt University    SPE   103583    Reservoir Performance
Heriot Watt University    SPE   112474      State of the Nation
Heriot Watt University    SPE   112126      State of the Nation
Heriot Watt University    SPE   101310      State of the Nation
Heriot Watt University    SPE   115028         Surveillence
Heriot Watt University    SPE   102867         Surveillence
Heriot Watt University    SPE   107198         Surveillence
Heriot Watt University    SPE    90024         Surveillence
Heriot Watt University    SPE   121701         Surveillence
Heriot Watt University    SPE   109112         Surveillence
Heriot Watt University    SPE   105374         Surveillence
Heriot Watt University    SPE   121055         Surveillence
Heriot Watt University    SPE   107308   Unconventional Reservoirs
Heriot Watt University    SPE   122231       Well Deliverability
Heriot Watt University   IPTC    12145       Well Deliverability
Heriot Watt University    SPE   108173       Well Deliverability
Heriot Watt University    SPE   123682       Well Deliverability
Heriot Watt University    SPE    99878       Well Deliverability
Heriot Watt University    SPE    86485       Well Deliverability
Heriot Watt University    SPE   100417       Well Deliverability
Heriot Watt University    SPE   123466       Well Deliverability
Heriot Watt University    SPE   101821       Well Deliverability
Heriot Watt University    SPE   107338       Well Deliverability
Heriot Watt University    SPE   107432       Well Deliverability
Heriot Watt University    SPE   121916       Well Deliverability
Heriot Watt University    SPE   107634       Well Deliverability
Heriot Watt University    SPE   115726       Well Deliverability
Heriot Watt University    SPE   104183       Well Deliverability
Heriot Watt University    SPE   107138       Well Deliverability
Heriot Watt University    SPE   108700       Well Deliverability
Heriot Watt University    SPE   100191       Well Deliverability
Heriot Watt University    SPE    99929       Well Deliverability
Heriot Watt University   SPE   107864   Well Deliverability
Heriot Watt University   SPE   100512   Well Deliverability
Heriot Watt University   SPE   122266   Well Deliverability
Heriot Watt University   SPE   122054   Well Deliverability
Heriot Watt University   SPE   122064   Well Deliverability
Heriot Watt University   SPE   101994   Well Deliverability
Heriot Watt University   SPE    89895   Well Deliverability
Heriot Watt University   SPE   110895   Well Deliverability
Heriot Watt University   SPE   106012   Well Deliverability
Heriot Watt University   SPE   113889   Well Deliverability
Heriot Watt University   SPE   112143   Well Deliverability
Heriot Watt University   SPE   107168   Well Deliverability
Heriot Watt University   SPE   110272    Well Testing
Heriot Watt University   SPE   121949    Well Testing
Heriot Watt University   SPE   122409    Well Testing
Heriot Watt University   SPE   100951    Well Testing
Heriot Watt University   SPE   128359    Well Testing
Heriot Watt University   SPE   100993    Well Testing
Heriot Watt University   SPE   120893    Well Testing
Heriot Watt University   SPE   113323    Well Testing
Heriot Watt University   SPE   107521    Well Testing
Heriot Watt University   SPE   107209    Well Testing
            Section                                  Subject
Mechanism - Dissolution and Injection CO2-Brine Surface Dissolution and Injection
     Enriched Water Injection                        Using CO2
           Technologies                         North Sea Experience
        Modelling - Choke
       Modelling - Pipelines                          Heat Loss
         Wax/Asphaltenes                           Risk Reduction
          Acid Numbers
     Downhole Fluid Analysis                  Neural Network Modelling
     Downhole Fluid Analysis                       OBM Clean-up
      Production Chemistry                           Asphaltenes
     Reservoir Fluid Detection                   Wavelet Transform
             Tracers                              Gas Condensate
    Complex Wells - Clean-up                  Downhole Control Valves
    Complex Wells - Clean-up                  Downhole Control Valves
           Sand Control                          Southern North Sea
              SCAL                            Scale inhibitor treatments
          Scale Analysis
           Scale Control                          Chalk Reservoirs
           Scale Control                                ESP's
           Scale Control                           Halite Inhibition
           Scale Control                         Low Suphate Water
           Scale Control                     Low Suphate Water Design
           Scale Control
           Scale Control
           Scale Control
         Scale Detection
          Scale Inhibitors                     Chemical Development
          Scale Inhibitors                     Chemical Development
          Scale Inhibitors                     Chemical Development
          Scale Inhibitors                          Core Testing
          Scale Inhibitors
        Scale Management                     Core Testing - Carbonates
        Scale Management                     Impact of Depressurization
        Scale Management                           Intelligent Well
        Scale Management                         Low Suphate Water
        Scale Management                              Modelling
        Scale Management                              Modelling
        Scale Management                              Modelling
        Scale Management                              Modelling
        Scale Management                              Modelling
        Scale Management                              Modelling
        Scale Management                              Monitoring
        Scale Management                      Produced Water Injection
        Scale Management
        Scale Management
        Scale Management
        Scale Management
        Scale Management
        Scale Management
       Scale Management
       Scale management
        Scale Mangement                   Squeeze Evaluation
        Scale Mangement                   Value of Information
       Squeeze Treatment                  Impact of Fracturing
         Sulfate Stripping                    Gyda Field
       Reservoir Modelling
           Surveillence
       CO2/Water Injection                       Alaska
        Depressuriziation                Pore Network Modelling
      Reservoir Description              Anisotropic Rel. Perms
               SAGD                       Performance Analysis
      Treatment Chemicals                    Thermal Aging
                 PTA
      Reservoir Description             Gas Condensate Mobility
     Flow Unit Determinaton                    DaQing Field
           Permeability                   Carbonate Reservoir
Relative Permeability Correlation           Gas Condensate
  Saturation Height Functions       Different Estimation Approaches
      Wettability Evaluation              Carbonate Reservoir
      Subsea Development                 Okwori and Nda Fields
           Thin Oil Rim                      Intelligent Wells
            Artificial Lift                     Orito Field
           Gas Storage                 Well Performance Analysis
          Intelligent Well                      Feasibility
  Modelling - Integrated Asset
   Produced Water Injection             Permeability Reduction
   Uncertainty Management                  Completion Type
 Well Placement Optimisation           Production Potential maps
 Well Placement Optimisation           Production Potential maps
            4D Seismic                       Schiehallion
            4D Seismic
           Assisted HM                    Algorithm Comparison
           Assisted HM                   Ant Colony Optimisation
           Assisted HM                Efficient Parameter Searching
           Assisted HM                    Fault Transmissbilities
           Assisted HM                  Neighbourhood Algorithm
           Assisted HM                    Stochastic Framework
           Assisted HM                  Uncertainty Management
    Complex Well Modelling                Temperature Prediction
 Efficient Parameter Searching                  Nelson Field
        Fracture Modelling          Integrated in Reservoir Simulation
              Gridding                   Upgridding - Case Study
     Heterogeneity - Subgrid             Uncertainty Management
       Inflow Performance                    Gas Condensate
       Inflow Performance                    Gas Condensate
          Inflow Profiling                    Intelligent Wells
          Inflow Profiling                    Intelligent Wells
  Injector Producer Modelling               Capacitance Model
  Modelling - Skin Formulation               Gas Condensate
  Modelling - Skin Formulation                Horizontal wells
 Naturally Fractured Reservoirs                3 Phase Model
Naturally Fractured Reservoirs
Naturally Fractured Reservoirs
          Net-Gross                     Total Property Modelling
      Network modelling                  Deepwater Reservoir
Numerical Well Test Analysis                Gas Condensate
         Permeability                           Uscaling
Pore-Scale Network Modelling            3D Rel. Perm Prediction
Pore-Scale Network Modelling             Blowdown Rel. Perms.
Pore-Scale Network Modelling              Gravitational Effects
Pore-Scale Network Modelling                  WAG Floods
    Results Interpretation
       Scale Modelling                         Streamlines
          Streamline                           Upgridding
      Thermal Recovery                 Finite Volume Formulation
           Upscaling                          Heterogeneity
      Depressuriziation                       Fluid Mobility
      Fault Reactivation         Coupled Reservoir/Geomechanical Model
  Mechanism - Diagenesis                 North Morecombe Field
   Mechanism - Diffusion                          SAGD
 Mechanism - Miscible Gas            Homogeneous/Heterogeneous
     Mechanism - WAG                        Micro-Scale flow
  Frac Pack Scale Inhibitor
   Horizontal Well Testing                    North Africa
       Well Intervention                    Zonal Isolation
       4D Micro gravity                   Water Encroachment
        Complex Wells                     Value of Information
     Downhole Sensors                      Quality Assurance
     Multiphase Metering                       Downhole
  Produced Water Analysis
               PTA               Continuous Reservoir Response Analysis
    Water Entry Detection                    Pressure Trends
       Zonal Allocation                       Intelligent Wells
     Reserves and Rates                         River Basin
           Clean-up                           Intelligent Wells
        Compex Wells                     Downhole control Valves
  Completion Optimisation                      Marginal Wells
       Complex Wells                     Downhole Control Valves
           Dual ESP                             Appications
       Fracture Design                       Chalk Reservoirs
       Fracture Design                     Damage prevention
       Fracture Design                      Fracture Geometry
       Fracture Design                    Non-Darcy/Multiphase
       Fracture Design                     Waxy-Oil Reservoir
     Fracture Diagnosis                 Clean-up Gas Condensate
    Fracture Diagnostics                Clean-up Gas Condensate
    Fracture Diagnostics                         Skin Factor
    Fracture Performance                 Gas-Condensate Mobility
        Horizontal Well                    Impact of Trajectory
     Inflow Performance                      Gas Condensate
        Intelligent Well                 Downhole Control Valves
        Intelligent Well          Downhole Control Valves - Placement
        Intelligent Well              Proactive and Reactive Control
  Performance Decline                  Scale Formation
  Performance Decline                  Scale Formation
   Production Capacity                  UBD - Vietnam
       Sand Control                      Gravel Pack
       Sand Control                      Gravel Pack
       Sand Control                       Tapti Field
     Sand production                  Flowing conditions
        Stimulation                     Acid Treatment
        Stimulation             Relative Permeability Modifier
  Water Entry Detection                Intelligent Wells
      Water Injection                    Flow Control
     Well Comparison             Gas Condensate - Layered
Analysis - Fluivial Reservoir      PTA/Seismic Attribute
  Multi-well Decovolution
   Numercial Analysis                    Streamline
   Numerical Analysis                  Heterogeneity
            PTA                  Flow Regime Identification
            PTA                      Gas Condensate
            PTA                    Challenging Conditions
    PTA Interpretation          Deconvolution/Decline Curve
    PTA Interpretation               Wavelet Method
 Rel Perm Determination
                                            Title
CO2-Brine Surface Dissolution and Injection: CO2 Storage Enhancement
Oil Recovery Improvement Using CO2―Enriched Water Injection
EOR Survey in the North Sea
Critical and Subcritical Oil/Gas/Water Mass Flow Rate Experiments and Predictions for Chokes
A Simple Model for Predicting Heat Loss and Temperature Profiles in Insulated Pipelines
Impact of Flow Assurance in the Development of a Deepwater Prospect
Acid Number Measurements Revisited
Application of Artificial Neural Networks to Downhole Fluid Analysis
Compositional Modeling of Oil-Based-Mud-Filtrate Cleanup During Wireline Formation Tester Sampling
Verification of Asphaltene-Instability-Trend (ASIST) Predictions for Low-Molecular-Weight Alkanes
Identifying Reservoir Fluids by Wavelet Transform of Well Logs
Application of Tracers in Oil-Based Mud for Obtaining High-Quality Fluid Composition in Lean Gas/Condensate Reservoirs
Advanced Wells: How to Make a Choice between Passive and Active Inflow-Control Completions
Advanced Well Flow Control Technologies can Improve Well Clean-up
Challenging Convention in Sand Control: �Southern North Sea Examples
Coreflood Studies Examine New Technologies That Minimize Intervention Throughout Well Life Cycle
Analysis of Organic Field Deposits: New Types of Calcium Naphthenate Scale or the Effect of Chemical Treatment?
Scale Control in Chalk Reservoirs: The Challenge of Understanding the Impact of Reservoir Processes and Optimizing Scale M
Squeezing Scale Inhibitors to Protect Electric Submersible Pumps in Highly Fractured, Calcium Carbonate Scaling Reservoirs
Mechanistic Study of Chemicals Providing Improved Halite Inhibition
Low Sulfate Seawater Injection for Barium Sulfate Scale Control: A Life-of-Field Solution to a Complex Challenge
Design of Low-Sulfate Seawater Injection Based Upon Kinetic Limits
The Comparison of Nonaqueous and Aqueous Scale-Inhibitor Treatments: Experimental and Modeling Studies
Inhibition Mechanisms for Sulphide Scales
Using Nature to Provide Solutions to Calcareous Scale Deposition
Detection of Scale Deposition Using Distributed Temperature Sensing
Development of a Nonaqueous Scale-Inhibitor Squeeze Simulator
Development of a New Polymer Inhibitor Chemistry for Downhole Squeeze Applications
Development of Environmental Friendly Iron Sulfide Inhibitors for Field Application
Analysis of the Mechanism of Transport and Retention of Nonaqueous-Scale-Inhibitor Treatments in Cores Using Novel Tracer
Coupled Adsorption/Precipitation of Scale Inhibitors: Experimental Results and Modelling
Scale Inhibitor Core Floods in Carbonate Cores: Chemical Interactions and Modelling
Impact on Scale Management of the Engineered Depressurization of Waterflooded Reservoirs:�Risk Assessment Principles
Impact of Intelligent Wells on Oilfield Scale Management
When Will Low Sulphate Seawater No Longer Be Required on the Tiffany Field?
Modelling of Nonaqueous and Aqueous Scale-Inhibitor Squeeze Treatments
Characterization of Sulfate-Scaling Formation Damage From Pressure Measurements
A New Method To Characterize Scaling Damage From Pressure Measurements
Modelling the Impact of Diesel vs Water Overflush Fluids on Scale Squeeze Treatment Lives Using a Two-Phase Near-Wellbo
The Challenge of Modelling and Deploying Divertion for Subsea Scale Squeeze Application
Modelling the Placement of Scale Squeeze Treatments in Heterogeneous Formations with Pressurised Layers
Evaluation Methods for Suspended Solids and Produced Water as an Aid in Determining Effectiveness of Scale Control Both D
Limiting Scale Risk at Production Wells by Management of PWRI Wells
Placement Using Viscosified Non-Newtonian Scale Inhibitor Slugs: The Effect of Shear Thinning
Laboratory and Field Prediction of Sulfate Scaling Damage
The Optimisation of a Scale Management and Monitoring Program for During the Production-Decline Phase of the Life Cycle
Modeling a Surfactant Preflush with Non-Aqueous and Aqueous Scale Inhibitor Squeeze Treatments
Performance of Scale Inhibitors Under Carbonate and Sulfide Scaling Conditions
Successful Scale Mitigation Strategies in Saudi Arabian Oil Fields
Impact of Mutual Solvent Preflush on Scale Squeeze Treatments: Extended Squeeze Lifetime and Improved Well Clean-up Tim
Wellbore Stability Issues in Shales or Hydrate Bearing Sediments
Scale Squeeze Evaluation Through Improved Sample Preservation, Inhibitor Detection and Minimum Inhibitor Concentration M
The Cost and Value of Field, Laboratory, and Simulation Data for Validating Scale Inhibitor Treatment Models
What Would Be the Impact of Temporarily Fracturing Production Wells During Squeeze Treatments?
Impact of In-Situ Sulfate Stripping on Scale Management in the Gyda Field
Seligi: Complex Modeling Case Study and Optimization of a Malay Basin Giant
Real-Time Field Surveillance and Well Services Management in a Large Mature Onshore Field: Case Study
Heavy Oil Recovery by Liquid CO2/Water Injection
Dynamic Pore Network Simulator for Modelling Buoyancy-Driven Migration during Depressurisation of Heavy-Oil Systems
Anisotropic Relative Permeabilities for Characterising Heavy-Oil Depletion Experiment
Performance Analysis of SAGD Wind-Down Process With CO2 Injection
Influence of Thermal Aging on Treatment Chemicals in HP/HT Applications: From Development of Equipment to Field Applica
Well Test Analysis in Tight Gas Reservoirs
Gas Condensate Relative Permeability of Low Permeability Rocks: Coupling Versus Inertia
Principle of a New Flow-unit Auto-subdividing Method and its Application in DaQing Oilfield
Permeability Estimation Using Hydraulic Flow Units in Carbonate Reservoirs
Variations of Gas/Condensate Relative Permeability With Production Rate at Near-Wellbore Conditions: A General Correlation
Estimation of Saturation Height Function Using Capillary Pressure by Different Approaches
Wettability Studies at the Pore Level of Saudi Aramco Reservoirs
Subsea Development of Okwori and Nda Oil Fields, Niger Delta
Enhancing Production From Thin Oil Column Reservoirs Using Intelligent Completions
Artificial Lift Optimization in the Orito Field
Performance Analysis of Horizontal Wells for Underground Gas Storage in Depleted Gas Fields
A Rigorous Stochastic Coupling of Reliability and Reservoir Performance When Defining the Value of Intelligent Wells
Successful Application of a Robust Link to Automatically Optimise Reservoir Management of a Real Field
Permeability Damage Due to Water Injection Containing Oil Droplets and Solid Particles at Residual Oil Saturation
Impact of Reservoir Uncertainty on Selection of Advanced Completion Type
Well Location Selection From Multiple Realizations of a Geomodel Using Productivity Potential Maps–A Heuristic Technique
Well Location Selection From a Static Model and Multiple Realisations of a Geomodel Using Productivity-Potential Map Techn
Multiple-Model Seismic and Production History Matching: A Case Study
Reducing Reservoir Prediction Uncertainty by Updating a Stochastic Model Using Seismic History Matching
Comparison of Stochastic Sampling Algorithms for Uncertainty Quantification
Ant Colony Optimization for History Matching
Faster Convergence in Seismic History Matching by Efficient Parameter Searching
Updating Fault Transmissibilies in Simulations by Successively Adding Data to an Automated Seismic History Matching Proces
Hydrocarbon Production Forecast and Uncertainty Quantification: A Field Application
Stochastic History Matching of a Deepwater Turbidite Reservoir
Effect of Sampling Strategies on Prediction Uncertainty Estimation
Temperature Modeling and Analysis of Wells with Advanced Completion
Faster Seismic History Matching in a UKCS Reservoir
Modeling of Hydraulically Fractured Wells in Full Field Reservoir Simulation Model
Reservoir Management and Optimization of Mature Field Using WAG Injection: Implication Of A New Upgriding Technique in B
Quantification of Uncertainty Due to Subgrid Heterogeneity in Reservoir Models
Critical Evaluation of Existing Methods for Accounting for Multiphase Effects Around Producers in Depleting Gas/Condensate R
Gas-Condensate Flow in Perforated Regions
Modification of Temperature Prediction Model to Accommodate I-Well Complexities
Prediction of Temperature Distribution in Intelligent Wells
A Capacitance Model To Infer Interwell Connectivity From Production- and Injection-Rate Fluctuations
A New Flow Skin Factor Formulation for Hydraulically Fractured Wells in Gas Condensate Reservoirs
A New Skin Factor Formulation for Flow Around Horizontal Wells Including Anisotropy and Partial Penetration
Black-Oil Simulations for Three-Component, Three-Phase Flow in Fractured Porous Media
Experimental and Simulation Studies of SAGD Process in Fractured Reservoirs
Massively Parallel Sector Scale Discrete Fracture and Matrix Simulations
Total-Property Modeling: Dispelling the Net-to-Gross Myth
Predicting Deepwater Well Behavior
A Gas/Condensate Reservoir Productivity Evaluation and Forecast Through Numerical Well Testing
Permeability Upscaling Techniques for Reservoir Simulation
Prediction of Three-Phase Relative Permeabilities Using a Pore-Scale Network Model Anchored to Two-Phase Data
Relative Permeabilities for Blowdown of a Near-Critical Oil Reservoir: Issues and Solutions Emerging From Pore-Scale Networ
A Pore-Scale Network Modeling Study of Gravitational Effects During Solution Gas Drive: Results From Macroscale Simulation
Pore-Scale Simulation of WAG Floods in Mixed-Wet Micromodels
Understanding Dynamic Simulation Results
The Application of Streamline Reservoir Simulation Calculations to the Management of Oilfield Scale
Efficiency Evaluation of Non-Uniform Upgridding Method Based on Streamlines Approach: Western Siberia Field Example
Development of a Higher-order Finite Volume Method for Simulation of Thermal Oil Recovery Process Using Moving Mesh Stra
A New Practical Method for Upscaling in Highly Heterogeneous Reservoir Models
Effect of Depressurization on Trapped Saturations and Fluid Flow Functions
Identification of Activated (Therefore Potentially Conductive) Faults and Fractures Through Statistical Correlations in Production
Recovery Behaviour of a Partly Illitized Sandstone Gas Reservoir
The Effect of Oil and Gas Molecular Diffusion in Production of Fractured Reservoir During Gravity Drainage Mechansim by CO
Experimental and Numerical Studies of Gas/Oil Multicontact Miscible Displacements in Homogeneous and Crossbedded Porou
Analysis of Phase Displacement Paths in Gas Injection and Three-Phase Flow in Water-Alternating-Gas (WAG) Processes
A History of Frac-Pack Scale-Inhibitor Deployment
The Future Challenge of Horizontal Well Testing in a North African Field: An Overview of a Decade of Field Practice and Opera
Zonal Isolation Modeling and Measurements—Past Myths and Today's Realities
Utilizing 4D Microgravity To Monitor Water Encroachment
Data Richness and Reliability in Smart-Field Management - Is There Value?
Tracking the State and Diagnosing Downhole Permanent Sensors in Intelligent Well Completions With Artificial Neural Network
Well Surveillance With a Permanent Downhole Multiphase Flowmeter
Reacting Ions Method To Identify Injected Water Fraction in Produced Brine
Transient Pressure Analysis of 4D Reservoir System Response From Permanent Down Hole Gauges (PDG) for Reservoir Mon
A Novel Approach of Detecting Water Influx Time in Multizone and Multilateral Completions Using Real-Time Downhole Pressu
Zonal Rate Allocation in Intelligent Wells
Powder River Basin Coalbed Methane Wells - Reserves and Rates
Efficient Intelligent Well Cleanup using Downhole Monitoring
Advanced Wells: A Comprehensive Approach to the Selection Between Passive and Active Inflow Control Completions
Multiple-Zone Completion in Marginal Production Wells
A Generalized Predictive Control for Management of an Intelligent Well’s Downhole, Interval Control Valves—Design and
Analysis of Possible Applications of Dual ESPs—A Reservoir-Engineering Perspective
Fracture Treatment Design and Execution in Low-Porosity Chalk Reservoirs
Field Case Studies: Damage Preventions Through Leakoff Control of Fracturing Fluids in Marginal/Low-Pressure Gas Reservo
Optimization of Hydraulic Fracture Geometry
Designing Hydraulic Fractures in Russian Oil and Gas Fields to Accommodate Non-Darcy and Multiphase Flow
Hydraulic Fracturing With Heated Fluids Brings Success in High-Pour-Point Waxy-Oil Reservoir in India
The Effects of Fracture Cleanup on the Productivity of Gas Condensate Systems
Investigation of Cleanup Efficiency of Hydraulically Fractured Wells in Gas Condensate Reservoirs
New Mechanical and Damage Skin Factor Correlations for Hydraulically Fractured Wells
Gas Condensate Relative Permeabilities in Propped Fracture Porous Media: Coupling Versus Inertia
The Effect of Well Trajectory on Horizontal Well Performance
The Effect of Positive Coupling and Negative Inertia on Deliverability of Gas Condensate Wells
Inflow Control Devices: Application and Value Quantification of a Developing Technology
Techniques for Optimum Placement of Interval Control Valve(s) in an Intelligent Well
Should “Proactive or “Reactive Control Be Chosen for Intelligent Well Management?
Field-Data-Based Prediction of Well Productivity Decline Due to Sulphate Scaling
Injectivity Impairment Due to Sulfate Scaling During PWRI: Analytical Model
Predicting the Production Capacity During Underbalanced-Drilling Operations in Vietnam
Horizontal Open Hole Gravel Pack Placement Requirements in Selective Completion Projects
A Comparison of Design Placement Methodologies for Horizontal Open Hole Gravel Pack in Multizone Completion Projects
Evolution of Sand Control Completion Techniques in the South Tapti Field
Sanding: A Rigorous Examination of the Interplay Between Drawdown, Depletion, Startup Frequency, and Water Cut
Acid Fracturing of Gas Wells by Use of an Acid Precursor in the Form of Solid Beads: Lessons Learned From First Field Applic
Sensitivity Study on the Main Factors Affecting a Polymeric RPM Treatment in the Near-Wellbore Region of a Mature Oil-Produ
Real-Time Water Detection and Flow Rate Tracking in Vertical and Deviated Intelligent Wells with Pressure Sensors
Downhole Flow Control For High Rate Water Injection Applications
Comparison of Vertical, Slanted, and Horizontal Wells Productivity in Layered Gas-Condensate Reservoirs
Integrating Pressure Transient Test Data With Seismic Attribute Analysis to Characterize an Offshore Fluvial Reservoir
Multi-Well Deconvolution Algorithm for the Diagnostic, Analysis of Transient Pressure With Interference From Permanent Down
New Advance in Numerical Well Testing Through Streamline Simulation
Fighting Against Nonunique-Solution Problems in Heterogeneous Reservoirs Through Numerical Well Testing
Statistical Diagnosis (VEMST) of Flow Regime: Alternative to Pressure Derivative Approach in Pressure Transient Analysis—P
Well Test Analysis in Lean Gas Condensate Reservoirs: Theory and Practice
Pressure Transient Well Testing Encountered Complexities: A Case Study
Application of Deconvolution and Decline-Curve Analysis Methods for Transient Pressure Analysis
Analyzing Transient Pressure From Permanent Downhole Gauges (PDG) Using Wavelet Method
Using Drillstem and Production Tests To Model Reservoir Relative Permeabilities
                                 Author                                      Abstract
                                                                             Abstract Carbon capture and storage (CCS) is cap
Paul Emeka Eke, SPE, Mark Naylor, Stuart Haszeldine, and Andrew Curtis, Scottish Centre for Carbon Storage, School of Geo
                                                                              , Shaun CO2 injection is increasingly considered a
Masoud Riazi ,SPE , Mehran Sohrabi ,SPE , Mahmoud Jamiolahmady ,SPE Abstract Ireland, Christopher Brown/ Institute of Pe
                                                                              Norge; This Kleppe, SPE, NTNU
A.R. Awan, SPE, NTNU and Total E&P Norge; R. Teigland, SPE, Total E&P Abstract and J. paper provides a summary and a gu
                                                                              Oil and Gas R&D Center; S. Selmer-Olsen, Det N
R.B. Sch�ller, Norwegian U. of Life Sciences;S. Munaweera, Norsk HydroSummary A large database on critical and subcriti
                                                                             Summary Accurate predictions of heat loss and te
Boyun Guo, SPE, Shengkai Duan, SPE, Ali Ghalambor, SPE, U. of Louisiana at Lafayette
                                                                             Abstract Gulf of Mexico; and George J. Hirasaki a
Doris L. Gonzalez and Abul K.M. Jamaluddin, Schlumberger; Trond Solbakken, HydroIn deepwater production systems extrem
Tianguang Fan and Jill S. Buckley, PRRC, New Mexico Tech                     Summary We propose an improved procedure for
                                                                             Summary Reservoir characterization and asset m
Peter Hegeman, SPE, and Chengli Dong, SPE, Schlumberger; and Nikos Varotsis, SPE, and Vassilis Gaganis, SPE, Technica
                                                                             Summary MiscibleCleanup During(OBM) filtrate co
                                                                                          Filtrate oil-based-mud Wireline Forma
Faruk O. Alpak, SPE, Hani Elshahawi, SPE, and Mohamed Hashem, SPE, Shell International Exploration and Production; and
                                                                             Summary Anticipating Weight Alkanes
                                                                                          Molecular when and where
Jefferson L. Creek and Jianxin Wang, Chevron Energy Technology Company, and Jill S. Buckley, New Mexico Tech asphalten
                                                                             Summary The China Natl. Petroleum Corp. (CNPC
Wen-Zheng Yue, SPE, and Guo Tao, SPE, China U. of Petroleum, and Zhen-Wu Liu, SPE, wavelet-transform (WT) method ha
F. Gozalpour, A. Danesh, A.C. Todd, and B. Tohidi, SPE, Heriot-Watt U.       Summary Oil-based drilling fluids are used extens
                                                                             Abstract Horizontal and multi-lateral wells allow oil
V.M. Birchenko and F.T. Al-Khelaiwi, SPE, Heriot-Watt University; M.R. Konopczynski, SPE, WellDynamics (a Halliburton Com
                                                                             Abstract Formation damage created during drilling
F. T. Al-Khelaiwi, SPE, K. M. Muradov, SPE, D. R. Davies, SPE, and D. K. Olowoleru, SPE, Heriot Watt University, Edinburgh,
                                                                              Limited
Colin McPhee, SPE, Chris Farrow, SPE, and Phil McCurdy, SPE, Helix RDSSummary Sand production is a major issue facing
                                                                             Summary With the development of
M.M. Jordan, SPE, ONES; I.R. Collins, SPE, and A. Gyani, SPE, BP; and G.M. Graham, SPE, Scaled Solutions more and mor
                                                                             Abstract Organic field deposits from distinct geog
A.G. Shepherd, SPE, G. Thomson, R. Westacott, and K.S. Sorbie, SPE, Heriot-Watt U., and M. Turner and P.C. Smith, SPE,
M.M. Jordan, SPE, Nalco, and E.J. Mackay, SPE, Heriot-Watt U.                Abstract The scale control challenges for a large N
                                                                             Abstract Rosneft has oil fields in Western Volosh
Neil Poynton, SPE, Alan Miller, Dmitry Konyukhov, and Andre Leontieff, Baker Hughes, and Ilgiz Ganiev and AlexanderSiberia
                                                                             Abstract This paper investigates the application of
Hua Guan, SPE, M-I SWACO Production Technologies; Richard Keatch, OMS Limited; Charles Benson, SPE, and Neil Graing
                                                                              and Eric J. Mackay, Heriot-Watt University
Myles M. Jordan, Nalco, Ian R. Collins, BP Exploration Operating Company, Summary The injection of seawater into oil-bearin
                                                                             Abstract Reliance on Rice U.
J.E. McElhiney, SPE, Pratt Technology Management, and M.B. Tomson, SPE, and A.T. Kan, SPE,low sulphate seawater as so
                                                                             Summary This paper U.
H. Guan, SPE, Champion Technologies, and K.S. Sorbie, SPE and E.J. Mackay, SPE, Heriot-Wattdescribes results from a ser
                                                                             Abstract: Sulphide scales have over
C. Okocha, K.S. Sorbie, and L.S. Boak, Institute of Petroleum Engineering, Heriot-Watt University, Edinburgh, UKrecent years
W.C. Cheong, A. Neville, P.H. Gaskell, and S. Abbott, University of Leeds Abstract The field of biomimetics is expanding in e
                                                                             Abstract The rapid deployment
Fajhan H. Almutairi, Kuwait Institute for Scientific Research, and David R. Davies, Heriot-Watt University of distributed tempe
O. Vazquez, E.J. Mackay, SPE, and K.S. Sorbie, SPE, Heriot-Watt U.           Abstract This paper describes the development a
                                                                             Abstract Inhibitor Leirvik, treatments have been re
Harry Montgomerie, Ping Chen, Thomas Hagen, Olav Vikane, Rozenn Matheson, and Vibeke squeezeChampion Technologies
                                                                             Abstract The inhibition of
Tao Chen, Harry Montgomerie, Ping Chen, Thomas Hagen, and Stuart Kegg, Champion Technologiesiron sulfide mineral scale
                                                                               and H. Guan, SPE, M-I Swaco Production Techno
R.A. Shields, K.S. Sorbie, SPE, M.A. Singleton, SPE, Heriot-Watt University,Summary In recent years a number of nonaqueou
M. Kahrwad, K.S. Sorbie, and L.S. Boak, Institute of Petroleum Engineering, Abstract In this paper results are presented on the
                                                                              Heriot-Watt University
                                                                             Abstract In previous work (SPE 87447)
S. Baraka-Lokmane and K S Sorbie Institute of Petroleum Engineering, Heriot-Watt University, Edinburgh, Scotland the effec
M. Chekani, Natl. Iranian Oil Corp., and E.J. Mackay, SPE, Heriot-Watt U. Summary Increased oil and particularly gas produ
V. Kavle, S. Elmsallati, E. Mackay, and D. Davies, Heriot-Watt U.            Abstract The main challenge facing the oil industr
                                                                              CNR International; sulphate rich Nalco; and John
Murshid Al-Riyami, PDO; Eric Mackay, Heriot-Watt University; Gabriel Deliu,Abstract Injection ofMyles Jordan, seawater into res
O. Vazquez, E.J. Mackay, SPE, and K.S. Sorbie, SPE, Heriot-Watt U.           Abstract The most common method for preventing
                                                                             Abstract Mixing of
P. Bedrikovetsky, M. Marotti, I.A. Lima Neto, and T. Carageorgos, North Fluminense State U. sea- and production waters duri
                                                                             Abstract Sulphate scaling with consequent deposit
T. Carageorgos, M. Marotti, and P. Bredrikovetsky, SPE, North Fluminense State University (UENF - LENEP)
                                                                              SPE, Nalco
O. Vazquez and E. Mackay, SPE, Heriot-Watt University, and Myles Jordan, Abstract This paper describes the development of
M.M. Jordan, SPE, Nalco Ltd., and E.J. Mackay, SPE, Heriot-Watt University   Abstract Due to the increased cost of scale manag
                                                                             Abstract
O. Vazquez, SPE, E.J. Mackay, SPE, and K.S. Sorbie, SPE, Heriot-Watt University The most common method for preventing
M.M. Jordan, C.J. Johnston, and M. Robb, Nalco                               Summary The formation of mineral scale (carbona
Eric J. Mackay, SPE, Heriot-Watt U.                                          Abstract Mixing of injected seawater with formatio
                                                                             Summary and BP Exploration, are and very hete
K.S. Sorbie and E.J. Mackay, Heriot-Watt University; I.R. Collins, Heriot-Watt UniversityReservoir formations UK; oftenR. Wat, S
                                                                             Abstract The BaSO4 scaling is a chronicle disaste
P.G. Bedrikovetsky, SPE, North Fluminense State U. (LENEP/UENF); E. Mackay, SPE, Herriot-Watt U.; R.P. Monteiro,�LEN
                                                                             Abstract This Nalco; and Alistair Strachan, Baker
Myles Jordan, Nalco; Ian Archibald, Chevron; Rod Farrell, Baker Petrolite; Clare Johnston, paper presents field results from sca
                                                                              University, Edinburgh, UK and M.M. for preventing
O. Vazquez, E.J. Mackay, SPE, K. Al Shuaili, K.S. Sorbie, SPE, Heriot-Watt Abstract The most common method Jordan, SPE,
                                                                             Abstract This paper compares the scale inhibition e
J. Kevyn Smith, SPE, Julie Hammons, Galyn Boyd, SPE, and Qiang Fu, SPE, Baker Petrolite
Kris U. Raju, SPE, Saudi Aramco                                              Abstract Scale deposition either in the formation o
                                                                              Abstract The most common
O. Vazquez, SPE, E. Mackay, SPE, K. Sorbie, SPE, Heriot-Watt University and M. Jordan, SPE, Nalco method for preventing
Reem Freij-Ayoub,CSIRO Petroleum                                              Wellbore instability can be an immediate result of s
                                                                              Abstract In and Dorthe Christensen, StatoilHydro
Kari Ramstad, SPE, StatoilHydro; Hans Christian Rohde, M-I SWACO; and Trine Tydal North Sea oil and gas fields seawater
                                                                              Abstract Scale formation presents a flow assuranc
J.A. Patroni Zavala, E.J. Mackay, O. Vazquez, L.S. Boak, and M. Singleton, Heriot-Watt University, and Gill Ross, Shell UK
A. Al-Rabaani, PDO, and E.J. Mackay, Heriot-Watt U.                           Abstract It is generally assumed that scale inhibito
                                                                              Abstract While barium stripping is and M. Jordan
E. Mackay, K. Sorbie, and V. Kavle, Heriot-Watt U.; E. S�rhaug and K. Melvin, Talisma; and K. Sjurs�ther commonly obs
                                                                               Yong Abdullah/ ExxonMobil Exploration effort by
Dave S. Frankel/ ExxonMobil Production Company (EMPC), Muhammad AwAbstract This paper describes a two-yearand Prod
                                                                              Summary This paper describes Chevron
L. Ormerod and G. Stephenson, Weatherford, SPE; H. Sardoff, J. Wilkinson, and B. Cox, SPE; B. Erlendson,the planning for im
A. Al-Quraini, Petroleum Development Oman (PDO), and M. Sohrabi and M.Abstract Alaska’s North Slope reservoirs conta
                                                                               Jamiolahmady, Heriot-Watt U.
                                                                              Abstract number of vertically-oriented
C.C. Ezeuko and S.R. McDougall, Heriot-Watt University; I. Bondino, TOTAL E&P UKALtd; G. Hamon, TOTAL S.A heavy oil d
                                                                              Abstract and G. years TOTAL S.A.
C.C. Ezeuko and S.R. McDougall, Heriot-Watt University; I. Bondino, TOTAL E&P UK;In recentHamon,the use of pore-scale net
A.S. Bagci, SPE, S. Olushola, and E. Mackay, SPE, Heriot-Watt University Abstract Thermal recovery methods involving stea
                                                                              Abstract Increased lifetime of chemical treatment
H.K. Kotlar, SPE, L.-E. Hauge, SPE, K. Solbakken, A. Gangstad, B. Gjersvold, and L.M. Sivertsen, Statoil ASA
                                                                              Abstract
Jose Umberto A. Borges/Petrobras; Mahmoud Jamiolahmady/Heriot-Watt University The increasing global energy demand ris
Jamiolahmady M., Sohrabi M., and Shaun Ireland, Heriot-Watt University Abstract Flow around the wellbore of gas-condens
                                                                              Abstract This paper discusses the method on how
Fuming Zhang, Cairui Shao, Hongqi Li, and Cuihua Jiao, China U. of Petroleum, Hongtao Liu, and Yuanjiang Li, DaQing Oilfield
                                                                              Abstract
A. Suat Bagci, Heriot-Watt U., and Ceylan Yildirim Akbas, Middle East Technical U. This study focuses on the evaluation of fo
M. Jamiolahmady, A. Danesh, D.H. Tehrani, and M. Sohrabi, Heriot-Watt U. Summary It has been demonstrated first by this la
                                                                              Abstract The saturation-height function
Mahmound Jamiolahmady, Mehran Sohrabi, and Mohammed Tafat, Inst. of Petroleum Engineering, Heriot-Watt U. greatly imp
Mansour A. Al-Shafei and Taha M. Okasha, Saudi Aramco                         Abstract The wettability of rocks is of critical impor
                                                                              Summary Addax SPE, and O. Aubert, Addax Pet
B.A. Stenger, SPE, F. Guinot, SPE, C. Clauss, SPE, J. Otevwemerhuere, SPE, T.E. Ezeukwu,Petroleum’s operated Okwo
                                                                              Abstract Intelligent completion have been proven
Fajhan H. Almutairi, Kuwait Institute for Scientific Research/Heriot-Watt University; David R. Davies, Heriot-Watt University; and
                                                                              Abstract Jos� Ismael Salazar Hern�ndez, Pe
Sandy Williams, SPE, ALP Ltd., and Rafael Rozo, SPE, Fernando P�rez Aya, and The Orito field located in the South of Col
                                                                              Corporation
A. Suat Bagci, Heriot-Watt University, and Bulent Ozturk, Turkish Petroleum Abstract Underground gas storage is a common ac
G.H. Aggrey and D.R. Davies, Heriot-Watt University                           Abstract Long term equipment reliability frequently
                                                                              U.; �. Tesaker and R. Straub, essential for both
F.T. Alkhelaiwi, Heriot-Watt U. and Saudi Aramco; D.R. Davies, Heriot-Watt 1. Abstract Realistic modelling is Statoil ASA; and R
                                                                              Abstract Re-injection of produced water Researc
Mohammad A.J. Ali and Peter K. Currie, Delft U. of Technology, and Mohammad J. Salman, Kuwait Inst. for Scientificis of incre
                                                                              Abstract Well performance prediction is a key Petr
V.M. Birchenko and V.V. Demyanov, SPE, Heriot-Watt University; M.R. Konopczynski, SPE, WellDynamics (a Halliburton Com
                                                                              Abstract Heuristic Heriot-Watt U.
N.Y. Guerra, SPE, Empresa Colombiana de Petroleos, Ecopetrol, and R. Narayanasamy, SPE, technique may be called as an
                                                                              Abstract
R. Narayanasamy, SPE, D.R. Davies, SPE, and J.M. Somerville, SPE, Heriot Watt U. One of major field development decision
                                                                              Summary Time-lapse Mike Christie, SPE, Heriot-W
Karl D. Stephen, SPE, Heriot-Watt U.; Juan Soldo, SPE, RepsolYpf; and Colin MacBeth, SPE, and (or 4D) seismic is increasing
Karl D. Stephen, SPE, and Colin MacBeth, Heriot-Watt University               Summary We have developed a method in which
                                                                              Abstract History matching University, Edinburgh,
L. Mohamed, SPE, M. Christie, SPE, and V. Demyanov, Institute of Petroleum Engineering, Heriot-Wattand uncertainty quantifi
                                                                              Abstract This paper introduces University, Edinbur
Yasin Hajizadeh, Mike Christie, and Vasily Demyanov; SPE, Institute of Petroleum Engineering, Heriot Watt a new stochastic ap
                                                                              Abstract Seismic history matching is the process o
F. Sedighi, Heriot-Watt University and K. D. Stephen, SPE, Heriot-Watt University
                                                                              Abstract Reservoir University; and C. MacBeth, H
N.R. Edris, Heriot-Watt University; K.D. Stephen, Heriot-Watt University; A. Shams, Heriot-Wattmanagement may be improved
                                                                              Abstract Realistic Christie, models are U.
M. Rotondi, G. Nicotra, A. Godi, and F.M. Contento, Eni E&P; M.J. Blunt, Imperial C.; and M.A. reservoir Heriot-Watt essential f
                                                                              Abstract A novel stochastic framework is describe
Faruk O. Alpak, SPE, Florian van Kats, and Detlef Hohl, SPE, Shell International Exploration and Production Inc.
                                                                              Abstract Edinburgh multiple history-matched rese
D. ErbaÅŸ, Heriot-Watt U. and BP Exploration; and M.A. Christie, Heriot-Watt U. and Generating Collaborative of Subsurface S
K.M. Muradov and D.R. Davies, SPE, Heriot-Watt University, Edinburgh, U.K.    Abstract Advanced completions using technologies
Karl D. Stephen, Asghar Shams, and Colin MacBeth, Heriot-Watt U.              Abstract In seismic history matching we perform a
Gataullin Timur / TNNC                                                        Abstract Many methods of fractured well represent
                                                                              PETRONAS
Abdolrahim Ataei, Nasir Darman, Ooi Kok Liang, and Rahim Masoudi, SPE, Abstract Baram field is one of the nine major oil fie
                                                                              Abstract Due to the lack of Christie, SPE, Heriot-W
H. Okano, SPE, Heriot-Watt U. and Japan Oil, Gas and Metals Natl. Corp.; G.E. Pickup, SPE, and M.A. data a reservoir engin
C.A. Estrada, SPE, and A. Settari, SPE, U. of Calgary                         Abstract Well test analysis techniques use variati
M. Jamiolahmady, A. Danesh, M. Sohrabi, and R. Ataei, Heriot-Watt U.          Summary The most crucial region with regard to a
                                                                              Abstract Inflow profiling
Fajhan H. Almutairi, Kuwait Institute for Scientific Research, David R. Davies, Heriot-Watt University has proved to be a major a
K.M. Muradov and D.R. Davies, SPE, Heriot-Watt University, Edinburgh, U.K.    Abstract Intelligent well system technology enables
                                                                              Summary This paper presents Larry procedure to
Ali A. Yousef, SPE, and Pablo Gentil, SPE, U. of Texas at Austin; Jerry L. Jensen, SPE, Texas A&M U.; anda new W. Lake, SP
Mahdiyar H., Jamiolahmadi M. and Sohrabi M., Heriot-Watt University           Abstract Fracturing is one of the most common we
                                                                              Abstract Modelling flow around horizontal wells (HW
Panteha Ghahri, Mahmoud Jamiolahmady, and Mehran Sohrabi, Heriot Watt University
                                                                              Summary Phase Flow in R. Helmig,Porous Media
                                                                                           Niessner and Fractured and simulati
S. Geiger, SPE, Heriot-Watt University; S. Matth�i, SPE, University of Leoben; and J.Discrete-fracture modelingUniversity of
A.S. Bagci, SPE, Heriot-Watt U.                                              ABSTRACT Experimental studies present the eff
                                                                             Abstract Edinburgh; S. able to SPE, Montan Univ
S. Geiger, SPE, Heriot-Watt University; Q. Huangfu and�F. Reid, The University of We have beenMatthai, solve a reservoir s
Philip S. Ringrose, StatoilHydro ASA                                                     Gross Myth
                                                                             Summary Reservoir-modeling practice has develo
Azhar Al Kindi, Shell                                                        Abstract In comparison to on-shore or shallow wat
Z. Shi-Yi, Heriot-Watt U., and N. Marius, Shell U.K. Ltd.                    Abstract Well productivity impairment due to two-
M. O. Salazar, U. Central de Venezuela, and J. R. Villa, PDVSA Intevep       Abstract Upscaling reservoir properties for reservo
                                                                             Summary A first attempt has been made to predic
D.S. Svirsky, SPE, M.I.J. van Dijke, and K.S. Sorbie, SPE, Heriot-Watt University        Phase Data
                                                                             Abstract University; R. Ward, a practical attempt a
I. Bondino, SPE, TOTAL E&P UK Ltd; C.C. Ezeuko and S.R. McDougall, Heriot-Watt This work constitutesTOTAL E&P UK Ltd;
                                                                              U.; and Although experimental
I. Bondino, Total E&P U.K.; J. Long, Total S.A.; S.R. McDougall, Heriot-WattAbstract G. Hamon, Total S.A. work for solution g
                                                                             Abstract In this
M.I.J. van Dijke, M. Lorentzen, SPE, M. Sohrabi, SPE, and K.S. Sorbie, SPE, Heriot-Watt U. paper the simulation is described o
Peter Obidike, Shell Nigeria Exploration and Production Company              Abstract Reservoir engineering tools applied in de
Tharwat Fawzy, Schlumberger, and Eric Mackay, Heriot-Watt University         Abstract Inorganic scales precipitate in oilfield syst
Sergey Kh. Kurelenkov and Andrey V. Ryazanov, SPE, Tomsk Polytechnic U.      Abstract In this work we present the comparative a
Mohammad Ahmadi, Heriot Watt University                                      Abstract Numerical simulation of thermal recovery
                                                                             Summary Geologists often generate
Pinggang Zhang, SPE, BP Exploration; and Gillian Pickup, SPE, and Mike Christie, SPE, Heriot-Watt University highly hetero
                                                                             Abstract Production below bubblepoint will of Berg
A.N. Nyre, CIPR and IFT/University of Bergen; S.R. McDougall, Heriot-Watt University; and A. Skauge, CIPR/University genera
                                                                             Abstract and Ian Main and Lun Li, and Edinburgh
Kes Heffer, Reservoir Dynamics Ltd.; Xing Zhang and Nick Koutsabeloulis, VIPS Ltd.;Long-range stress-relatedU. of fault-relate
Anthony O. Uwaga, SPE, Centrica Energy                                       Abstract Diagenesis is defined as any chemical p
                                                                             Abstract During the primary production of fractured
A. Kazemi, SPE, Heriot Watt University, and M. Jamialahmadi, Petroleum University of Technology
                                                                             Summary We investigate oil recovery
Y.M. Al-Wahaibi, SPE, Sultan Qaboos U., and A.H. Muggeridge, SPE, and C.A. Grattoni, SPE, Imperial College from multico
                                                                             Abstract Gas injection and water-alternating-gas (
I.S. Ivanova, Rosneftneft, and K.S. Sorbie and M.I.J. van Dijke, Heriot-Watt U.          Gas (WAG) Processes
Aine M. Fitzgerald and Laurence G. Cowie, BP                                 Abstract In recent years BP has moved into reserv
                                                                             Abstract Projected increases in Algerian hydrocarb
Salim Bachiri, Sonatach, Ahmed Dahroug, SPE, Schlumberger, and S.Y. Zheng, SPE, Heriott Watt University
Simon James, SPE, and Linda Boukhelifa, SPE, Schlumberger                    Summary Over the past 10 years several papers
                                                                             Abstract The common wisdom Robin Westerman
Mohammed J. Alshakhs, SPE, Heriot-Watt University & Saudi Aramco; Erling Riis, University of Strathclyde;is that gravity meth
                                                                             Abstract An essential part
G.H. Aggrey and D.R. Davies, Heriot-Watt U., and A. Ajayi and M. Konopczynski, WellDynamics Inc. of the process to determ
G.H. Aggrey and D.R. Davies, Heriot-Watt University                          Abstract Permanent downhole sensors are extens
                                                                             Summary Flow Riboud fluid type (phase) are two
M. Webster, SPE, and S. Richardson, SPE, BP Exploration; C. Gabard-Cuoq, Schlumberger rate andProduct Center; J.B. Fitzg
Oleg Ishkov, Eric Mackay, and Ken Sorbie, Heriot-Watt University             Abstract Waterflooding is a very common method
                                                                             Abstract One
Shi-Yi Zheng, SPE, and X.G. Li, Institute of Petroleum Engineering, Heriot-Watt University of the key objectives doing well testi
G.H. Aggrey and D.R. Davies, Heriot-Watt U., and L.T. Skarsholt, Statoil ASA 1.������ Abstract Increasing use
K.M. Muradov and D.R. Davies, SPE, Heriot-Watt University, Edinburgh, UKAbstract Intelligent well system technology enables
Gary S. Swindell, Consultant                                                 Abstract Coalbed methane has become a significa
                                                                             Abstract Effective Edinburgh, during well start-up
D.K. Olowoleru, K.M. Muradov, F.T. Al-Khelaiwi and D.R. Davies; SPE, Heriot-Watt University, well cleanupU.K.
                                                                             Abstract Advances (from conventional wells to Da
F.T. Al-Khelaiwi, SPE, and V.M. Birchenko, SPE, Heriot-Watt University; M.R. Konopczynski, SPE, WellDynamics; and D.R. ho
Guillermo Pitrelli and Maximiliano Giraldo, Repsol-YPF                       Abstract Concepts on well multiple zone completio
Yang Qing and D.R. Davies, Heriot Watt University                            Abstract This paper presents an advanced control
                                                                             Summary Relatively University
D.R. Davies, SPE, R. Narayanasamy, SPE, B. Kristensen, and J.M. Somerville, SPE, Heriot-Watt few field installations of a dua
                                                                             Summary This
C.L. Cipolla, Pinnacle Technologies; and K.K. Hansen and W.R. Ginty, Amerada Hess A/S paper details the results for 33 pro
                                                                             Summary The primary purpose of surfactants CE
J. Paktinat, J.A. Pinkhouse, and C. Williams, Universal Well Services Inc.; G.A. Clark, Phillips Production; and G.S. Penny, use
                                                                             Abstract An optimized design for hydraulic fracturi
H. Mahdiyar, Shiraz University, and M. Jamiolahmady and M. Sohrabi, Heriot-Watt University
                                                                             Summary SIAM; Alexey G. Zagurenko, SPE, Ros
Andrey V. Dedurin, TNK-BP; Vadim A. Majar, Gazpromneft; Andrey A. Voronkov, SPE, Non-Darcy and multiphase flow effects
                                                                             Summary Most existing production of waxy oils oc
                                                                                         Oil Reservoir in India
Josef Shaoul, SPE, and Winston Spitzer, SPE, Pinnacle Technologies, and Michael Ross, Stuart Wheaton , SPE, Paul Maylan
                                                                             Abstract The performance
M. Jamiolahmady, D. Ganesh, M. Sohrabi, and A. Danesh, Petroleum Engineering Inst., Heriot-Watt U. of fracturing treatments
P. Ghahri, M. Jamiolahmady, and M. Sohrabi, Heriot Watt University           Abstract In tight gas reservoirs gas well production
H. Mahdiyar, M. Jamiolahmady, and A. Danesh, Heriot-Watt U.                  Abstract Hydraulic fracturing is one of the most com
M. Jamiolahmady, M. Sohrabi, and Shaun Ireland, Heriot-Watt University Abstract Hydraulic fracturing is one of the most com
                                                                             Abstract A&M U.
A. Bond, Pioneer Natural Resources Alaska Inc., and D. Zhu and R. Kamkom, Texas Horizontal wells provide extended contact
                                                                             Abstract Most of the
G.A. Carvajal, E. Arreaza, C. Gonz�lez, C. Cesin, M. Fern�ndez, and J. Bello, PDVSA E&P cases in gas condensate well
                                                                             Abstract Horizontal and
F.T. Alkhelaiwi, Heriot-Watt University and Saudi Aramco, and D.R. Davies, Heriot-Watt University multilateral completions ar
F. Ebadi, SPE, and D.R. Davies, SPE, Heriot-Watt U.                          Abstract Intelligent Well (IW) Technology improve
F. Ebadi, SPE, and D.R. Davies, SPE, Heriot-Watt U.                          Abstract Intelligent Well (IW) Technology combin
                                                                           Abstract J.A.T. Gomes, and V.C. Amorim, Petrobr
P.G. Bedrikovetsky and R.P.S. Monteiro, North Fluminense State U., and J.S. Daher, The system where sulphate scaling dama
                                                                           Abstract Previous work has derived an and F. Pa
P. Bedrikovetsky, SPE, North Fluminense State U. (LENEP/UENF); E. Mackay, SPE, Herriot-Watt U.; R.P. Monteiro analytical
                                                                           Abstract During recent years interest in underbala
C. Nguyen, J.M. Somerville, SPE, and B.G.D. Smart, SPE, Heriot-Watt University
                                                                           Abstract Horizontal Open Hole Gravel and (HOHG
B.V. Loureiro, UCL - Faculdade do Centro Leste, J.V.M. de Magalh�es, SPE, M.V.D. Ferreira, A. Calderon, SPEPack A.L. Ma
                                                                           Abstract Horizontal SPE, and A. Calderon, SPE,
B.V. Loureiro, UCL-Faculdade do Centro Leste, and�J.V.M. de Magalhaes, SPE, A.L. Martins,Open hole gravel pack is the c
J.D. Holmes and M.P. Tolan, BGEPIL, and C. Hale, BJ Services               Abstract The stacked sands of the South Tapti fie
                                                                           Summary Factors Peter Robinson, leading to san
Hans Vaziri, BP America; Robbie Allam, Gordon Kidd, Clive Bennett, and Trevor Grose, BP plc;and mechanisms BP Australia;
                                                                           Summary Acid-fracturing SPE, H.M. Al-Marri, SPE
H.A. Nasr-El-Din, SPE, A.A. Al-Zahrani, SPE, F.O. Garzon, SPE, C.A.F. Giraldo, SPE, I.M. Al-Hakami, treatments are used com
                                                                           Abstract SPE, Baker Petrolite
O. Vazquez, M. Singleton, SPE, and K.S. Sorbie, SPE, Heriot-Watt U., and R. Weare,This paper describes a sensitivity study o
George Aggrey* and David Davies, Heriot-Watt University, UK                Abstract Value addition via real-time reservoir mon
Mark F. Barrilleaux and Thomas A. Boyd, BP                                 Abstract Smart completions that can remotely con
M. Jamiolahmady, P. Ghahri, O.E. Victor, and A. Danesh, Heriot-Watt U.     Abstract: The performance of a horizontal (highly s
                                                                           Abstract Interpreting pressure transient tests in co
Akshay Sahni, SPE, Ken Kelsch, SPE, Hathaiporn Samorn, and Chalatpon Boonmeelapprasert, SPE, Chevron
Zheng Shi-Yi, SPE, and Wang Fei, Heriot-Watt University                    Abstract Permanent Down-hole Gauge (PDG) has
                                                                           Abstract
Yao Jun, China University of Petroleum, and Zheng Shiyi, SPE, Heriot-Watt UniversityNumerical well testing technique has bee
Zheng Shi-Yi, SPE, Heriot-Watt U.                                          Abstract Numerical well testing started in about a
                                                                           Abstract Before the early eighties Engineering of
Victor T. Biu, Total E&P Nigeria, Emmanuel O. Biu, University of Port Harcourt, and Mike O. Onyekonwu, Laser identification Co
                                                                           Abstract Gas London
A.C. Gringarten, M. Bozorgzadeh, S. Daungkaew, and A. Hashemi, SPE, Imperial College,condensate reservoirs exhibit a com
                                                                           Abstract Pressure transient
Pooyan Karami and Abolfazl Hashemi Petropars Oil and Gas Company National Iranian Oil Company testing is one of the m
Zheng Shiyi, SPE, and Wang Fei; Heriot-Watt University; Edinburgh; ScotlandAbstract Traditionally well testing is completed by a
Zheng Shi-Yi and Li Xiao-Gang, Heriot-Watt U.                              Abstract Reservoir pressure monitoring during its p
                                                                           Summary Relative permeabilities are fundamenta
John D. Matthews, SPE, Jonathan N. Carter, SPE, Robert W. Zimmerman, SPE, Imperial College, London
 ture and storage (CCS) is capable of reducing atmospheric emissions of greenhouse gases from coal or gas fired power plants. The upward
 n is increasingly considered as having potential applications as a possible enhanced oil recovery (EOR) process for oil reservoirs. However
  provides a summary and a guide of the Enhanced Oil Recovery (EOR) technologies initiated in the North Sea in their period from 1975 until
 tabase on critical and subcritical flow through orifice- and cage-type chokes have been obtained in the Multiphase Flow Loop (MPFL) of Nors
predictions of heat loss and temperature profile in oil- and gas-production pipelines are essential to designing and evaluating pipeline operatio
er production systems extreme pressure and temperature conditions multipart sub-sea networks complex reservoir characteristics and var
se an improved procedure for measuring acid numbers. Major changes include spiking crude oil samples and blank solutions with a known a
 characterization and asset management require comprehensive information about formation fluids. Obtaining this information at all stages o
 eanup During Wireline Formation Tester Sampling
   Weight Alkanes
 et-transform (WT) method has been applied to logs to extract reservoir-fluid information. In addition to the time (depth)/frequency analysis ge
 drilling fluids are used extensively in drilling activities worldwide. During the drilling process because of overbalance pressure in the mud col
nd multi-lateral wells allow oil and gas companies to maximise contact with reservoir quality rock in either a single reservoir or multiple reserv
 amage created during drilling or workover operations significantly reduces the performance of many wells. Long horizontal and multilateral w
 uction is a major issue facing many operators in the mature southern North Sea (SNS) gas fields. Historically sand-control completion decis
 evelopment of more and more subsea fields the challenge for scale-inhibitor squeeze treatments is to reduce intervention frequency by exte
 ld deposits from distinct geographical regions were analysed using a wide range of analytical techniques viz. for cation composition (EDAX)
 ontrol challenges for a large North Sea carbonate reservoir are reviewed in this paper.� Field data from a reservoir where the process of s
s oil fields in Western Siberia producing fluids from a number of wells via Electric Submersible Pumps (ESP’s). While production rates ar
nvestigates the application of halite inhibitors and the mechanisms associated with salt formation and inhibition. Several new chemistries (two
 on of seawater into oil-bearing reservoirs to maintain reservoir pressure and improve secondary recovery is a well-established mature opera
n low sulphate seawater as sole protection against sulphate scale may be discomforting to some operators when such expensive subsea we
r describes results from a series of comparative corefloods and static compatibility tests examining the differences in laboratory-test procedu
cales have over recent years become increasingly common in many oil and gas producing regions. The main sulphide scales are iron zinc a
biomimetics is expanding in engineering and refers to the mimicking of natural system functionality in technological systems. The most well k
eployment of distributed temperature sensor (DTS) systems in the oil and gas E&P industry provided the engineers with large amount of real-
  describes the development and application of a two-phase multi-component multi-layer radial mathematical model capable of simulating
 eeze treatments have been regularly carried out to prevent both sulphate and carbonate scale depositions in a North Sea field since 1990s.
on of iron sulfide mineral scale formation in oil and gas production is notoriously difficult. High concentrations of scale inhibitors are always ne
  ears a number of nonaqueous delivery systems for scale inhibitors (SI) have been developed that are designed to be applied as low-damag
   results are presented on the general mechanisms by which scale inhibitors (SIs) are retained within porous media. There is a generally acc
  work (SPE 87447) the effect of pH on phosphonate/carbonate interaction was studied by performing variable pH core floods in short outcro
  oil and particularly gas production may be achieved in waterflooded reservoirs by stopping further water injection and depressurizing the res
  hallenge facing the oil industry is to reduce development costs while accelerating recovery while maximising reserves. One of the key enabl
sulphate rich seawater into reservoirs with formation brines rich in calcium barium or strontium may result in the precipitation of sulphate sca
ommon method for preventing downhole scale formation is by applying a scale inhibitor squeeze treatment. In this process a scale inhibitor s
a- and production waters during waterflooding of offshore oil reservoirs results in reaction of barium and sulphate ions causing precipitation o
aling with consequent deposit formation and wellbore damage is a well-known phenomenon that occurs during waterflooding when mixing o
  escribes the development of a two-phase near-wellbore simulator to predict the impact on squeeze lifetime of the overflush fluid type. In the
ncreased cost of scale management in subsea compared to platform or onshore fields and because of the more limited opportunities for inte
  mmon method for preventing scale formation is by applying scale inhibitor squeeze treatments. In this process a scale inhibitor solution is in
 tion of mineral scale (carbonate/sulfate/sulfide) within the near wellbore production tubing and topside process equipment has presented a
  ected seawater with formation brines may cause scale precipitation at production wells and surface facilities but does not generally cause s
 formations are often very heterogeneous and fluid flow is strongly determined by their permeability structure. Thus when a scale inhibitor (S
4 scaling is a chronicle disaster in waterflood projects with incompatible injected and formation waters. This is usually due to precipitation of
presents field results from scale squeeze treatments carried out on platform and subsea horizontal wells from a oilfield in the UK sector of th
  mmon method for preventing downhole scale formation is by applying a scale inhibitor (SI) squeeze treatment. In this process a SI solution
  ompares the scale inhibition efficiencies of a phosphate ester two phosphonate and two polymer chemistries in the presence of ferrous iron
sition either in the formation or in the production facilities is a challenging problem in the petroleum industry. Scale mitigation and prevention
  mmon method for preventing scale formation is by applying a scale inhibitor squeeze treatment. In this process a scale inhibitor solution is i
an be an immediate result of stress redistribution following the removal of the rock mass. Due to the fine-grained nature low permeability and
    oil and gas fields seawater injection is used for reservoir pressure support. Formation water and seawater mixing may lead to sulphate sca
 tion presents a flow assurance challenge to the oil and gas industry. Scale inhibitor squeeze treatments are the most common method used
 lly assumed that scale inhibitor squeeze treatments in production wells are displaced radially into the formation since it is normal to pump t
  m stripping is commonly observed in sandstone reservoirs where seawater mixes with formation water that may be rich in calcium strontium
  escribes a two-year effort by ExxonMobil and PETRONAS to develop a simulation model of a complex Seligi group J-sand a major reservoi
r describes the planning for implementation of and results generated by a real-time field surveillance and well services management system
s North Slope reservoirs contain a massive heavy oil resource. There has been some success producing the less viscous crudes in the West
    vertically-oriented heavy oil depletion experiments have been conducted in recent years in an attempt to investigate the impact of gravitation
 ars the use of pore-scale network models has greatly advanced our understanding of solution gas drive processes by accounting for the com
covery methods involving steam injection have long been considered as an effective means of extracting heavy oil resources. In addition the
 ifetime of chemical treatments is an important achievement both from an economical - field productivity issue as well as from an environmen
 ng global energy demand rising energy prices and declining conventional gas reserves all call for increasing exploitation of gas reserves fro
    the wellbore of gas-condensate systems when pressure drops below dew point is controlled by complex interaction of capillary viscous an
  iscusses the method on how to subdivide the reservoir into zones based on flow-units. Based on the thought of “inner homogeneity in flo
ocuses on the evaluation of formation permeability for a carbonate reservoir from well logs and core data using the concept of flow units. Cha
n demonstrated first by this laboratory and subsequently by other researchers that the gas and condensate relative permeability can increas
on-height function greatly impacts reserve calculations and is used by geologists or reservoir engineers to predict the saturation in the reserv
 lity of rocks is of critical importance in understanding reservoir dynamics. Several studies of wettability evaluation on Saudi Aramco reservoir
 roleum’s operated Okwori oil field offshore Nigeria illustrated the benefits of reviving shelved projects because of an insufficient return
ompletion have been proven to be an efficient reservoir management tool with rapid deployment in various reservoirs environments value h
  ld located in the South of Colombia near the Ecuadorian border has been in production since 1967 and is operated by the Colombian state
d gas storage is a common activitity in countries with major transport and distribution gas pipeline infrastructures which allows to efficiently r
equipment reliability frequently controls the Value created by Intelligent Well Technology. One of the barriers to intelligent well deployment is t
modelling is essential for both the planning and the optimal operation of Oil and Gas Fields. Such a model for modern well or field developme
    of produced water is of increasing importance as water cuts continue to increase worldwide. It provides an environmentally acceptable solu
mance prediction is a key Petroleum Engineering task. However large discrepancies between Petroleum Engineering models and reality still
chnique may be called as an “intelligent guess which reduces the search for the right answer of a usually complex problem. Such techni
 or field development decision is choosing the number of wells required to efficiently drain an oil or gas reservoir. It is an interactive process
e (or 4D) seismic is increasingly being used as a qualitative description of reservoir behavior for management and decision-making purposes
developed a method in which spatial and dynamic information offered by time-lapse or 4D seismic surveys is used in history matching of res
 ching and uncertainty quantification are two important research topics in reservoir simulation currently.� In the Bayesian approach we sta
ntroduces a new stochastic approach for automatic history matching based on a continuous ant colony optimization algorithm. Ant colony opt
 ory matching is the process of modifying a reservoir simulation model to reproduce the observed production data in addition to information ga
 anagement may be improved if the present state of the field is known and if changes may be predicted. The former�requires information a
servoir models are essential for efficient field management and accurate forecasting of hydrocarbon production. Such models based on the
chastic framework is described that facilities automatic history matching and uncertainty quantification workflows. The underlying algorithm o
multiple history-matched reservoir models by stochastic sampling to quantify the uncertainty in oil recovery predictions has recently aroused i
ompletions using technologies such as Inflow Control Devices or Interval Control Valves are successfully optimising oil and gas production. T
  story matching we perform a computer assisted history match to conventional production data but also include the spatio-temporal informat
 ds of fractured well representation in simulation model are known. Some of them are too complex to use in large simulation model where mo
   is one of the nine major oil fields in Baram Delta Operation (BDO) area which is located 28 km northwest of Lutong in the offshore area of M
 lack of data a reservoir engineer needs to calibrate unknown petrophysical parameters based on production history. However because the
nalysis techniques use variations of the pseudopressure concept to account for multiphase effects due to condensate drop-out in near-well r
 crucial region with regard to affecting well productivity is the perforated region. Considerable effort has been directed to study this subject ma
ng has proved to be a major application of Distributed Temperature Sensor (DTS) systems. The real-time downhole temperature data is ana
ell system technology enables downhole monitoring and zonal fluid production control in real time. This allows well control decisions to be im
r presents a new procedure to quantify communication between vertical wells in a reservoir on the basis of fluctuations in production and inje
    one of the most common well stimulation techniques especially for tight gas-condensate reservoirs. Gas condensate flow around hydraulica
  w around horizontal wells (HWs) is a complex and challenging task due to the three-dimensional (3D) nature of the flow including the perme
ow in Fractured Porous Media
mental studies present the effect of horizontal and vertical fractures and well configurations on the SAGD process in a three-dimensional mo
een able to solve a reservoir simulation problem which was previously thought of as intractable:�We simulated multiphase displacement in

on to on-shore or shallow water fields there is limited experience in the industry for deepwater well performance prediction. The developmen
ctivity impairment due to two-phase flow in the near well region is a major concern in gas condensate reservoirs. There usually exhibit comp
 servoir properties for reservoir simulation is one of the most important steps in the workflow for building reservoir models. Upscaling allows t

onstitutes a practical attempt at addressing issues surrounding depletion gas-oil relative permeabilities in the case of a near-critical oil by usin
perimental work for solution gas drive processes is routinely carried out and interpreted for the purpose of defining critical gas saturations an
 r the simulation is described of water-alternating-gas injection (WAG) flood cycles in 2-D etched glass mixed-wet micromodels using a 3-D p
 ngineering tools applied in development planning or operations support ranges from material balance calculations to simulation studies. The
 ales precipitate in oilfield systems - downhole in the reservoir in the production flow tubing and in surface facilities - because of thermodyna
  we present the comparative analysis of uniform and non-unifrom upgridding techniques in combination with upscaling methods currently inc
 mulation of thermal recovery processes like steam injection often involves localized phenomena such as saturation and temperature fronts d
   often generate highly heterogeneous descriptions of reservoirs containing complex structures which are likely to give rise to very tortuous f
below bubblepoint will generate free gas first as discontinuous gas up to the critical gas saturation and thereafter free or mobile gas. The lev
  stress-related and fault-related characteristics of correlations in fluctuations in flow-rates are explained conceptually in the context of the lith
 is defined as any chemical physical or biological change undergone by a sediment (rock) after its initial deposition and during and after its lit
 rimary production of fractured reservoir most of oil is produced from fractures and a lot of oil remains in matrix. Trapped oil in the matrix can
 gate oil recovery from multicontact miscible (MCM) gas injection into homogeneous and crossbedded porous media using a combination of
G) Processes
ars BP has moved into reservoirs in deep water subsea projects where sea water flooding is required for reserves recovery. The introduction
creases in Algerian hydrocarbon production will come in part from more complex reservoirs. In Algeria conventional quality reservoirs (>1 m
 ast 10 years several papers have been published discussing the long-term mechanical durability of the cement sheath. The customary proc
n wisdom is that gravity methods have limited application in the oil industry although they have long been available. The main use of gravity h
  part of the process to determine the value of advanced wells and fields is the explicit inclusion of the reliability of the various measurement s
 downhole sensors are extensively used in Intelligent Well completions. Typically their numbers increase with the number of controllable zon
and fluid type (phase) are two of the most fundamental parameters needed to characterize well performance. Traditional methods of estimat
 ng is a very common method of oil displacement and pressure support.� One particular problem that may arise after injection water (IW) b
key objectives doing well testing is to derive effective reservoir properties such as permeability to provide input for reservoir simulation. Trad
 � Abstract Increasing use of advanced (intelligent) completions has provided the facility for real time reservoir monitoring through use of p
ell system technology enables continuous downhole monitoring and zonal production control. Knowledge of zonal multiphase rates in real tim
ethane has become a significant source of U.S. natural gas production contributing 9% of the country’s supply and 10% of its proved res
  l cleanup during well start-up ensures efficient formation damage removal and maximises the resulting well production potential. Horizontal w
 from conventional wells to horizontal and then multi-lateral) in well architecture for maximising reservoir contact have been paralleled by adv
n well multiple zone completion systems applied in marginal wells in Los Perales Oil Field located in the Gulf of San Jorge Basin Santa Cruz
presents an advanced control method for online regulation of downhole Interval Control Valves (ICVs) to achieve optimal production via chok
 few field installations of a dual-electric submersible-pump (DESP) completion have been reported. In general the purpose of the second pum
r details the results for 33 propped-fracture treatments in low-porosity zones in the South Arne (SA) field Danish North Sea. To date seven h
 ry purpose of surfactants used in stimulating sandstone reservoirs is to reduce surface tension and contact angle and provide leakoff control
 d design for hydraulic fracturing is of great importance especially with the growing demand for this method as a means of production enhanc
y and multiphase flow effects in hydraulic fractures have been well documented in the last several years. The pressure losses caused by thes

 ance of fracturing treatments has been an issue for over fifty years and considerable effort has been devoted to improve its prediction perfor
 eservoirs gas well production after hydraulic fracturing (HF) is often greatly impaired through various mechanisms by invasion of fracturing
 cturing is one of the most common well stimulation techniques. Hence considerable amount of efforts has been devoted to study their perfo
 cturing is one of the most common well stimulation techniques for gas-condensate reservoirs. In recent years considerable effort has been d
ells provide extended contact with the reservoir and have unique advantages over vertical wells in many applications. As nominally horizonta
cases in gas condensate wells produce below dew point pressure generating a saturated zone in liquid that blockage the gas flow efficiency t
nd multilateral completions are a proven superior development option compared to conventional solutions in many reservoir situations. How
Well (IW) Technology improves well and field performance management by combining zonal production control using Interval Control Valves
Well (IW) Technology combines zonal production control using Interval Control Valves (ICVs) together with installation of appropriate flow m
 where sulphate scaling damage occurs is determined by two governing parameters: the kinetics coefficient characterising the velocity of che
 ork has derived an analytical model for simultaneous flow of incompatible waters in porous media with sulphate salt precipitation determine
nt years interest in underbalanced drilling (UBD) has grown rapidly. As a drilling technique it has gained acceptance because it provides a m
 pen Hole Gravel Pack (HOHGP) is the conventional sand control technique for offshore non consolidated reservoirs in Brazil. Gravel pack p
Open hole gravel pack is the conventional sand control technique for offshore non consolidated reservoirs in Brazil. Gravel pack placement re
d sands of the South Tapti field have presented completion challenges from field start-up in 1997 to the present-day. A large part of these ch
nd mechanisms leading to sanding are described within an integrated-rock and soil-mechanics framework.� While the conventional sandin
uring treatments are used commonly to enhance the productivity of carbonate formations with low-permeability zones. Various forms of hydro
describes a sensitivity study on the main factors affecting a polymeric Relative Permeability Modifier (RPM) treatment in the near wellbore re
on via real-time reservoir monitoring and optimisation is one of the main drivers for the increasing implementation of intelligent (I-)well comple
pletions that can remotely control the flow from multiple layers of a reservoir interval were introduced in the mid 1990’s. Downhole flow-co
mance of a horizontal (highly slanted) well (HW) or a slanted well (SW) is generally believed to be better than that of a vertical well (VW) due
 pressure transient tests in complex faulted and stratigraphic environments can be difficult. In fluvial depositional environments where sand c
 Down-hole Gauge (PDG) has been widely installed in the oilfield around the world in recent years. One of the challenges in analyzing long-te
well testing technique has been regarded as the future of well testing in tackling non-linear heterogeneous reservoir testing problems. Finite
well testing started in about a decade ago. The technique was developed to tackle well testing problems in heterogeneous reservoirs. Integra
early eighties identification of flow regime has been a difficult task for reservoir engineer and welltest analyst until the emergence of the deriv
nsate reservoirs exhibit a complex behavior when wells are produced below the dew point due to the existence of a two-fluid system reservo
 nsient testing is one of the most useful reservoir description methods. It provides valuable information about the reservoir/well-bore characte
 well testing is completed by analysing transient pressure due to constant production rate. However in the oil industry practice engineer ofte
 essure monitoring during its production life is to evaluate its performance to ensure the effective extraction of hydrocarbon from the reservoir
ermeabilities are fundamental to any assessment of reserves and reservoir management. When measurements on core samples are availab
 r gas fired power plants. The upward buoyancy of dense phase carbon dioxide (CO2) in deep reservoirs means that sites need to be chosen
                                                   OnePetro
  process for oil reservoirs. However poor sweep efficiency has been a problem in many CO2 floods and hence the injection strategies like W
 th Sea in their period from 1975 until today. The five EOR technologies which have been initiated in the North Sea were hydrocarbon miscib
Multiphase Flow Loop (MPFL) of Norsk Hydro Oil and Gas R&D Center in Porsgrunn Norway. This work is an extension of the studies perfor
gning and evaluating pipeline operations. Although some sophisticated computer packages are available for such purposes their accuracies
 lex reservoir characteristics and various fluid phases flowing from the reservoir rock to the surface could promote production interruption du
 s and blank solutions with a known amount of stearic acid to force a clear titration endpoint replacing potassium hydroxide with tetrabutyl am
aining this information at all stages of the exploration and development cycle is essential for field planning and operation. Traditionally fluid in


 he time (depth)/frequency analysis generally performed by the wavelet method we also have performed energy spectral analysis for time/fre
                                                                                       formation.
 overbalance pressure in the mud column the filtrate of oil-based mud invades the OnePetro This hydrocarbon-based filtrate mixes with the
  r a single reservoir or multiple reservoirs. However they do not by themselves guarantee optimum reservoir drainage. Premature water or g
 ls. Long horizontal and multilateral wells crossing heterogeneous possibly multiple reservoirs often show greater formation damage than co
 rically sand-control completion decisions have often been based on the assumption that sand control will occur and have been constrained b
 educe intervention frequency by extending squeeze treatment lifetime while concomitantly reducing any potential damage in both low water-c
 s viz. for cation composition (EDAX) diffraction patterns (XRD) thermal profiling (DSC/TGA) naphthenic acid distribution using electrospr
  m a reservoir where the process of scale ion stripping between the seawater injection well and production wells is known to occur is studied
ESP’s). While production rates are increased using ESP’s run time can be compromised by the formation of scale within the inner w
 hibition. Several new chemistries (two inorganic compounds and one organic nitrogen-based product) have been identified which provide imp
  y is a well-established mature operation. Moreover the degree of risk posed by deposition of mineral scales to the injection and production
  ors when such expensive subsea wells are at stake. Normal methods such as bullheading squeeze chemicals are nearly impossible to imp
differences in laboratory-test procedure scale-inhibitor (SI) returns and modeling approaches for nonaqueous and aqueous SI treatments.ï¿
 main sulphide scales are iron zinc and lead with the latter two often occurring together. This paper presents experimental results from a ser
                                                                                       OnePetro OnePetro
chnological systems. The most well known example of biomimetics is the development of Velcro which resulted from the inability of burrs from
   engineers with large amount of real-time downhole data. Although the basic principles for DTS operations are simple the interpretation of t
matical model capable of simulating aqueous and non-aqueous scale inhibitor squeeze treatments. The model considers the immiscible dis
 ns in a North Sea field since 1990s. Some of the wells in which the fluid is producing from the “clean sandstone formation had experien
                                                    OnePetro
  ions of scale inhibitors are always needed to provide limited inhibition performance. In addition it is extremely difficult to test the iron sulfide
designed to be applied as low-damage low-water-cut or pre-emptive squeeze treatments (e.g. in critical or expensive subsea wells). The me
  rous media. There is a generally accepted view that the main two mechanisms of SI retention are “adsorption and “precipitation and
  ariable pH core floods in short outcrop carbonate cores. Effluent concentrations of scale inhibitor (DETPMP) lithium tracer calcium and m
                                                                                       OnePetro
   injection and depressurizing the reservoir to release solution gas.�Pressure depletion may be accelerated by backproducing injected brin
mising reserves. One of the key enabling technologies in this area is intelligent well completions.�Downhole inflow control devices allow fo
ult in the precipitation of sulphate scales. One technique for managing mineral scales in fields where scale inhibitor squeeze treatments may
ent. In this process a scale inhibitor solution is injected down a producer well into the near wellbore formation.� Commonly these scale in
   sulphate ions causing precipitation of barium sulphate with consequent rock permeability decrease and well productivity decline. The reliable
  during waterflooding when mixing of incompatible injection and formation waters may result in sulphate salt precipitation and flow restriction
  me of the overflush fluid type. In the past a single aqueous phase model was used for both brine and hydrocarbon overflush treatments. Th
  he more limited opportunities for interventions it is becoming increasingly important to carry out a risk analysis process for scale manageme
                                                    OnePetro
                                                    OnePetro
  rocess a scale inhibitor solution is injected down a producer well and into the near wellbore formation. Generally reservoir formations consi
 process equipment has presented a challenge to the oil and gas industry for more than 50 years. Chemical methods to control scale have be
 lities but does not generally cause significant damage within the formation itself. Indeed mixing within the reservoir may be beneficial if the
  ture. Thus when a scale inhibitor (SI) slug is injected into the formation in a squeeze treatment fluid placement is an important issue. To de
This is usually due to precipitation of barium sulphate from the mixture of both waters and consequent permeability reduction resulting in we
                                                                                       OnePetro
   from a oilfield in the UK sector of the North Sea.� Downhole scale control and the resulting squeeze treatments to production wells were
atment. In this process a SI solution is injected down a producer well into the near wellbore formation. Commonly scale treatments comprise
  stries in the presence of ferrous iron calcium carbonate barium sulfate iron sulfide and iron carbonate scales as well as combinations ther
ustry. Scale mitigation and prevention programs are critical for sustained oil production.�It is therefore essential to put in place proper scal
process a scale inhibitor solution is injected down a producer well into the near wellbore formation. Commonly scale treatments comprise th
 -grained nature low permeability and saturation with pore fluid shales are susceptible to time-dependent wellbore instability. Processes rela
 ater mixing may lead to sulphate scaling in the near wellbore area tubing and process systems. Scale inhibitor squeeze treatments are appli
 are the most common method used to prevent scale deposition in subsurface applications. Software tools exist which are routinely used to a
                                                                                         OnePetro
 rmation since it is normal to pump these treatments below the fracture pressure.�However it is known that thermal stresses as a result
  that may be rich in calcium strontium and barium ions this paper presents evidence for in situ sulphate stripping in a sandstone reservoir.
Seligi group J-sand a major reservoir of this Malay Basin giant. This joint study demonstrated the successful collaboration between ExxonM
 d well services management system as it was deployed in an onshore mature field in California USA. The motivation behind the deploymen
g the less viscous crudes in the West Sak formation by waterflooding and water-alternating-gas injection. CO2 injection could also have pote
o investigate the impact of gravitational forces on gas evolution during solution gas drive. Although some experimental result indirectly sugge
e processes by accounting for the complex dynamics operating at the microscopic scale. Moreover it has also been demonstrated that a por
g heavy oil resources. In addition the high recovery performance of SAGD makes it a popular option for these non-conventional oil resources
   issue as well as from an environmental point of view. Whatever type of reservoir potential enhanced treatment efficiency would be benefici
                                                      OnePetro
asing exploitation of gas reserves from unconventional sources most notably gas trapped in tight formations. This study describes an investi
 ex interaction of capillary viscous and inertial forces. Hence accurate determination of gas-condensate relative permeability (kr) that is affec
ought of “inner homogeneity in flow-unit a new and reasonable auto-subdividing method named “slicing-merging was proposed in thi
a using the concept of flow units. Characterization of carbonate reservoirs by flow units is a practical way of reservoir zonation. The study rep
sate relative permeability can increase significantly by increasing rate contrary to the common understanding. There are now a number of co
 to predict the saturation in the reservoir for a given height above the free water level. If cores are preserved the water saturation information
 valuation on Saudi Aramco reservoir rocks were reported but to our knowledge none of them have attempted to study wettability on the por
 cts because of an insufficient return on investment using more traditional approaches by applying more recent technical and contractual so
                                                                                         OnePetro
ous reservoirs environments value have been established for the use of inflow control valves (ICVs) and different downhole sensors. One of
   is operated by the Colombian state oil company Ecopetrol (originally discovered and exploited by Texaco). Petrominerales signed an Increm
  ructures which allows to efficiently resolving demand seasonality problems. The first ever underground gas storage project in Turkey is bein
                                                                                         the loss of
 iers to intelligent well deployment is the inability to properly quantify Value terms ofOnePetro the intelligent system's ability to function prope
 el for modern well or field development architecture requires coupling of the reservoir simulator with the well/surface facility network model w
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    an environmentally acceptable solution to the disposal of produced water and contributes to pressure maintenance when injection takes pla
    Engineering models and reality still frequently occur; despite the continuous increase in the complexity and predictive quality of reservoir mo
sually complex problem. Such techniques are aimed to dramatically reduce the time required to solve a problem. This paper examined the P
  eservoir. It is an interactive process in which various development scenarios are chosen and their performance analysed. Formation geolog
ement and decision-making purposes. When combined quantitatively with geological and flow modeling as part of history matching improved
 eys is used in history matching of reservoir simulations. Improved predictions of both recovery and areal sweep are then obtained by reducin
  ½ In the Bayesian approach we start with prior information about a reservoir – for example from analogue outcrop data – and update ou
optimization algorithm. Ant colony optimization (ACO) is a multi-agent optimization algorithm inspired by the behaviour of real ants. ACO is ab
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                                                      OnePetro
  tion data in addition to information gained through time-lapse (4D) seismic. The search for good predictions requires that many models are g
 The former�requires information about current fluid sweep and pressure changes while the latter requires accurate reservoir description a
duction. Such models based on the physical description of the reservoir need to be calibrated or conditioned to historical production data. T
                                                                                         OnePetro OnePetro
 orkflows. The underlying algorithm of the framework combines Design of Experiments (DoE) and Markov Chain Monte Carlo (MCMC) infere
ery predictions has recently aroused interest in the industry. Coupling a stochastic sampling algorithm with a Bayesian analysis potentially allo
y optimising oil and gas production. They are often accompanied by the installation of Distributed Temperature Sensors and Permanent Dow
                                                      OnePetro
                                                                                         OnePetro
  include the spatio-temporal information offered by time-lapse (4D) seismic to further constrain the model. Good predictive models can only b
e in large simulation model where more then one well are fractured some don’t represent a fractured well behaviour. In this work a chois
 st of Lutong in the offshore area of Miri Sarawak in�East Malaysia.�The field has been producing since 1967 with multiple stacked san
uction history. However because the observations cannot constrain all the subsurface properties over a field production forecasts for reser
 to condensate drop-out in near-well regions (e.g. Jones and Raghavan[1] approach). In this work an evaluation of the accuracy and applica
  een directed to study this subject mathematically by many investigators but they have been mainly focused on single-phase flow while two-
  e downhole temperature data is analyzed by matching the measurements with values predicted by a well thermal model; reducing the unce
 allows well control decisions to be implemented that optimize recovery and avoid future problems. Currently both pressure and temperature
  of fluctuations in production and injection rates. The proposed procedure uses a nonlinear signal-processing model to provide information ab
  s condensate flow around hydraulically fractured wells (HFWs) is different from conventional gas oil systems. This is mainly due to phase ch
                                                      OnePetro
 ature of the flow including the permeability anisotropy. This work is aimed to provide a reliable tool for prediction of the well performance of H
 D process in a three-dimensional model using 12.4 � and 18 �API gravity crude oils. A total of eleven runs were conducted using a 30
 imulated multiphase displacement including viscous capillary and gravitational forces for highly resolved and geologically realistic models

 rmance prediction. The development of deep offshore reservoirs is a high risk exercise: in addition to commercial and environmental exposu
eservoirs. There usually exhibit complex flow behaviours due to the condensate banking around the well caused by the bottom-hole pressur
 reservoir models. Upscaling allows taking high-resolution geostatistical models (107-108 grid blocks) to coarse scale models (104-105 grid b

   the case of a near-critical oil by using pore-scale network modelling techniques. Firstly a new model for gas buoyancy is presented that is a
 of defining critical gas saturations and relative permeability data developing a thorough understanding of the results to facilitate confident ap
mixed-wet micromodels using a 3-D pore-scale network model for three-phase immiscible flow in porous media of arbitrary wettability. Althou
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alculations to simulation studies. The results from a full 3D complex reservoir simulation study comprise a large amount of data. To better ap
 ce facilities - because of thermodynamic changes that affect the flowing brines. These changes may be induced by temperature or pressure
 with upscaling methods currently included in commercially available software. Also the efficiency of the new Streamlines-based upgridding m
 s saturation and temperature fronts due to hyperbolic features of governing conservation laws Treating more efficiently convective terms cou
 re likely to give rise to very tortuous flow paths. However these models contain too many grid cells for multiphase flow simulation and the nu
  hereafter free or mobile gas. The level of critical gas saturation is affected by pressure decline rate interfacial tensions pore structure etc. T
 conceptually in the context of the lithosphere’s near-critical mechanical state and a strong feedback between deformation and local perm
  deposition and during and after its lithification exclusive of surface alteration (weathering) and metamorphism. The diagenetic changes that
 matrix. Trapped oil in the matrix can be recovered by gas injection by activating gravity drainage mechanism. In addition there is a big impac
 orous media using a combination of well-characterized laboratory experiments and detailed compositional flow simulation.� All simulator

 r reserves recovery. The introduction of sulfate rich seawater into a reservoir producing a formation brine rich in barium ions significantly incr
  conventional quality reservoirs (>1 md) are interbedded with volumetrically significant low permeability sandstones (<1 md)–the ‘tight s
 cement sheath. The customary procedure is to use a model to predict potential failure scenarios and to subsequently design a sealant mate
n available. The main use of gravity has been for exploration purposes. 4D microgravity monitoring is another new promising gravity applicati
 iability of the various measurement sensors in particular and the data collection transmission and analysis in general when building the â€
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e with the number of controllable zones. Replacement of a failed sensor rarely occurs in practice even when data is known to be incorrect (or
ance. Traditional methods of estimating these parameters particularly for real-time detection and diagnosis of production anomalies have be
 may arise after injection water (IW) breakthrough at the production well is the formation of sulphate scale.� One of the main parameters t
de input for reservoir simulation. Traditional approach in well test analysis is first to separate transient pressure draw down and build ups’
 reservoir monitoring through use of permanent downhole instrumentation and control of production from different zones within the reservoir
                                                   ability to
e of zonal multiphase rates in real time gives theOnePetroflexibly respond to changes in the well and reservoir performance; leading to recov
 ™s supply and 10% of its proved reserves. The most active coalbed methane area is the Powder River basin of eastern Wyoming with mor
well production potential. Horizontal wells are more susceptible than vertical wells to formation damage due to the longer completion length
 contact have been paralleled by advances in completion equipment development of both Passive" Inflow Control Devices (ICDs) and "Active
                                                                                         OnePetro
                                                                                          by Repsol-YPF. The
 Gulf of San Jorge Basin Santa Cruz province Argentina. The field is fully operatedOnePetro OnePetro paper narrates the challenge and e
  achieve optimal production via choke performance management. A Generalized Predictive Controller (GPC) has been shown to be capable
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 neral the purpose of the second pump was either to increase the pumping capacity or to act as a backup to improve the reliability of the pu
   Danish North Sea. To date seven horizontal wells (2900 m total vertical depth [TVD]) have been completed using 100 tip screenout (TSO)
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 act angle and provide leakoff control. However many of these chemicals adsorb rapidly within the first few inches of the sandstone formatio
 od as a means of production enhancement from tight gas reservoirs. The first optimum fracture design (OFD) approach which maximizes w
  The pressure losses caused by these phenomena are accepted widely to be of great significance in most gas-well completions in the United

                                                                                         gas-condensate reservoirs where fracturing considered a
 voted to improve its prediction performance. However the effect of cleanup in tightOnePetro
                                                   OnePetro
mechanisms by invasion of fracturing fluid (FF) into the matrix and fracture and poor cleanup efficiency. In the last four decades fracture face
                                                                                        OnePetro of hydraulically fractured wells using the existin
has been devoted to study their performance under different prevailing conditions. Description OnePetro
  years considerable effort has been directed towards understanding of flow around hydraulically fractured wells especially for tight gas reserv
 y applications. As nominally horizontal wells get longer and follow more complicated trajectories wellbore hydrodynamics becomes an impor
 hat blockage the gas flow efficiency to the well. Not only is the gas well productivity affected by fluid but also velocity. The conventional theor
 ns in many reservoir situations. However they are still susceptible to coning toward the heel of the well despite their maximizing of reservoir
  control using Interval Control Valves (ICVs) with the installation of flow monitoring devices. The “Added Value for an IW is dependent o
with installation of appropriate flow monitoring devices to improve well and field performance management. Zonal flow control can maximise
 ent characterising the velocity of chemical reaction and the formation damage coefficient reflecting permeability decrease due to salt precipit
sulphate salt precipitation determined typical values of kinetics reaction coefficient from corefloods and what the impact would be on produ
                                                    OnePetro
 acceptance because it provides a method of minimizing formation damage preventing lost circulation risks and increasing penetration rates
ed reservoirs in Brazil. Gravel pack placement requirements include the design of pumping pressures inside the operational window formed b
 s in Brazil. Gravel pack placement requirements include the design of pumping pressures inside the operational window formed by the minim
                                                    OnePetro
 present-day. A large part of these challenges have been caused by reactive shales interbedding the sand bodies. This has had a persistent i
rk.� While the conventional sanding models generally consider a single-mechanism for sanding namely the critical depletion resulting in r
eability zones. Various forms of hydrochloric acid (HCL) are used to create deep etched fractures. However regular HCl reacts very fast with
PM) treatment in the near wellbore region of a mature oil producing well. The study is divided into several parts where various factors which a
mentation of intelligent (I-)well completions. The benefits from these more expensive completions will be realized through increased reserves
 he mid 1990’s. Downhole flow-control (DHFC) as it has become known has since been installed in hundreds of wells. However there h
  than that of a vertical well (VW) due to its greater exposure to the reservoir. However the costs of drilling and completion are more and the
 ositional environments where sand continuity is a significant uncertainty pressure transient test interpretation can generate several non-uniq
                                                    OnePetro
of the challenges in analyzing long-term real-time dynamic data such as transient pressure from PDG is the diagnostic and analysis of data
 us reservoir testing problems. Finite difference and finite element methods were used before in the construction of the well testing model wh
 in heterogeneous reservoirs. Integration of geoscience and well testing for improved fluvial reservoir characterisation was the first project of
 alyst until the emergence of the derivative approach. This approach has helped to reduce the uncertainties of the interpretation of welltest re
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  stence of a two-fluid system reservoir gas and liquid condensate. Different mobility zones develop around the wellbore corresponding respe
 bout the reservoir/well-bore characteristics (e.g. homogeneity heterogeneities phase segregation stimulation effectiveness interventions e
he oil industry practice engineer often has to deal with the transient pressure resulted from variable flowing rate history. This is particularly tr
 on of hydrocarbon from the reservoir. Continuous reservoir monitoring offers a window of prospects to increase well productivity while reduc
 rements on core samples are available however they often predict initial water production that is not experienced by individual wells. For ex
s means that sites need to be chosen with a methodology which has carefully evaluated details of performance during and after the injection

  North Sea were hydrocarbon miscible gas injection WAG injection SWAG injection FAWAG injection and MEOR. Each EOR technology
  is an extension of the studies performed in 1999 (367 data points) by Sch�ller et al. (2003) making a total data set of 509 data points. Th
   for such purposes their accuracies suffer from numerical treatments and model-building skills of inexperienced users. A simple and accura
  d promote production interruption due to the formation and deposition of hydrocarbon solids such as asphaltene wax and hydrates anywher
 otassium hydroxide with tetrabutyl ammonium hydroxide in the alcoholic titratant and correctly accounting for changes in electrode response
  g and operation. Traditionally fluid information has been obtained by capturing samples and then measuring the pressure/volume/temperatu


  energy spectral analysis for time/frequency-domain signals by the WT method. We have further developed a new method to identify reservo

ervoir drainage. Premature water or gas breakthroughs frequently occur due to: ����• ����Reservoir permeability he
ow greater formation damage than conventional wells. This is partly due to the longer exposure of the formation to the drilling and completion
 ll occur and have been constrained by the restrictions imposed upon sand entering the gas transport pipeline. The inherent conservatism of
 potential damage in both low water-cut and high water-cut wells.�This paper discusses the technical problems and examines new techno
nic acid distribution using electrospray mass spectrometry (ESMS) nuclear magnetic resonance 1H NMR and solid state 13C NMR. Clear
on wells is known to occur is studied in detail to identify if it is possible to predict the impact it has on scale management.� Injection water
  formation of scale within the inner workings of the pump. The deposition of scale can be detected by the pumps requiring increasing amoun
ave been identified which provide improved halite inhibition. Their inhibition performance was studied and compared with commercially availa
cales to the injection and production wells during such operations has been much studied. The current deep water subsea developments off
emicals are nearly impossible to implement due to the long and sometimes multiple flow lines connecting injection wells. Subsea interventio
ueous and aqueous SI treatments.� Two types of nonaqueous systems one ethylene glycol (EG) -based and two oil-soluble products eac
sents experimental results from a series of static iron sulphide (FeS) inhibition efficiency tests using 2 scale inhibitors (SI) a phosphonate an

 ons are simple the interpretation of the downhole data presents a challenge for the production engineer. Inflow profiling has been promoted
  model considers the immiscible displacement of oil and water phases along with inhibitor transport in both phases and mass transfer betw
 n sandstone formation had experienced a relatively short squeeze life when a conventional phosphonate scale inhibitor was squeezed. Thro

 or expensive subsea wells). The mechanisms through which nonaqueous SI systems operate is an important technical issue. Only when a g
adsorption and “precipitation and these are described by different but related modelling approaches in the literature. These approaches h
PMP) lithium tracer calcium and magnesium were measured as were the corresponding pH profiles. Such detailed sets of measurements

wnhole inflow control devices allow for the flexible operation of non-conventional wells.� By placing sensors and control valves at the rese
 le inhibitor squeeze treatments may prove very difficult or ineffective is injection of low sulphate seawater. The CNR operated Tiffany field in
mation.� Commonly these scale inhibitor treatments are injected as aqueous solutions.� However there are certain situations where an
  well productivity decline. The reliable productivity decline prediction is based on mathematical modelling with well-known model coefficients.
  salt precipitation and flow restriction. The reliable productivity decline prediction is based on mathematical modelling with well-known model
 ydrocarbon overflush treatments. The new model enables a more accurate description of the displacement process if a hydrocarbon fluid (eg


 ical methods to control scale have been developed including scale squeeze treatments and continual chemical injection. A key factor in the s
he reservoir may be beneficial if the concentration of scaling ions is reduced due to ion stripping as the brine mixture approaches the produc
acement is an important issue. To design successful squeeze treatments we wish to control where the fluid package is placed in the near-we
permeability reduction resulting in well productivity decrease. The sulphate scaling damage system contains two governing parameters: the

 ommonly scale treatments comprise the following stages: a preflush (often involving a surfactant) the main scale inhibitor pill an overflush
 scales as well as combinations therein. The results show that as the scale speciation of the precipitating solids change so does the scale in
 essential to put in place proper scale management strategies before developing a new field. In addition exploring new chemical formulation
mmonly scale treatments comprise the following stages: preflush main scale inhibitor pill overflush tubing displacement and shut-in followed
nt wellbore instability. Processes related to transport of fluid solutes and heat between the drilling fluid and the formation fluid can increase th
nhibitor squeeze treatments are applied to protect the producers and extend the field lifetime. Reducing cost and prolonging the squeeze lifet
ols exist which are routinely used to assist with the challenges posed by scale. An important step in using predictive simulation models is valid

e stripping in a sandstone reservoir.�The formation brine composition suggests that a moderate to severe barite scaling tendency will req
 ssful collaboration between ExxonMobil and PETRONAS to enhance the existing depletion plan and identify improved oil recovery opportuni
The motivation behind the deployment of this system was simultaneously to improve efficiency and reduce operating costs in this large field w
 . CO2 injection could also have potential applications as an enhanced oil recovery (EOR) process with the added benefit of providing a solut
e experimental result indirectly suggest the occurrence of gas migration during these tests (especially at slow depletion rates) a major limitat
 s also been demonstrated that a pore-network model when suitably anchored to core material is able to provide both qualitative and quantita
 these non-conventional oil resources. Steam processes are energy intensive and result in generation of emissions which are detrimental to h
eatment efficiency would be beneficial.�Normally this could be obtained by different strategies of employments like precipitation squeez

 relative permeability (kr) that is affected by relative impact of these forces is challenging. There are a number of reports demonstrating kr o
œslicing-merging was proposed in this paper. And the main characteristic parameters used by this method such as FZI (Flow zone indicator)
  of reservoir zonation. The study represents a petrophysical-based method that uses well loggings and core plug data to delineate flow units
 nding. There are now a number of correlations in the literature and commercial reservoir simulators accounting for the positive effect of coup
ved the water saturation information can be obtained directly. However cores are often subject to changes from their original state before br
empted to study wettability on the pore scale level. In this study wettability evaluation of carbonate rock samples of Saudi Aramco reservoirs w

d different downhole sensors. One of the difficult environments to manage is the thin oil column reservoirs where issues of rapid and simulta
 co). Petrominerales signed an Incremental Production Contract agreement in April 2001 to participate with Ecopetrol in increasing production
 gas storage project in Turkey is being carried out in the KM field with injection and withdrawal operations. Optimization of gas storage field w

 well/surface facility network model when making choices as to the reservoir and production management strategies to be employed. Such c

 and predictive quality of reservoir models. To-day’s field development decisions are still made with a high level of uncertainty in the unde
 problem. This paper examined the Productivity Potential Map (PPM) technique as a heuristic approach tool in assisting the reservoir enginee
 ormance analysed. Formation geology and zone connectivity have a major impact on the choice of well location since they determine well p
 as part of history matching improved predictions of reservoir production can be obtained. Here we apply a method of multiple-model history
  sweep are then obtained by reducing uncertainty. Flow simulations are converted to predictions of seismic-impedance attributes using a pe
 ogue outcrop data – and update our reservoir models with observations for example from production data or time lapse seismic.� The g


 uires accurate reservoir description and a predictive tool such as a simulation model. With this information important decisions can then be
 ioned to historical production data. The process of incorporating dynamic data in the generation of reservoir models known as history match

 th a Bayesian analysis potentially allows incorporation of all sources of uncertainties including data simulation and interpolation errors. Howe


 d well behaviour. In this work a choise of a fractured well representation in simulation model have been proceded from the practical point of
  since 1967 with multiple stacked sandstone reservoirs in a shallow offshore environment. Based on the BDO�EOR feasibility study condu
   field production forecasts for reservoirs are essentially uncertain. In general many parameters of the model must be adjusted in the histo
valuation of the accuracy and applicability of these techniques was carried out using data from the discovery well of the Cupiagua field inclu
  sed on single-phase flow while two-phase flow has received less attention. It has been demonstrated first by Danesh et al. (1994) and sub
ell thermal model; reducing the uncertainty in the well’s production parameters (e.g. permeability water cut). The accuracy of the resultin
ently both pressure and temperature are usually monitored downhole; while often only the pressure data is used to provide the key informatio
ssing model to provide information about preferential-transmissibility trends and the presence of flow barriers. Previous work used a steady-
 tems. This is mainly due to phase change condensate drop out and coupling (i.e. the increase of relative permeability as velocity increases
ven runs were conducted using a 30 cm x 30 cm x 10 cm rectangular-shaped box model. Temperature distributions the rise and growth of
 ed and geologically realistic models of naturally fractured reservoirs (NFR) at the sector i.e. kilometre scale with very reasonable runtime. T

ommercial and environmental exposure the sparsity of early exploration data compounds with the inherent geological complexity of turbiditic
l caused by the bottom-hole pressure drops below the dew point (for most gas-condensate reservoirs). This leads to a drop in gas relative p
 coarse scale models (104-105 grid blocks) manageable for reservoir simulation while retaining the geological realism and thus effectively r

  gas buoyancy is presented that is able to track dynamically the movement of buoyant gas in the pore network; this framework is successful
 f the results to facilitate confident application to the field is a hard task. Unfortunately existing macroscopic models are unable to reproduce

  a large amount of data. To better appreciate the result of the calculations simulation packages make use of various visualization tools such
 induced by temperature or pressure changes or by mixing of incompatible brines. While much work has been performed to study the effect
 new Streamlines-based upgridding method1 as one of the non-uniform upgridding technique was estimated. In the context of the project it w
  more efficiently convective terms could help to diminish spurious oscillation and/or numerical dispersion and better tracking of discontinuity s
multiphase flow simulation and the number of cells must be reduced by upscaling for reservoir simulation. Conventional upscaling methods o
  rfacial tensions pore structure etc. The gas relative permeability is strongly reduced when trapped gas is present. Recent experimental stud
   between deformation and local permeability. A more sophisticated statistical model devised to extract a parsimonious set of flow-rate corre
 rphism. The diagenetic changes that occur in the rock result in the alteration of some of the original petrophysical properties of the rock. Poro
 nism. In addition there is a big impact of molecular diffusion of oil and gas in total oil recovery from fractured reservoir .The experimental wor
 nal flow simulation.� All simulator input data including most EOS parameters were determined experimentally or from the literature produ

 e rich in barium ions significantly increases the potential for barium sulfate scale deposition. This type of scale is not acid soluble unlike the
 sandstones (<1 md)–the ‘tight sand’. The challenge has been to develop a programme of work to establish reserves in this sub-mill
 subsequently design a sealant material that will not fail under the expected conditions. The predictive models are either analytical or finite-el
 other new promising gravity application to monitor changes of fluid contacts. Some successful 4D monitoring surveys have been conducted

  hen data is known to be incorrect (or completely missing) due to the cost implication of a workover. However these sensors serve as the op
osis of production anomalies have been limited by sampling frequency and data quality. This paper presents field-test results of a new type o
  e.� One of the main parameters that determines the severity of this type of scale formation is the amount of injection water/formation wate
 ressure draw down and build ups’ due to constant flowing rate then analyze them by forcing a pre-selected model to derive effective res
m different zones within the reservoir through use of surface operated inflow control devices.� The potential for the real-time data generate

 basin of eastern Wyoming with more than 20 000 wells completed in the last 10 years with annual additions of greater than 2 000 wells. Th
 due to the longer completion length the longer drilling time the potentially increased overbalance and the reduced cleanup efficiency caused


 GPC) has been shown to be capable of automatically controlling the area open to flow of multiple ICVs to achieve a specified production rate

pleted using 100 tip screenout (TSO) propped-fracture treatments containing 70 million pounds of proppant. The target oil bearing Tor and Ek

(OFD) approach which maximizes well productivity for a given fracture volume was introduced by Prats in 1960 for single-phase Darcy flow
ost gas-well completions in the United States and elsewhere (Palisch et al. 2007; Forchheimer 1901; Milton-Tayler 1993a; Penny and Jin 199




d wells especially for tight gas reservoirs. However there has been no report of a study of flow behaviour within propped fractured porous m
 e hydrodynamics becomes an important issue on well performance. In this paper we will discuss a problem in horizontal wells - the elevation
also velocity. The conventional theory to analyze the phenomena associated at rate dependent is commonly interpreted using Isochronal or f
despite their maximizing of reservoir contact. This is due to frictional pressure drop and/or permeability variations along the well. Annular flow
dded Value for an IW is dependent on the number and location of the ICV controlled zones. Too many valves lead to unnecessary and exce
ent. Zonal flow control can maximise produced oil value minimise unwanted fluids or a combination of both objectives. We have previous
meability decrease due to salt precipitation. We derived an analytical model-based method for determination of kinetics and formation damag
 what the impact would be on productivity impairment during sulphate scaling. This paper extends the previous work by modelling the inje

side the operational window formed by the minimum pump rate to avoid premature rat hole screen-out and maximum pump rate to avoid form

 d bodies. This has had a persistent influence on the sandface completion design and in particular on the drilling and completion fluid system
ely the critical depletion resulting in rock disaggregation the proposed approach considers the interplay of several mechanisms that can lead
 ver regular HCl reacts very fast with limestone and high-temperature dolomite formations and unless retarded will produce a fracture with l
 l parts where various factors which affect the application of RPM technology in a chosen field base case well are studied. These factors inc
  realized through increased reserves generated by increased drainage efficiency and reduction in well numbers and intervention frequency. A
  hundreds of wells. However there has been very little use of these valves to control water injection distribution within the layers of a reservo
ng and completion are more and the options for monitoring control and intervention often limited. Gas-condensate reservoirs are increasingly
etation can generate several non-unique solutions all of which may match test data. Using seismic attribute analysis to constrain pressure tra

 truction of the well testing model which was proved worked well for the most practical cases. In this study streamline simulation techniques
aracterisation was the first project of this kind supported by the oil industry that time. When approaching non-unique solution problems in het
ies of the interpretation of welltest result because key regions of radial flow and boundary features required for reservoir characterization des

ulation effectiveness interventions etc.) and quantitative information about reservoir parameters (e.g. permeability fracture length average
ing rate history. This is particularly true in the case when transient pressure data is from a PDG over a relatively long period of production tim
ncrease well productivity while reducing operating costs through an improved and more accurate well performance. These are achieved thro
perienced by individual wells. For example dry oil production occurs from portions of reservoirs where the local water saturation is relatively
mance during and after the injection process.� Standard methods of site evaluation for saline aquifers focus overwhelmingly on the aspec

n and MEOR. Each EOR technology which has been initiated in the North Sea was identified with its respective maturity level and / or matur
a total data set of 509 data points. The downstream separator pressure and temperature were kept at 8 bara and 50�C respectively. The
 erienced users. A simple and accurate analytical heat-transfer model is highly desirable. This paper presents three analytical heat-transfer s
phaltene wax and hydrates anywhere in the production system. These are flow assurance key risk factors that create significant impact on fi
ng for changes in electrode response that occur upon exposure of the electrode to crude oil. Introduction Chemical methods of improved oil
 uring the pressure/volume/temperature (PVT) properties in a laboratory. More recently downhole fluid analysis (DFA) during formation testin


ped a new method to identify reservoir fluid by setting up a correlation between the energy spectra and reservoir fluid. We have processed 4

 ���Reservoir permeability heterogeneity ����• ����Variations in distance between the wellbore and the flu
 rmation to the drilling and completion fluid due to the well geometry as well as to the greater overbalance pressure often applied during drillin
peline. The inherent conservatism of this approach leads to significant increases in completion costs and misses potential productivity gains.
  problems and examines new technologies for treatment of such production wells through their life cycle.�This paper covers the findings fr
MR and solid state 13C NMR. Clear distinctions for end member soap types were observed with regard to the type and amount of cations th
  le management.� Injection water sulphate ions are shown to break through eventually but the seawater fraction at which this occurs varie
e pumps requiring increasing amounts of current to maintain the flow rates. Eventually the pumps fail (either mechanically or electrically) and
 d compared with commercially available inhibitors. Salt deposition in high salinity brines can cause blockages to production and process sys
deep water subsea developments offshore West Africa and Brazil have brought into focus the need to manage scale in an effective way. To t
 ng injection wells. Subsea intervention to place squeeze inhibitors is prohibitively expensive due to the requirement of utilizing a service boa
 sed and two oil-soluble products each containing penta-phosphonate SIs were investigated. Detailed compatibility and injectivity tests were
  ale inhibitors (SI) a phosphonate and a polymer. The paper also highlights the methodology which has been developed for assessing iron s

. Inflow profiling has been promoted as the prime reason for the installation of DTS systems though DTS data are currently used in all aspec
both phases and mass transfer between phases. It can model kinetic and equilibrium adsorption and desorption from either phase.� The
e scale inhibitor was squeezed. Through a research program a polymer inhibitor was developed and a number of laboratory static and dyna

portant technical issue. Only when a good understanding of the transport and retention mechanisms is developed can this be built into a mod
 n the literature. These approaches have been used quite successfully to model field squeeze treatments. To analyse in a detailed and unam
 Such detailed sets of measurements are required to interpret the inhibitor/carbonate interaction mechanisms. This previous study showed th

ensors and control valves at the reservoir face engineers can monitor reservoir and well performance in real time analyse data make deci
er. The CNR operated Tiffany field in the North Sea is one of the oilfields that has been swept with low sulphate seawater for the longest peri
 there are certain situations where an aqueous based treatment is not desirable such as where relative permeability effects water blocking f
g with well-known model coefficients. The sulphate scaling system contains two governing parameters: the kinetics coefficient characterising
cal modelling with well-known model coefficients. The sulphate scaling system contains two governing parameters: the kinetics coefficient ch
 ent process if a hydrocarbon fluid (eg diesel) is used and the impact on inhibitor transport through the formation and retention onto the rock


 emical injection. A key factor in the success of such treatments is the understanding of chemical placement and the effectiveness of the trea
 brine mixture approaches the production well1.� One potential exception to this is when the availability of produced water for re-injection (
 uid package is placed in the near-well reservoir formation. In recent work (Sorbie and Mackay 2005) we went “back to basics on the iss
ntains two governing parameters: the kinetics coefficient characterising the velocity of chemical reaction and the formation damage coefficie

main scale inhibitor pill an overflush and a shut-in which is followed by back-production of the well. As noted a surfactant preflush is often in
g solids change so does the scale inhibition efficiency. These changes in efficiency were attributed to the cumulative effects of crystal matrix
 exploring new chemical formulations and treatment strategies for current field programs should be examined on a continuous basis to ensu
ng displacement and shut-in followed by back-production of the well. For some years the industry has applied mutual solvent chemicals in th
nd the formation fluid can increase the formation pore pressure rendering the wellbore unstable. The proper design of the drilling fluid can co
cost and prolonging the squeeze lifetime is essential. In some StatoilHydro operated fields squeeze lifetime has been evaluated based on in
g predictive simulation models is validation. Validation requires the collection of field or laboratory data for comparison with the model predict

 evere barite scaling tendency will require inhibitor concentrations in the range of 10-50 ppm to control scale but in practice concentrations <
 ntify improved oil recovery opportunities. This J-sand contains roughly 750 to 850 million stb of oil originally in place in this maturing offshore
ce operating costs in this large field with over 1 000 wells. The paper will describe how the business processes and supporting work flows w
 he added benefit of providing a solution to the problem of produced CO2 present in the associated gas. CO2 is generally in supercritical stat
 slow depletion rates) a major limitation of such an interpretation is the difficulty in visualising the process in reservoir rock samples. In contr
o provide both qualitative and quantitative descriptions of relative permeability and hydrocarbon recovery. In contrast many so-called “exp
  emissions which are detrimental to humankind and the environment. The use of non-thermal processes involving CO2�as a miscible or im
mployments like precipitation squeezes enhanced adsorption and bridging techniques. However in HPHT fields e.g. field with temperature

umber of reports demonstrating kr of high permeability rocks affected by both coupling (the increase of kr as velocity increases and/or IFT de
od such as FZI (Flow zone indicator) and RQI (Reservoir quality index) were obtained based on core-analysis and well-logging data. This te
core plug data to delineate flow units within the most productive carbonate reservoir of Derdere Formation in Y field Southeast Turkey. Derd
ounting for the positive effect of coupling and the negative effect of inertia at near-wellbore conditions. The available functional forms estimat
ges from their original state before brought to laboratories. Hence capillary pressure (Pc) curves measured on different core samples of a he
amples of Saudi Aramco reservoirs were investigated using environmental scanning electron microscope (ESEM). The data obtained gives a

rs where issues of rapid and simultaneous gas and water breakthrough affect ultimate oil recovery. This study investigates the opportunities
 ith Ecopetrol in increasing production from the field. Under the terms of the agreement Petrominerales invest 100% of any development acti
s. Optimization of gas storage field was enabled by an improved reservoir and geologic description including the evaluation of deliverability a

nt strategies to be employed. Such close coupling is not currently readily available; particularly when the reservoir simulator the well/surface

a high level of uncertainty in the underlying data and its economic impact. The degree of data uncertainty is greatest during the exploration s
ool in assisting the reservoir engineer to� choose optimum well locations for field development planning. Eleven well locations were selec
 location since they determine well productivity. The industry’s current well placement selection process is time consuming and costly. I
y a method of multiple-model history matching based on simultaneous comparison of spatial data offered by seismic as well as individual we
mic-impedance attributes using a petroelastic transform and suitable rescaling. The resulting misfit between the model and observed data is
data or time lapse seismic.� The goal of this activity is often to generate multiple models that match the history and use the models to qua


 on important decisions can then be made including facility maintenance and well optimisation. In some fields faults control the flow patterns
 voir models known as history matching is traditionally done by hand and is a very tedious time-consuming procedure that in addition retur

ulation and interpolation errors. However the accuracy of the uncertainty estimations strongly depends on the sampling performance. In orde


 proceded from the practical point of view. A method of fractured well simulation model assessment in situation with lacking production histor
 BDO�EOR feasibility study conducted in 2004 the field has been selected as one of the major EOR candidates in the area. This paper d
 model must be adjusted in the history-matching process and the amount of computation required to solve the inverse problem may be pro
overy well of the Cupiagua field including well testing relative permeabilities (Kr) measured at low capillary number and a tuned PREOS.
first by Danesh et al. (1994) and subsequently by other researchers (Henderson et al. 1995; Blom et al. 1997; Ali et al. 1997) that the gas an
ater cut). The accuracy of the resulting inflow profile depends heavily on the accuracy of the temperature prediction model. Existing wellbore
  is used to provide the key information about the downhole performance. Temperature measurements have the potential to be as informativ
rriers. Previous work used a steady-state (purely resistive) model of interwell communication. Data in that work often had to be filtered to ac
ve permeability as velocity increases and/or interfacial tension decreases) and inertial (i.e. the reduction of relative permeability as velocity in
  distributions the rise and growth of the initial steam chamber were observed by using 25 thermocouples. Three different well configuration
 scale with very reasonable runtime. This has been possible because we used massive parallelisation and hierarchical solvers in conjunction

ent geological complexity of turbiditic formations making any performance prediction and therefore development planning highly uncertain.
 This leads to a drop in gas relative permeability a decrease in gas production and a significant economic condensate remains in the reserv
ological realism and thus effectively representing fluid transport in the reservoir 1 2. This work presents a study of the effectiveness of differe

 etwork; this framework is successfully used to model experimental visual observations of “coherent channelized gas flow and dispersed
opic models are unable to reproduce or take into account several different features of solution gas drive experiments. For example: (i) the im

se of various visualization tools such as 2D plots or 3D displays. Properties such as water cut and sweep arrays can be visualized with the 2D
s been performed to study the effect of thermodynamic changes such as pressure decrease or temperature increase on scale precipitation i
ated. In the context of the project it was realized (coded). The effectiveness of these techniques is evaluated by their application to the revisio
  and better tracking of discontinuity shocks . But in regions near the shock numerical dispersion can only be removed by the use of very fine
n. Conventional upscaling methods often have difficulty in the representation of tortuous flow paths mainly because of the inappropriate assu
 is present. Recent experimental studies have proved that gas relative permeability can be several orders of magnitude lower for an internal g
a parsimonious set of flow-rate correlations has shown similar characteristics. Coupled geomechanical-flow modeling was able to reproduce
ophysical properties of the rock. Porosity and permeability amongst others have been established to be altered by diagenesis. It is common
ured reservoir .The experimental work can by used to model this mechanism in combination of numerical simulator to investigate this phenom
rimentally or from the literature produced fluids in all experiments were found not to be in compositional equilibrium. This was not predicted b

  scale is not acid soluble unlike the carbonate based scales traditionally encountered in many regions. Alkaline based chelants such as ED
 to establish reserves in this sub-millidarcy resource; on the whole the results of this evaluation programme are positive. The main tight sec
 odels are either analytical or finite-element models. The analytical models can only be applied to relatively simple situations that require a sim
 oring surveys have been conducted in the industry revealing that this technique is a proven technology in monitoring of gas-water contacts.

wever these sensors serve as the optic nerve for achieving the vision of Real Time Optimization. They measure parameters of interest (Mon
 ents field-test results of a new type of downhole multiphase flowmeter which confirm the value of permanent downhole metering. The meter
 ount of injection water/formation water (IW/FW) mixing that has taken place.� Thus the injected water fraction in the produced brine mix i
 elected model to derive effective reservoir permeability through an inversion process. However the results obtained this way are not really d
 ential for the real-time data generated by advanced completion solutions is now being exploited to a greater extent The paper will demonstra

tions of greater than 2 000 wells. This study analyzed the projected ultimate recovery flow rates and dewatering time of 6 600 wells producin
he reduced cleanup efficiency caused by the heal-toe effect. Extensive modelling and simulation work has been previously performed analys


o achieve a specified production rate. A black box model was established using real-time downhole instrument data as a predictive model f

ant. The target oil bearing Tor and Ekofisk intervals range from 40 to 120 m of combined thickness with a Young’s modulus and permea

 in 1960 for single-phase Darcy flow systems. This method which was later modified and presented in the form of Unified Fractured Design
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




ur within propped fractured porous media for these low interfacial tension (IFT) systems. It is now a well established finding both experimenta
blem in horizontal wells - the elevation change in well trajectory and its effect on well performance. In general a horizontal wellbore is never p
 only interpreted using Isochronal or flow-after-flow tests. After this test the negative impact of inertia on gas deliverability can be very well an
 ariations along the well. Annular flow leading to severe erosion hot-spots" and plugging of screens is another challenge. Inflow Control Devi
 valves lead to unnecessary and excessive cost as well as the potential for reduced reliability. Too few valves will not provide sufficient flexib
 both objectives. We have previously shown[1] that a minimum degree of un-evenness of an invading fluid front is needed for effective ICV
tion of kinetics and formation damage coefficients from production well data consisting of barium concentrations in the produced water and o
  previous work by modelling the injectivity impairment during simultaneous injection of incompatible waters i.e. cation-rich produced water

nd maximum pump rate to avoid formation fracture. Some special projects require additional equipment to provide selective completion –

he drilling and completion fluid systems. The completion design has evolved from stacked cased hole gravel pack to open hole gravel pack d
 of several mechanisms that can lead to the rock breakup and sand transport.� One important difference is that rock disaggregation is not
etarded will produce a fracture with low conductivity. In addition concentrated HCl-based acids are very corrosive to well tubulars especially
e well are studied. These factors include the effects of instantaneous vs. kinetic adsorption for the treatment and the further influence of trea
umbers and intervention frequency. A more rigorous exploitation of the real time production data is necessary to fully achieve this objective.
ribution within the layers of a reservoir interval at high rates (>25 000 BWPD) in a continuous proportional operating mode. This paper will re
ondensate reservoirs are increasingly considered as suitable candidates for drilling SWs or HWs. These reservoirs pose special challenges
 ute analysis to constrain pressure transient test interpretation leads to better understanding of reservoir heterogeneities and boundaries and

udy streamline simulation techniques was further developed for numerical well testing purpose in which production history reservoir heterog
 non-unique solution problems in heterogeneous reservoirs the traditional analytical approach based on the ideal reservoir conditions failed.
red for reservoir characterization description and evaluation have been adequately diagnose. However the approach is complex for non-mat

permeability fracture length average reservoir pressure skin wellbore storage etc). The study of pressure transient testing in one of the Ir
relatively long period of production time. Another well testing method is to analyse transient flowing rate as a result of the constant well botto
erformance. These are achieved through analyzing the long term real time dynamic transient pressure obtained from Permanent Down-hole
he local water saturation is relatively high even though the relative permeability data would predict a water cut in the range of 30 to 60%. Thi
s focus overwhelmingly on the aspects of geological containment and monitorability.� Also important to storage site performance is the en

spective maturity level and / or maturing time frame technology use restrictions and process efficiency on the basis of incremental oil. Apa
 bara and 50�C respectively. The maximum upstream pressures were approximately 40 bara giving a maximum pressure ratio of approx
esents three analytical heat-transfer solutions for predicting heat loss and temperature profiles in pipelines transporting petroleum fluids. The
ors that create significant impact on field development planning especially when dealing with marginal deposits having varying fluid characte
n Chemical methods of improved oil recovery are not equally effective in all reservoirs. An important factor that can influence a project’s
 nalysis (DFA) during formation testing has provided real-time fluid information. However the extreme conditions of the downhole environme


 eservoir fluid. We have processed 42 models from an oil field in China using this method and have subsequently applied these rules to inter

nce between the wellbore and the fluid contacts particularly in compartmentalized reservoirs ����• ����Variations i
e pressure often applied during drilling such wells and poorer cleanup. The typical well clean up process involves flowing the well naturally o
d misses potential productivity gains. A holistic sand management strategy has been developed for the southern North Sea to challenge the
.�This paper covers the findings from late 2001 through early 2002.�Because even newer technologies have been developed since the
  to the type and amount of cations the naphthenic acid content as well as their thermal behaviour. Specific soap samples were analysed a
 ter fraction at which this occurs varies between different wells.� The impact of the various possible driving mechanisms and the extent to
 ther mechanically or electrically) and have to be replaced. Typically examination of these pumps indicated the main failure mechanism to be
 kages to production and process systems requiring remedial action often on short notice. Current commercial halite inhibitors are only effec
 anage scale in an effective way. To this end the challenge of scale control during the lifecycle of water injection production and onto produc
 equirement of utilizing a service boat over the well for many days.[1] Calculations of scaling index from formation and injected seawater mix
 ompatibility and injectivity tests were carried out before coreflooding and a carefully designed application/treatment process was required as
 been developed for assessing iron sulphide scale inhibition. The objective of this preliminary iron sulphide inhibition efficiency study was (a) t

S data are currently used in all aspects of production engineering. The differences between the thermal properties of oil gas and water allow
esorption from either phase.� The model has been validated by comparison with analytical solutions standard conventional single-phase
number of laboratory static and dynamic tests were conducted to evaluate the performances of the newly synthesized polymer inhibitor. Seve

eveloped can this be built into a model for designing such squeeze treatments (such as the SQUEEZE VI model). The experimental work in
s. To analyse in a detailed and unambiguous manner where a given retention mechanism (e.g. pure adsorption) or mechanisms (e.g. couple
nisms. This previous study showed that carbonate dissolution was evident in all core floods and on how this depended on pH.�It also ind

n real time analyse data make decisions and modify the completion without physical intervention to optimise reservoir and asset performan
ulphate seawater for the longest period (> 10 years) and from the start of water injection and consequently yields useful information on brine
permeability effects water blocking fluid lifting chemical penetration or hydrate formation are of major concern. This paper presents the res
he kinetics coefficient characterising the velocity of chemical reaction and the formation damage coefficient showing how the permeability de
 arameters: the kinetics coefficient characterising the velocity of chemical reaction and the formation damage coefficient showing how the pe
ormation and retention onto the rock matrix. Field data is presented with various treatments where either seawater or diesel are applied as d


ment and the effectiveness of the treatment chemicals. Evaluation of residual chemical concentration and scaling ion chemistry have long bee
 y of produced water for re-injection (PWRI) is insufficient to maintain voidage replacement and must be supplemented with seawater.� U
e went “back to basics on the issue of viscous SI slug placement. That is we re-derived the analytical expressions that describe placeme
 and the formation damage coefficient reflecting permeability decrease due to salt precipitation. Previous work has derived analytical-mod

noted a surfactant preflush is often injected in order to “condition the rock potentially by altering the wettability resulting in enhanced SI r
 e cumulative effects of crystal matrix distortion by either exogenuous scale specie or effect of metal complexation to the scale inhibitor chem
 mined on a continuous basis to ensure efficient results are achieved. Saudi Arabian reservoirs have their own set of scale related challenge
pplied mutual solvent chemicals in the preflush stage of such treatments to (i) avoid emulsion formation or water blocking thus avoiding slow
oper design of the drilling fluid can counteract wellbore instability. Lower and upper bounds on mud weight are determined from mechanical s
 ime has been evaluated based on inhibitor return concentration and cumulative water treated. Field experience and laboratory studies have
or comparison with the model predictions. The cost and value of various data required for designing scale inhibitor squeeze treatments with S

 cale but in practice concentrations < 5 ppm are adequate.�Investigation of the produced brine compositions has revealed that this is du
 ally in place in this maturing offshore reservoir in the Malay Basin comprising multiple interdependent closures with relatively thin oil columns
 cesses and supporting work flows were defined. This is an essential step before any technology can be deployed. The challenges of data ma
 CO2 is generally in supercritical state in normal reservoir conditions. However permafrost causes an unusually low reservoir temperature an
 s in reservoir rock samples. In contrast experimental observations using transparent glass models have proved invaluable in this context an
. In contrast many so-called “experimental depletion drive relative permeabilities are not measured directly but are generally obtained by
s involving CO2�as a miscible or immiscible gas phase in combination with steam for heavy oil recovery is considered as a viable alternati
PHT fields e.g. field with temperature higher than 150�C an additional obstacle would be the thermal stability of the chemicals. In nature

kr as velocity increases and/or IFT decreases) and inertia (i.e. the reduction of kr as velocity increases) for these low IFT systems. However
nalysis and well-logging data. This technology can be used to subdivide the reservoir into flow-units and identify the type of flow-units simulta
on in Y field Southeast Turkey. Derdere Formation is composed of limestones and dolomites. Logs from the 5 wells are the starting point for
he available functional forms estimate the two effects separately and include a number of parameters which should be determined with mea
 red on different core samples of a heterogeneous formation are usually correlated to porosity permeability and/or rock type using various te
 e (ESEM). The data obtained gives access to the distribution of oil and water in relation with mineral interface which can not be observed by

s study investigates the opportunities that intelligent completions provide for efficient oil recovery from thin oil column reservoirs. Three wells
nvest 100% of any development activity in return for a portion of the value of the incremental production. The Orito reservoir is a multi layere
uding the evaluation of deliverability and storage capacity in the reservoir. Based on available information and those generated by simulation

e reservoir simulator the well/surface facility simulator and potentially the optimiser programs are provided by different suppliers. We have

ty is greatest during the exploration stage but decreases as the reservoir development plan is executed and production data is obtained. Sta
ng. Eleven well locations were selected using PPM technique and compared with the same number of wells located using conventional STO
cess is time consuming and costly. It requires analysing numerous development options by performing a large number of flow simulations.
 d by seismic as well as individual well-production data. Using a petroelastic transform and suitable rescaling forward-modeled simulations a
 een the model and observed data is combined with an equivalent measure for well data and these are used to constrain simulations by itera
he history and use the models to quantify uncertainties in predictions of reservoir performance.� A critical aspect of generating multiple his


 fields faults control the flow patterns and the update of the transmissiblities has great impact on matching of fluid saturations and pressure t
ming procedure that in addition returns only one single matched model. It has been shown that the best matched model may well not be a g

 n the sampling performance. In order to improve the robustness of the coupled Bayesian methodology the factors that affect the accuracy o


 tuation with lacking production history was created. It is based on comparison of productivity and transient pressure behaviour with results of
candidates in the area. This paper describes a successful application of the PETRONAS upgridding technique in Baram field. The so called
olve the inverse problem may be prohibitive. To address this issue we proposed a new methodology which restricts the parameter ranges
 lary number and a tuned PREOS. Henderson et al’s capillary number dependent relative permeability and effective inertial resistance
 1997; Ali et al. 1997) that the gas and condensate relative permeability (kr ) can increase significantly by increasing the flow rate contrary to
e prediction model. Existing wellbore fluid temperature models were developed for conventional wells. This paper focuses on the modificatio
have the potential to be as informative as pressure measurements in reflecting the reservoir’s and the well’s production performance
 at work often had to be filtered to account for compressibility effects and time lags. Even though it was often successful the filtering required
  of relative permeability as velocity increases) effects. Description of HFWs in gas condensate reservoirs using the existing reservoir simula
es. Three different well configurations were investigated – a horizontal injection and production well pair a vertical injection – vertical pr
nd hierarchical solvers in conjunction with a new discrete fracture and matrix modelling (DFM) technique that is based on mixed-dimensional

elopment planning highly uncertain. Prediction of a well performance is generally a twofold matter: predicting the initial rate of the well and t
mic condensate remains in the reservoir. In this study we use a methodology to evaluate the productivity of gas condensate wells. Starting
a study of the effectiveness of different available techniques for permeability upscaling and the implementation of a new technique for upscal

 channelized gas flow and dispersed “incoherent gas flow that are seen to take place in porous media as permeability increases. We then
 experiments. For example: (i) the impact of outlet boundary conditions upon the formation of saturation gradients and (ii) transitions between

p arrays can be visualized with the 2D or 3D displays respectively. These plots enable an understanding of the result of a reservoir simulation
 ure increase on scale precipitation it is only recently that a body of work has been developed on the impact that the dynamics of brine mixin
ated by their application to the revision process of the reservoir model of the part of “Kp field of Western Siberia Russia. Considered res
y be removed by the use of very fine uniform grids with many grid blocks. To avoid expensive solution of such a finely girded domain we dev
nly because of the inappropriate assumptions concerning the boundary conditions. An accurate and practical upscaling method is therefore r
 s of magnitude lower for an internal gas drive process (gas liberation during depressurization) than for an external gas drive process (gas inj
 flow modeling was able to reproduce those characteristics for a generic pattern waterflood perturbed with random noise but only when loade
e altered by diagenesis. It is common knowledge in the industry that the amount of hydrocarbon recovered from a reservoir is dependent am
al simulator to investigate this phenomenon more accurately. A fully compositional model has been applied to a numerical experiment in liter
 equilibrium. This was not predicted by the simulator giving a poor match between experimental and simulated oil recoveries. The match was

Alkaline based chelants such as EDTA and DTPA are only effective at removing small accumulations. Mechanical removal is generally con
mme are positive. The main tight sections in Hassi Messaoud are of Cambrian age. Grain-rimming chlorite cement within thin intervals locall
ely simple situations that require a simplified set of input data. In these cases the results are consistent with those of finite-element models. M
 n monitoring of gas-water contacts. This paper studies the ability of microgravity to capture movement of the injected water in a giant carbon

measure parameters of interest (Monitoring) which is the first stage of the production optimization loop frequently known as Measure Analyze
anent downhole metering. The meter contains only three sensors but is capable of direct multiphase-flow-rate and cut measurements withou
er fraction in the produced brine mix is an important value to determine.�Our ability to model scale precipitation in situ and in the well is link
ults obtained this way are not really dynamic or at most is “pseudo-dynamic because these are based on the fact that a continuous signa
 ater extent The paper will demonstrate that trending analysis of the pressure drop (dP trending) using the data delivered by sensors located

 watering time of 6 600 wells producing from the Wyodak and Big George coal zones – the source of 58% of the basin’s cumulative pro
 as been previously performed analysing the impact of formation damage and well cleanup in horizontal wells. This paper extends that work t


strument data as a predictive model for the controller. The model parameters were updated in real-time using the Decay Recursive Least Squ

 a Young’s modulus and permeability that can vary from less than 0.5 to over 2.5 million psi and 0.1 to 4 m respectively along the horiz

he form of Unified Fractured Design (UFD) charts by other investigators is widely used in the petroleum industry even for gas condensate s
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




 established finding both experimentally and theoretically that the flow of gas-condensate fluid systems in porous media is affected by both co
neral a horizontal wellbore is never perfectly horizontal. The inclination angle could be a result of drilling control or sometimes could be desi
 gas deliverability can be very well analyzed using special graphics. However the actual effect related to capillary number and its dependenc
nother challenge. Inflow Control Devices (ICDs) were proposed as a solution to these difficulties in the early ‘90s. ICDs have recently gaine
alves will not provide sufficient flexibility for efficient control. We previously showed[1] that a minimum degree of un-even fluid-front progre
fluid front is needed for effective ICV control. This work studies scenarios to identify when “Proactive rather than “Reactive ICV chok
ntrations in the produced water and of well productivity decline. We analyse production data for five scaled-up producers from giant offshore
aters i.e. cation-rich produced water (PWRI) and seawater with sulphate anions. An analytical model with explicit expressions for deposited

 to provide selective completion – External casing packers (ECP) installed at different positions along the production screen aim the isolati

ravel pack to open hole gravel pack designs. Non-gravel pack open hole designs are also being considered for the future to meet the challen
nce is that rock disaggregation is not seen to represent the onset of sanding because the sand mass can offer significant resistance from fri
 corrosive to well tubulars especially at high temperatures. To address problems associated with concentrated acids various retarded acids
ment and the further influence of treatment properties reservoir fluid properties and the reservoir formation. From the sensitivity study we ca
 ssary to fully achieve this objective. We previously showed that water influx time and source could be detected in horizontal wells in real tim
al operating mode. This paper will review BP’s efforts to team with manufacturers to deliver new technologies that can reliably provide th
  reservoirs pose special challenges selecting one type or the other due to the complex nature of fluid flow in porous media exhibited by these
 heterogeneities and boundaries and is the central theme of this paper.� Additionally seismic data can guide the design of pressure trans

 production history reservoir heterogeneity multi-well interference as well as oil-water two phase flow problems were all considered. Stream
 the ideal reservoir conditions failed. An option to get an approximate solution for the problem is to solve the non-linear pressure diffusivity eq
 he approach is complex for non-mathematician and an alternative method for improving its interpretation and reducing the difficulty of its pra

sure transient testing in one of the Iranian giant oilfields was initially undertaken to estimate important well and reservoir flow parameters and
 as a result of the constant well bottom hole flowing pressure. The method is so-called decline curve analysis. However in reality because of
obtained from Permanent Down-hole Gauges (PDG) which will provide input and vital information for improving the existing reservoir model
ter cut in the range of 30 to 60%. This lack of agreement means that effective reservoir management is hampered because it is difficult for s
 o storage site performance is the engineering design of transport and injection.� Transport to storage in offshore saline aquifers is norma

on the basis of incremental oil. Apart from WAG at Ekofisk and FAWAG at Snorre CFB all technologies have been applied successfully o
 a maximum pressure ratio of approximately 4.� The Hydro models (Sch�ller et al. 2003) show a very good agreement for prediction of
es transporting petroleum fluids. The three solutions consist of one steady-state-flow solution and two transient-flow solutions. The two transi
 eposits having varying fluid characteristics. To reduce the risk we have adopted a systematic approach to evaluate the potential impact of a
 tor that can influence a project’s success is crude oil composition. Because crude oils are complex mixtures evaluation of oil compositio
onditions of the downhole environment limit the DFA-tool measurements to only a small subset of the fluid properties provided by a laborator


sequently applied these rules to interpret reservoir layers. It is found that identifications by use of this method are in very good agreement wit

½ï¿½â€¢ ����Variations in reservoir pressure in different regions of the reservoir penetrated by the wellbore. ����•
s involves flowing the well naturally or aided by artificial lift to remove the external and internal mudcake and flow-back the mud filtrate. This p
southern North Sea to challenge the conservative paradigm. This is based on a complete understanding of SNS reservoir rock properties an
ogies have been developed since the writing of this paper it should be read as the history of technological development. Scale control techn
ecific soap samples were analysed along with their parent soap forming crude oils collected from the same field over a period of one year. T
riving mechanisms and the extent to which matrix and fracture flow contribute to the process are described.� The discussion is generalis
 ed the main failure mechanism to be the deposition of Calcium Carbonate scale within the pump. The actual run times achieved tend to be d
mercial halite inhibitors are only effective at high concentrations (250 – 5 000 ppm). Therefore a more efficient salt inhibitor would need to
 njection production and onto produced water reinjection has been reviewed for a number of fields by the authors. This outlines the risk ass
 formation and injected seawater mixtures are routinely based upon the thermodynamics of the mixed brines. Although some mixing does o
 n/treatment process was required as a result of the hydrophobic nature of these products. To understand the SI-transport and -retention mec
de inhibition efficiency study was (a) to establish which of the conventional SI tested inhibit FeS and under which test conditions; (b) to determ

properties of oil gas and water allow the detection of unwanted fluids using DTS. Monitoring of the produced fluid temperature allow the eng
standard conventional single-phase squeeze calculations and multi-phase reservoir simulation calculations. Example results are presented
y synthesized polymer inhibitor. Several field trials were also carried out with a satisfactory result. This paper outlines the idea of how the ne

VI model). The experimental work in this paper focused on a specific oil soluble version of a standard pentaphosphonate inhibitor (DETPMP)
 orption) or mechanisms (e.g. coupled adsorption and precipitation) are operating requires that we carry out careful laboratory experiments u
 this depended on pH.�It also indicated where simple adsorption isotherms could describe this accurately and where this was not the cas

 imise reservoir and asset performance.�They provide the ability to independently control each valve individually from the surface to max
ntly yields useful information on brine mixing and brine-rock interactions during low sulphate seawater sweep. This paper presents the evolut
 oncern. This paper presents the results of a modelling sensitivity study comparing non-aqueous and aqueous scale inhibitor squeeze treatm
 ent showing how the permeability decreases due to salt precipitation. Previous works have derived analytical-model-based method for dete
mage coefficient showing how the permeability decreases due to salt precipitation. Previous works have derived analytical-model-based met
er seawater or diesel are applied as displacement fluids being considered. In each case the well was treated with the same aqueous scale in


d scaling ion chemistry have long been used in monitoring programs and more recently probes have been developed that increase the rate
e supplemented with seawater.� Under such circumstances seawater and formation brine may be completely mixed before injection. This
al expressions that describe placement in linear and radial layered systems for unit mobility and viscous fluids. Although these equations are
 ous work has derived analytical-model-based method for determination of kinetics coefficient from laboratory coreflood on quasi steady stat

 wettability resulting in enhanced SI retention. In these treatments the main SI pill and overflush fluids may be aqueous or non-aqueous base
mplexation to the scale inhibitor chemistry. The ultimate conclusion of this study is that because of the relationship between the scale inhibitor
eir own set of scale related challenges. Calcium carbonate scales were a major challenge in a majority of wet producers in several carbonate
 or water blocking thus avoiding slow well clean-up and also (ii) for enhancing adsorption of the scale inhibitor onto the formation rock. This
 ht are determined from mechanical stability criteria. Once the drilling fluid type and weight is decided the pore pressure increase due to mud
 erience and laboratory studies have determined the criteria for re-squeezing the wells. One critical aspect of downhole scale management i
 e inhibitor squeeze treatments with SQUEEZE VI has been assessed. The first stage of designing a scale inhibitor squeeze treatment is che

positions has revealed that this is due to much lower sulphate concentrations in the produced brine mix than would be expected purely from
osures with relatively thin oil columns and large gas caps. The reservoir communicates with nine producing fields via a common regional aqu
 deployed. The challenges of data management included not only the automatic handling of very large quantities of real-time data but also th
nusually low reservoir temperature and as a result CO2 will be in liquid state for these heavy oil fields. In this study we consider West Sak re
e proved invaluable in this context and provide a sound physical basis for modelling gravitational gas migration in gas-oil systems. The exper
 directly but are generally obtained by history-matching laboratory production data with reservoir simulators often resulting in very low gas rel
ery is considered as a viable alternative to limit the drawbacks of steam generation. These processes have the capability to enhance oil recov
al stability of the chemicals. In nature the thermal stability of products is often in conflict with or in contradiction to the property of high biode

  for these low IFT systems. However there is little information on this subject for low permeability rocks. In this work we report and analyze
  identify the type of flow-units simultaneously. This paper analyzed the rationality and petroleum geological meanings. Its application was sho
m the 5 wells are the starting point for the reservoir characterization. The general geologic framework obtained from the logs point out for disc
which should be determined with measurements at high-velocity conditions. Measurements of gas/condensate relative permeability at simula
 ility and/or rock type using various techniques to generate field wide saturation height function. This paper evaluates performance of six sat
erface which can not be observed by normal techniques. It also improves the understanding of rock/fluid interaction. In this study preserved

  in oil column reservoirs. Three wells located in an offshore field were studied to show the benefit of intelligent completions in different reserv
 . The Orito reservoir is a multi layered reservoir with three production intervals: Pepino Villeta and Caballos at depths of 3000 ft TVD and 70
 n and those generated by simulation model KM field is the best candidate for underground gas storage. The KM offshore natural gas field w

 ded by different suppliers. We have had the opportunity to test a newly developed “link tool to integrate the reservoir simulation model w

  and production data is obtained. Standard probabilistic workflows have been developed to quantify this uncertainty. These workflows are us
wells located using conventional STOIIP based methodology. The exercise used information from six vertical wells in Field A Otter Sandston
 a large number of flow simulations. This paper describes a technique to partially automate this well placement process. It has been found
aling forward-modeled simulations are converted into predictions of seismic impedance attributes and compared to observed data by calcula
 used to constrain simulations by iteratively updating the model. Updated-model probabilities can then be used to analyze uncertainty. The m
 tical aspect of generating multiple history matched models is the sampling algorithm used to generate the models.� Algorithms that have


 ng of fluid saturations and pressure to time-lapse seismic (4D) or production history observations. We present an automated history matchin
  matched model may well not be a good predictor of future performance. In this work one of the first field applications of the Neighbourhood

 the factors that affect the accuracy of the estimations must be examined. This paper investigates how different sampling strategies affect th


  nt pressure behaviour with results of analytical model of Cinco-Ley and Samaniego. Analysis of the known methods of the hydraulic fracture
 hnique in Baram field. The so called Optimum�Grid Coarsening Scheme" uses fine grid static and dynamic reservoir variability to identify
which restricts the parameter ranges of the calibration by using physically based prior information extracted from geological and petrophysic
bility and effective inertial resistance correlations [2] as implemented in a commercial simulator were used to history match the well test dat
 y increasing the flow rate contrary to the common understanding. This effect known as positive coupling complicates the flow of gas and c
 his paper focuses on the modification of these temperature models for application to intelligent completions equipped with DTS & Inflow Con
he well’s production performance. However currently available models are unable to simulate the temperature profile of an intelligent we
often successful the filtering required subjective judgment as to the goodness of the interpretation. This work uses a more complicated mode
 rs using the existing reservoir simulators requires the use of very fine grids to capture the significant changes of flow and rock properties occ
air a vertical injection – vertical production well pair and a vertical injection – horizontal production well pair with and without fractures th
 that is based on mixed-dimensional unstructured hybrid-element discretisations. High-resolution DFM simulations are important to resolve

dicting the initial rate of the well and the longevity of the well. Historical information is often extremely useful in such an exercise. In a Deepwa
 ty of gas condensate wells. Starting from the analysis of six available well tests we have identified one test that most suitable for the aim o
ntation of a new technique for upscaling of relative permeability curves based on the numerical solution of a two-phase system and the Kyte

a as permeability increases. We then apply the pore-scale network model to study the dynamics of gas flow during reservoir depressurization
gradients and (ii) transitions between different flow regimes (disconnected immobile gas disconnected mobile gas continuous gas flow) tha

 of the result of a reservoir simulation run. In some cases the results are easy to understand and appreciate for example increasing well cou
pact that the dynamics of brine mixing in the reservoir has on scale precipitation in situ. Much of this work has been conducted using finite dif
tern Siberia Russia. Considered reservoir is highly heterogeneous in vertical direction (permeability ranges from 0.01 to 500 mD). The exist
f such a finely girded domain we develop a moving mesh approach combined with higher order up-winding schemes. Numerical solver here
ctical upscaling method is therefore required to preserve the flow features caused by highly heterogeneous fine scale geological description.
 n external gas drive process (gas injection). The critical gas saturation may indirectly influence gas breakthrough gas cut and also oil produ
 h random noise but only when loaded to a near-critical state hence providing strong support for the conceptual model. Coupled modeling o
 ed from a reservoir is dependent amongst other factors on the hydrocarbon initially-in-place in the reservoir and the intra reservoir rock por
 ied to a numerical experiment in literature to investigate the drainage of CO2 from a core with artificial fractures and the effect of molecular d
 ulated oil recoveries. The match was significantly improved for the cross-bedded displacements by using alpha factors derived from the MC

Mechanical removal is generally considered to be the only effective removal option for significant sulfate scale deposits in the tubing but is n
 ite cement within thin intervals locally inhibited later pervasive quartz cementation; the quartz is the cause of reservoir degradation in the bul
with those of finite-element models. More complex situations can be simulated with finite-element models but the input data requirements a
of the injected water in a giant carbonate field. The oilwater case is more difficult due to the significantly lower density contrast as compared

equently known as Measure Analyze and Control" which will manage the reservoir and well performance. The reliability of permanent downh
w-rate and cut measurements without slip models even in highly deviated recirculating flow. The physics basis and flow loop tests are discu
ecipitation in situ and in the well is linked to our ability to accurately determine the IW fraction at production wells.� Current industry practic
ed on the fact that a continuous signal was broken into discontinuous signals. Some information (more than a changed permeability value) of
he data delivered by sensors located strategically in a multi-zone horizontal or multilateral intelligent completion can identify the time and loca

8% of the basin’s cumulative production 61% of the current production and 45% of the CBM wells. For the Big George and Wyodak we
wells. This paper extends that work to advanced completions employing Interval Control Valves (ICVs) and Inflow Control Devices (ICDs). It


using the Decay Recursive Least Squares (DRLS) method. A case study in which a multi-zone horizontal intelligent well was located in comp

 to 4 m respectively along the horizontal section. The wide variations in reservoir and rock properties present significant fracture design and

 industry even for gas condensate systems. Recently some methodologies have been proposed to modify UFD considering the two-phase r
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




n porous media is affected by both coupling (the increase of relative permeability (kr) as velocity increases and/or IFT decreases) and inertia
 control or sometimes could be designed on purpose for an extremely anisotropic formation. When vertical permeability is much smaller tha
 capillary number and its dependency with velocity called Positive coupling is not yet analyzed in transient tests. As it has been mentioned i
arly ‘90s. ICDs have recently gained popularity and are being increasingly applied to a wider range of field types. Their efficacy to control t
degree of un-even fluid-front progression needs to be induced in order for effective ICV control to be observed to “Add sufficient “V
e rather than “Reactive ICV choking policy can add greater value. Reservoir scenarios were created in which inter-zone connection per
led-up producers from giant offshore field A submitted to seawater flooding (Campos Basin Brazil) in order to predict productivity index and
ith explicit expressions for deposited concentration and injectivity decline was developed. The location of scale deposition and the resulting

 the production screen aim the isolation of certain reservoir zones. In these cases gravel pack placement present an additional constraint â€

ered for the future to meet the challenges of drilling and completion at higher well angle. The field requires a mix of all these techniques to me
an offer significant resistance from frictional properties interlocking of sand grains and arching.� The approach presented here can be us
 ntrated acids various retarded acids were introduced. Organic acids were used also in some cases. These organic acid systems were used
 ion. From the sensitivity study we can conclude that the most influential factors in the treatment response i.e. the water cut reduction are th
 etected in horizontal wells in real time1. Extension of this technique will be shown to allow confident detection of water influx in vertical or dev
 hnologies that can reliably provide this functionality. By 2010 a significant portion of BP’s production will come from complex water flood
  w in porous media exhibited by these low interfacial tension systems which are different from those of conventional gas-oil systems. In this
an guide the design of pressure transient tests especially the test duration to evaluate key seismic anomalies.� Other data such as produc

roblems were all considered. Streamline well testing model was developed to analyze pressure draw down and build up under these field con
 the non-linear pressure diffusivity equation through well test numerical modelling and simulation. Well test analysis and interpretation condu
n and reducing the difficulty of its practical application haven’t been discovered most especially where there is inconsistency in data sam

ell and reservoir flow parameters and characterize heterogeneities in the Fn limestone formation; However during the course of interpretatio
alysis. However in reality because of production constraints or changes in operating procedures the down-hole flowing pressure seldom rem
mproving the existing reservoir model for flow simulation. Reservoir monitoring during field development can amplify the understanding of the
 hampered because it is difficult for simulation models to mimic the observed reservoir production without use of data that may bear little rese
e in offshore saline aquifers is normally expected to be by pipeline. There are several proposed methods of CO2 injection for example as a d

es have been applied successfully on the corresponding fields. Hydrocarbon miscible gas injection and WAG injection can be considered as
ery good agreement for prediction of mass flow rate both for critical and subcritical flow conditions with an average error of absolute values
ansient-flow solutions. The two transient-flow solutions are for startup mode and flow-rate-change mode (shutting down is a special mode in w
  to evaluate the potential impact of asphaltene and wax precipitation and deposition. In this field case two distinct layers of hydrocarbon dep
 mixtures evaluation of oil composition in a way that is meaningful with respect to specific chemical recovery processes can present many pr
 id properties provided by a laboratory. Nevertheless these tools are valuable in predicting other PVT properties from the measured data. Th


 thod are in very good agreement with the results of well tests. Introduction An important log-analysis application is determining reservoir-flu

 by the wellbore. ����• ����Pressure drop along the completion’s flow path due to friction (“heel-toe effect).
and flow-back the mud filtrate. This process can be effective in conventional wells but is not adequate in long horizontal and multilateral wells
 of SNS reservoir rock properties and sand control completion performance in gas wells and has been tuned by learnings from SNS and ana
al development. Scale control technology available to control scale formation within the reservoir and near-wellbore area of production wells
 me field over a period of one year. The nature of two of these soap samples were found to be related to the particular chemical treatment o
 bed.� The discussion is generalised to findings applicable to other carbonate systems. The mechanisms of scale inhibitor retention when
ctual run times achieved tend to be dependant on the severity of the scaling produced water but were typically in the order of weeks. Howev
 efficient salt inhibitor would need to reduce both treatment level and production downtime. The inhibition performance of three new chemica
 e authors. This outlines the risk assessment process that should be undertaken to select the most economical and effective scale control m
brines. Although some mixing does occur in the interwell distance the most vigorous mixing occurs in the vicinity of the production wellbore
 d the SI-transport and -retention mechanisms for these nonaqueous systems comparisons were made with the corresponding aqueous app
er which test conditions; (b) to determine the mechanisms through which SIs inhibit FeS; and (c) to determine if it is possible to determine a â

uced fluid temperature allow the engineer to prevent the formation of wax and hydrates ensuring effective flow assurance. This paper exam
 ons. Example results are presented along with guidelines for appropriate use of these types of calculation in the design of aqueous and n
paper outlines the idea of how the new inhibitor chemistry was developed and how a special monomer was introduced to make the co-polym

ntaphosphonate inhibitor (DETPMP) which has been described previously in the literature. Several floods have been carried out comparing
out careful laboratory experiments under “field relevant conditions. In this work we study adsorption vs. adsorption/ precipitation by perf
rately and where this was not the case. Recently we have performed additional core floods using carbonate core from a second block of thi

  individually from the surface to maximise oil production and/or minimise formation water and/or gas production.�However they may also
weep. This paper presents the evolution of individual well brine chemistry data backed up by reservoir simulation and reactive transport flow
queous scale inhibitor squeeze treatments.� The model described can simulate the effect on the treatment life of treatment solubility in the
 lytical-model-based method for determination of both coefficients from breakthrough concentration and pressure drop during laboratory core
  derived analytical-model-based method for determination of both coefficients from breakthrough concentration and pressure drop during lab
eated with the same aqueous scale inhibitor. The initial squeeze treatments used a diesel overflush. However subsequent treatments utilised


een developed that increase the rate of evaluation/interpretation. All these methods prove that the chemical is present in the brine when sam
mpletely mixed before injection. This will not lead to a loss of injectivity if scale inhibitor chemicals are appropriately applied to the injected br
 fluids. Although these equations are quite well known we applied them in a novel manner to describe scale inhibitor placement. We also de
ratory coreflood on quasi steady state commingled flow of injected and formation waters. The current study extends the method and derive

 ay be aqueous or non-aqueous based fluids. The main purpose of this paper is to present a near-well radial SI squeeze model that can sim
lationship between the scale inhibitor performance and ferrous iron concentration it is important to consider this relationship when determini
 f wet producers in several carbonate reservoirs across Saudi Arabia.�The possibility of a sulfate scaling problem in these fields was minim
 hibitor onto the formation rock. This paper discusses the effect of a mutual solvent preflush on scale inhibitor squeeze lifetime and also on w
e pore pressure increase due to mud pressure penetration mechanism can be calculated. Manipulation of the chemical potential mechanism
ect of downhole scale management is the laboratory determined Minimum Inhibitor Concentration (MIC) of the squeeze inhibitor. If the MIC is
ale inhibitor squeeze treatment is chemical selection. Corefloods are used to derive an inhibitor-rock interaction function called an isotherm.

  than would be expected purely from dilution of seawater with the formation brine.�The question this paper addresses is what has caused
 ing fields via a common regional aquifer encompassing an area of more than 7000 square kilometers. Seligi was challenging to model beca
 uantities of real-time data but also the management of inventory and the integration of field level data with corporate level data. Historical da
n this study we consider West Sak reservoir and investigate different injection strategies in which available water and CO2 can be utilized ind
 gration in gas-oil systems. The experimental observations often exhibit somewhat contradictory trends however - some studies showing disp
ors often resulting in very low gas relative permeabilities that are difficult to explain from a physical viewpoint. Although pore-scale network m
 ve the capability to enhance oil recovery through CO2�utilization during production and also provide an avenue to dispose CO2�after p
 adiction to the property of high biodegradation e.g. environmental friendliness. In the present paper a new multi-task method with a high t

   In this work we report and analyze a series of steady state kr for a 3.9 mD reservoir rock with low porosity of 6% measured using our uniqu
cal meanings. Its application was shown by some examples from DaQing Oilfield. Key words: flow unit slice-merging auto-subdivide inner h
 ained from the logs point out for discriminations within the formation. 58 representative core plug data from 4 different wells are utilized to be
 nsate relative permeability at simulated near-wellbore conditions are very demanding and expensive. Recent experimental findings in this la
 per evaluates performance of six saturation-height methods (i.e. Leverret-J[1] Cap-Log[2] Johnson[3] Cuddy et al. [4] Skelt-Harrison[5] an
  interaction. In this study preserved rock samples from two distinct reservoirs (Arab-C and Shu'aiba) were used. The mineralogical analysis

ligent completions in different reservoir behavior. The study shows that using intelligent well completion can increase the total oil production
allos at depths of 3000 ft TVD and 7000 ft TVD respectively. The reservoirs are depleted and pressures are below the original bubble point p
  The KM offshore natural gas field was discovere in 1988 located about 3 km off the shore of Silivri in the Marmara sea. The field was initial

rate the reservoir simulation model with a subsurface/surface network model allowing (automatic) optimisation of the full network performan

  uncertainty. These workflows are usually framed by the reservoir scale development plan and end prior to the well’s detailed completion
 rtical wells in Field A Otter Sandstone Formation (Sherwood Group). It is a discontinuous fluvial system with highly variable permeability pat
acement process. It has been found that a new map which ranks the reservoir zones based on their productivity potential can speed-up and
 ompared to observed data by calculation of a misfit. A similar approach is applied to dynamic well data. This approach improves on gradient
e used to analyze uncertainty. The method has been applied to the Schiehallion UK Continental Shelf (UKCS) reservoir. We first found a goo
he models.� Algorithms that have been studied include gradient methods genetic algorithms the Ensemble Kalman Filter and others. Th


resent an automated history matching method that updates fault transmissibilities by matching 4D seismic predictions from the simulations to
 ld applications of the Neighbourhood Algorithm (NA) is presented. The NA is a stochastic sampling algorithm that explores the parameter sp

different sampling strategies affect the estimation of uncertainty in prediction of reservoir production. The sampling strategy involves the choi


own methods of the hydraulic fractured well simulation First of all several methods of hydraulic fracture representation are analysed form the
 namic reservoir variability to identify the non-uniform grid cell configuration at the coarse grid model. Averaged saturation equation is the key
 cted from geological and petrophysical input. The aim of the work is to have a sound basis for forecasting uncertainty in reservoir productio
 sed to history match the well test data. To investigate the assumptions in the analytical models numerical simulations were run first with co
 g complicates the flow of gas and condensate near the wellbore even further when it competes with the inertial forces at higher velocities ty
 ons equipped with DTS & Inflow Control Valves. A published temperature prediction model was modified to analyze an intelligent well’s g
 mperature profile of an intelligent well correctly. This paper provides a theoretical underpinning for the temperature data interpretation workf
 work uses a more complicated model that includes capacitance (compressibility) as well as resistive (transmissibility) effects. The procedur
anges of flow and rock properties occurring in and around the fracture. This tasks it very cumbersome time consuming and impractical. In th
well pair with and without fractures that provided a vertical path through the horizontal producer for 12.4 �API gravity crude oil. The effec
simulations are important to resolve the non-linear coupling of small scale capillary - viscous and large scale gravitational - viscous processe

eful in such an exercise. In a Deepwater field in the Gulf of Mexico understanding the behavior of existing wells and reasons for their historic
 test that most suitable for the aim of this project. Then we have used a well-developed workflow in the Institute of Petroleum Engineering a
of a two-phase system and the Kyte and Berry method3. The reference fine scale model considered in this study is a conceptual fluvial rese

low during reservoir depressurization in virgin and waterflooded conditions with the dual purpose of understanding the microscopic flow beha
mobile gas continuous gas flow) that are characterized by different pore-scale dynamics. These features can be considered using pore-scal

 iate for example increasing well count you may likely recover more oil. In some other cases surprises may be resolved by investigating the u
 k has been conducted using finite difference simulators which are handicapped with regard to these calculations in that numerical dispersio
 ges from 0.01 to 500 mD). The existing geological model has low vertical resolution (about 1.3 m). The simuation model was upscaled by un
 ing schemes. Numerical solver here have been employed is Finite volume method. A MMPDE(moving mesh PDE) is solved associated with
 us fine scale geological description. In this paper the problems encountered in routinely used upscaling approaches are outlined and a mo
 kthrough gas cut and also oil production. Network modeling has been used to investigate physical relations to factors influencing the forma
nceptual model. Coupled modeling of a cross-section representative of the Gullfaks field also demonstrated long-range influences. The matri
 rvoir and the intra reservoir rock pore space connectivity. The hydrocarbon initially-in-place is a function of the reservoir rock porosity and th
ractures and the effect of molecular diffusion included. The same study has been applied for a synthetic fractured reservoir model to investig
 g alpha factors derived from the MCM displacements in the homogeneous pack. Introduction The recovery of oil by miscible gas injection h

e scale deposits in the tubing but is not appropriate for removing scale from within the near well bore area or within a frac-pack or screen. Thu
se of reservoir degradation in the bulk of the sandstone with resulting permeabilities of <1 md and often in the microdarcy range. Generally
 ls but the input data requirements are far greater. Typically in the modeling papers little information is included on how the input data is obta
 lower density contrast as compared to the gas-water case. Monitoring water floodfront in the field is a key factor in applying successful reser

 e. The reliability of permanent downhole gauges is not 100% throughout the well life. It is therefore imperative to authenticate whenever pos
 s basis and flow loop tests are discussed. Introduction Well monitoring surveillance and problem diagnosis are critical parts of the product
on wells.� Current industry practice is to work on an analytic approach for determining the fraction of IW in the produced brine stream in g
han a changed permeability value) of the reservoir system response may already lose while uncertainties were increased or multiplied in the
 pletion can identify the time and location of water influx into a well.� It will be shown that pressure drop trend signatures" can identify the lo

  For the Big George and Wyodak wells the estimated ultimate recovery (EUR) averages 223 million cubic feet (MMcf) per well (median 168
 nd Inflow Control Devices (ICDs). It reports a comparative study that illustrates the greater cleanup efficiency of advanced long horizontal w


al intelligent well was located in complex reservoir showed that the GPC operation is highly effective. The robustness of the technique was illu

resent significant fracture design and execution challenges. Results indicate that propped-fracture treatments become increasingly more dif

dify UFD considering the two-phase region around the fracture as a damage zone with reduced permeability. These methods are generally o
 wells in Russia. For the analysis the authors evaluate three primary categories of Russian production wells: gas wells oil wells producing a




es and/or IFT decreases) and inertial (i.e. the reduction of kr as velocity increases) effects. However the interaction of capillary viscous and
ical permeability is much smaller than horizontal permeability an undulating wellbore may be favorable to overcome the low vertical permeab
ent tests. As it has been mentioned in literature the effect of coupling over gas condensate wells improves the pair of krg and krc and minim
 field types. Their efficacy to control the well inflow profile has been confirmed by a variety of field monitoring techniques. An ICD is a chokin
bserved to “Add sufficient “Value to justify the costs and risks involved in installing this relatively new technology. ICV(s) can balance
d in which inter-zone connection permeability contrast between zones zonal length and other reservoir parameters were systematically var
 rder to predict productivity index and to plan the well stimulation program. The wells are completed by gravel packs. Complete mixing of sea
  of scale deposition and the resulting injectivity impairment are calculated for a range of sensitivities including reaction kinetics (ranging fro

nt present an additional constraint – operational pump rates should be high enough to avoid alpha wave sedimentation around the packers

es a mix of all these techniques to meet well objectives. Introduction The South Tapti gas field is located 160 km north north-west of Mumba
  approach presented here can be used to explain why sanding in the field tends to be episodic and how depletion which is a major factor in
 ese organic acid systems were used successfully to acid fracture several wells in a deep gas reservoir in Saudi Arabia. Field data however
se i.e. the water cut reduction are the combination of polymer adsorption type (kinetic or equilibrium) with method of application of the resist
ection of water influx in vertical or deviated multi-zone and/or multi-lateral I-well completions. The source of water influx into the well and the
n will come from complex water flooded reservoirs in an environment of rising operating costs. The injection wells in these fields need to acc
conventional gas-oil systems. In this study we have investigated the performances of SW HW and VW in both single-layer homogenous and
malies.� Other data such as production history core data formation evaluation from well logs analog information on channel geometry etc

 wn and build up under these field conditions. In the developed well testing mathematical models along each streamline equations were solv
 est analysis and interpretation conducted on this basis is called numerical well testing. This technique has been proved through study and re
 re there is inconsistency in data sampling. The statistical approach (VEMST) utilized simple statistical tools such as StatDiff StatDev and S

ver during the course of interpretation numerous engineering complexities were encountered due to the nature of well behavior and reservo
wn-hole flowing pressure seldom remains at a constant level over a long period of time. Deconvolution is a technique which can be used to
 can amplify the understanding of the reservoir depletion compartmentalization and efficiency of water injection also the presence of any flo
ut use of data that may bear little resemblance to measurements. After a brief discussion of relative permeability the focus of this paper is fir
 of CO2 injection for example as a dense phase in the liquid or supercritical phase as water-alternating gas cycles or as carbonated brine.

 WAG injection can be considered as mature technologies in the North Sea. The most commonly used EOR technology in the North Sea wa
an average error of absolute values of 6.2% and a standard deviation of 8.9%. Comparisons with the models of Sachdeva et al. (1986) and P
(shutting down is a special mode in which the flow rate changes to zero). An application example is presented to illustrate how the models ca
wo distinct layers of hydrocarbon deposits are considered marginal from reserves point of view; the upper deposit is a gas condensate layer
very processes can present many problems. In particular there is a need for improvements in acid number (AN) measurements also known
operties from the measured data. These predictions can be used in real time to optimize the sampling program to help evaluate completion


pplication is determining reservoir-fluid properties. It is common practice to calculate the water and oil saturations of reservoir formations by

  due to friction (“heel-toe effect). Many such well and reservoir management problems can be mitigated by installation of downhole flow c
n long horizontal and multilateral wells suffering from increased frictional pressure drop along the wellbore and heterogeneity. The cleanup ef
 uned by learnings from SNS and analogous fields. It combines sand failure prediction methodical and structured selection of sand control ap
ear-wellbore area of production wells will be outlined with a focus on the current developing technology to control scale within low water-cut w
o the particular chemical treatment on site. There were clearly observable differences in the final location within the surface facility as well a
 sms of scale inhibitor retention when phosphonate polymer and vinyl sulphonate co-polymer inhibitor squeeze treatments are applied in this
 pically in the order of weeks. However in some extreme cases pump failures had occurred in a matter of days from replacement and start u
 n performance of three new chemicals and two commercial products were evaluated under static conditions along with performance assess
 nomical and effective scale control methodology (which for sulfate-based scale could be seawater injection with scale inhibitor squeeze treat
he vicinity of the production wellbore where water from multiple layers and streamlines impinge. These near wellbore mixtures have short re
  with the corresponding aqueous applications. These comparisions were made in terms of SI-return performance flowback permeability pos
 rmine if it is possible to determine a “minimum inhibitor concentration (MIC) with this methodology. This preliminary study shows that: (i)

 ve flow assurance. This paper examines a novel DTS application by analyzing the effect of scale deposition on the temperature profile of a
 ation in the design of aqueous and non-aqueous scale inhibitor treatments in wells across a wide range of water cuts. Introduction The m
was introduced to make the co-polymer inhibitor. The monomer was introduced to enhance the inhibitor adsorption property since it carries a

ds have been carried out comparing corresponding nonaqueous and aqueous applications of DETPMP to better determine the main feature
n vs. adsorption/ precipitation by performing a series of experiments where we know that the system exhibits either (a) adsorption only or (b)
onate core from a second block of this outcrop chalk using DETPMP scale inhibitor slugs at various concentrations and pH values.�Thes

oduction.�However they may also be used to address other produced water management issues such as inorganic scale control.�
 mulation and reactive transport flow modelling which demonstrates the effect that low sulphate seawater injection has had on the produced
ment life of treatment solubility in the oil and water phases treatment strategy adsorption properties (from the water and oleic phases) visco
 pressure drop during laboratory coreflood on quasi steady state commingled flow of injected and formation waters. The current study extend
ntration and pressure drop during laboratory coreflood on quasi steady state commingled flow of injected and formation waters and also from
wever subsequent treatments utilised the same inhibitor but with seawater as the overflush fluid. It is clear from the field returns that the use


ical is present in the brine when sampled or that scale formation is not occurring at the point of brine analysis. Evaluation of suspended solid
ppropriately applied to the injected brine stream2. However scale inhibitors are retained by the reservoir rock as they are displaced away fro
cale inhibitor placement. We also demonstrated the implications of these equations on how we should analyze placement both in the laborat
 udy extends the method and derives formulae for calculation of formation damage coefficient from pressure drop measurements during co

 adial SI squeeze model that can simulate the impact of a surfactant preflush on both inhibitor return concentrations and on well clean-up tim
 ider this relationship when determining the minimum inhibitor concentration (M.I.C.) for the inhibition of scale growth in oilfield production sys
 ing problem in these fields was minimized by selecting compatible floodwaters and/or creating a sufficient buffer-band to separate the incom
hibitor squeeze lifetime and also on well clean up time. It builds on a previous publication that introduced a recent model to simulate the impa
 of the chemical potential mechanism by knowing the membrane efficiency of the shale-mud system and utilizing the right salt concentration
 of the squeeze inhibitor. If the MIC is lower than the concentration of inhibitor required to prevent scale at real conditions the well could scale
eraction function called an isotherm. The possible consequence of terminating a coreflood too early has been demonstrated. An opportunity f

 paper addresses is what has caused this reduction in sulphate concentration. The formation brine Mg/Ca ratio is < 0.1.�Over geologica
 Seligi was challenging to model because of its large size (8km x 12km) long history (30 years) significant gas and water coning issues and
ith corporate level data. Historical data had to be brought into and made compatible with the new system. The technologies required for this
 le water and CO2 can be utilized individually or combined for EOR and CO2 storage purposes. A three-phase three-dimensional black oil s
 owever - some studies showing dispersed gas migration whilst others describe fingered channelised flow - and to date there appears to h
point. Although pore-scale network models have been successfully used in the past to match raw production data the steady-state relative p
an avenue to dispose CO2�after production. Numerical simulation studies have been carried out utilizing STARS (a three phase multi-com
 new multi-task method with a high throughput screening system for thermal ageing is presented. Combined with this set up is a new dynam

osity of 6% measured using our unique experimental facilities. These data have been measured at three IFT below one mNm-1 and five velo
slice-merging auto-subdivide inner homogeneity Integrated Flow Factor (IFF) Introduction The concept of flow-unit or hydraulic unit was pr
 om 4 different wells are utilized to better understand the petrophysical framework of the formation. The plots correlating petrophysical param
 ecent experimental findings in this laboratory indicate that measured gas/condensate relative permeability values on cores with different cha
 Cuddy et al. [4] Skelt-Harrison[5] and Sodena[6] methods) employed in the oil industry. Measured capillary pressure data and core propert
ere used. The mineralogical analysis showed that the predominant minerals were calcite and dolomite in both samples. Determination of wet

  can increase the total oil production from a well by controlling the gas and water production.� The value is clearer in wells where the gas
 are below the original bubble point pressure. The wells can exhibit a number of challenges for production of fluids using artificial lift including
he Marmara sea. The field was initially planned to be developed with 3 wells but recently 2 additional wells were added during the developm

 isation of the full network performance. The tool supplies the simulation results to the surface network simulator/optimiser which in turn rec

  to the well’s detailed completion design. This is despite the fact that expensive advanced completions have become common during re
  with highly variable permeability patterns which poses a significant challenge for selecting well targets. A comparison of simulated flow perf
oductivity potential can speed-up and hence reduce the cost of this decision making process. This map termed the Productivity Potential M
 This approach improves on gradient-based methods by avoiding entrapment in local minima. We demonstrate the method by applying it to t
UKCS) reservoir. We first found a good match to production and seismic data in the field. From the updated probability distribution of the para
 emble Kalman Filter and others. This paper investigates the efficiency of three stochastic sampling algorithms: Hamiltonian Monte Carlo (H


 ic predictions from the simulations to observed data. We investigate the impact of successively updating faults by adding new data to our ob
orithm that explores the parameter space finds an acceptable ensemble of data fitting models and extracts robust information from this ense

e sampling strategy involves the choice of algorithm and selection of algorithm parameters in sampling the high-dimensional parameter spac


epresentation are analysed form the practical point of view: in simulation model with almost 1 million cells futher significant complication of g
eraged saturation equation is the key driver in calculating the sub-grid properties in the fine level that subsequently will be the basis for determ
 ng uncertainty in reservoir production. We demonstrate the applicability of the methodology using quarter five-spot pattern waterflooding m
cal simulations were run first with constant Kr and then with the effect of capillary number and inertial resistance. The main conclusions a
e inertial forces at higher velocities typical of those around perforation tips. The flow of gas and condensate in the perforated region was stud
d to analyze an intelligent well’s geometry i.e. distributed inflow into an annulus fluid mixing at multiple points etc. The new model was u
emperature data interpretation workflow. A novel temperature model for multiphase flow with (possible) phase changes in an intelligent comp
ansmissibility) effects. The procedure was tested on rates obtained from a numerical flow simulator. It was then applied to a short-time-scale
me consuming and impractical. In this work a two dimensional mathematical simulator has been developed which is based on finite-differen
4 �API gravity crude oil. The effect of fracture orientation (vertical or horizontal) on steam-oil ratio (SOR) and oil recovery was studied usi
 cale gravitational - viscous processes adequately for sector scale NFR. Cross-scale process coupling in NFR controls oil recovery and NFR

ng wells and reasons for their historical deviations from prediction has formed a major input into the design of the next Phase development w
 Institute of Petroleum Engineering at Heriot-Watt University to carry out the study. The workflow is to first characterize the formation for res
this study is a conceptual fluvial reservoir based on the Stanford V model4. The reference fine scale isotropic and locally heterogeneous perm

 erstanding the microscopic flow behavior and producing predicted estimates for the variation of multi-phase flow properties: this is undertake
 s can be considered using pore-scale modeling techniques. However such microscopic applications even in the few cases where they are

may be resolved by investigating the underlying principles of fluid flow through the grid blocks. Because of the complexity of some reservoir m
 culations in that numerical dispersion effects can be orders of magnitude greater than physical dispersion. The introduction of chemical rea
 simuation model was upscaled by uniform simple (algebraic averaging) method. The new geological model (finer in vertical direction) was c
 mesh PDE) is solved associated with physical PDE's of steam injection process in order to relocates the mesh nodes to concentrate them in
 g approaches are outlined and a more accurate and practical way of performing upscaling is proposed. The new upscaling method Well Dr
ations to factors influencing the formation of critical gas saturation and the corresponding flow functions. The rock matrix composition determ
 ted long-range influences. The matrix of empirical correlations between all well-pairs for a field can be decomposed in various ways. The pri
  of the reservoir rock porosity and the pore space connectivity is a measure of the permeability of the reservoir rock. Thus the recovery from
 fractured reservoir model to investigate the effect of CO2 injection in oil recovery mechanism in the field scale. � In this work we found th
 very of oil by miscible gas injection has been a subject of interest and research in petroleum engineering for more than 40 years (Stalkup 19

 a or within a frac-pack or screen. Thus the recommended management strategy is one of prevention rather than remediation. A combination
n in the microdarcy range. Generally the overlying Lower Devonian has a low density of faulting and fractures; open and closed fractures are
ncluded on how the input data is obtained. Because of this several papers have been published that have proposed ways to obtain the input
ey factor in applying successful reservoir management practices to maximize recovery and prolong the field life. The monitoring of inter-well f

erative to authenticate whenever possible the operational state of these downhole sensors. Such authentication will allows greater confidenc
 nosis are critical parts of the production business and many production parameters are monitored in the process. Of these flow rate and flu
 W in the produced brine stream in general and for identifying IW breakthrough in particular. A robust and accurate method for determining
 s were increased or multiplied in the process of data evaluation and analysis. This paper presents a new approach which will allow for cont
 p trend signatures" can identify the location of the water influx and application of this approach will be illustrated by use of two three and fou

 bic feet (MMcf) per well (median 168 MMcf). An average peak gas rate of 319 thousand cubic feet per day (Mcf/D) (median 236 Mcf/D) occu
 iency of advanced long horizontal well completions over that achieved by the equivalent conventional openhole completion. The highest c


e robustness of the technique was illustrated by its ability to operate effectively in the complex reservoir environment when the signal is pertu

 ments become increasingly more difficult to place as porosity decreases and this problem is primarily attributed to higher natural fracture/fis

bility. These methods are generally oversimplified as they neglect the phase change and variation of relative permeability with interfacial tens
wells: gas wells oil wells producing above the bubblepoint and oil wells producing below the bubblepoint. For each category the authors des




 e interaction of capillary viscous and inertial forces within highly conductive propped fractures is yet unknown. In this work we report a serie
 o overcome the low vertical permeability. Undulation in wellbore trajectory will change the inflow distribution along the wellbore and therefor
ves the pair of krg and krc and minimized the effect of skin rate dependent. Flow-after-flow tests of 6DD+1BU have done in gas condensate
 ring techniques. An ICD is a choking device installed as part of the sandface completion hardware. It aims to balance the horizontal well’
  new technology. ICV(s) can balance the fluid-front provided they are placed correctly. A typical example would be their installation across z
  parameters were systematically varied. The interaction between the aquifer and reservoir was observed when producing these reservoirs w
ravel packs. Complete mixing of sea- and formation waters in production well neighbourhoods in the reservoir under consideration was assu
cluding reaction kinetics (ranging from minimum to maximum values as obtained from coreflood and field data) fraction of produced water

ve sedimentation around the packers to assure sealing after the packer inflation process. Traditionally design criteria consider a minimum cr

d 160 km north north-west of Mumbai in the Arabian Sea off the west coast of India. The field is operated by a joint venture between BG Exp
  depletion which is a major factor in rock breakup can be highly effective in holding broken-up sand grains together and in fact become a s
n Saudi Arabia. Field data however indicated that there is a need to create deeper and more-conductive fractures. To achieve this goal it w
 th method of application of the resistance factors (threshold or variable) resistance factor ratio reservoir fluid properties and reservoir layou
e of water influx into the well and the zonal fluid contribution will be quantified allowing this unwanted fluid's production to be reduced. Knowl
ction wells in these fields need to accept in some cases up to 65 000 barrels water per day. The use of DHFC reduces the number of injecti
 in both single-layer homogenous and layered gas-condensate reservoirs. ECLIPSE 300 compositional reservoir simulator which includes ou
information on channel geometry etc. is also important in getting a better understanding of reservoir description. While we briefly discuss all

each streamline equations were solved all together numerically to derive transient pressure solutions for draw downs and build ups. Results
as been proved through study and research in the past few years to be an effective way to solve the problems not only for single phase flow
ools such as StatDiff StatDev and StatExp derived from time series analysis to identify possible unseen features diagnose key flow regime

e nature of well behavior and reservoir conditions led to the masking of the actual reservoir response: 1) a high permeable reservoir with high
 s a technique which can be used to convert measured transient pressure due to variable sand-face rate into the transient pressure respons
injection also the presence of any flow barriers (such as activated fault). On this basis reservoir management can be more accurate and re
meability the focus of this paper is first to examine the uncertainties in the data that are used for the predictions. This then provides a numer
g gas cycles or as carbonated brine.� These result in different migration pathways in the aquifer during the short term (1-50yr) and storag

 EOR technology in the North Sea was WAG and recognized as the most successful EOR technology. The main problems experienced we
odels of Sachdeva et al. (1986) and Perkins (1993) show that the performances of these models are not as good as the Hydro model. The S
sented to illustrate how the models can be used in insulation design of an offshore pipeline. Introduction Heat transfer across the insulation
er deposit is a gas condensate layer and the lower is a black oil layer.� Because of marginal reserves mono-bore commingle production w
 ber (AN) measurements also known as total acid number (TAN). AN is important in evaluating crude oils for alkaline and surfactant proces
rogram to help evaluate completion decisions and to understand flow-assurance issues. The petroleum industry has devoted much effort to


aturations of reservoir formations by use of electrical logs. With the development of well-logging technology a number of methods have been

ated by installation of downhole flow control devices – Active" Interval Control Valves (ICVs) and "Passive" Inflow Control Devices (ICDs). IC
 e and heterogeneity. The cleanup efficiency is improved by employing Advanced Well completions. Inflow Control Valves (ICVs) control the
 tructured selection of sand control approach (including consideration of production performance longevity and risks) and novel solids lifting
o control scale within low water-cut wells.�Moreover this paper shows that the new technical area of emulsion-scale-inhibitor-delivery syst
on within the surface facility as well as the final composition (calcium content acid distribution presence of other chemical families) of thes
 queeze treatments are applied in this carbonate reservoir are outlined.� Chemical placement represents the most significant technical cha
of days from replacement and start up. It was proposed that one treatment strategy to increase the pump run time by inhibiting scale formati
  ions along with performance assessment after aging. Both sea salt and pharmaceutical-grade sodium chloride were used in the tests. All thr
 ion with scale inhibitor squeeze treatments to maintain production or sulfate reduction of the injection water with or without the need to scale
near wellbore mixtures have short residence times before being produced therefore reaction kinetics must be considered and it is not clear
 ormance flowback permeability possible formation damage and changes in the wettability conditions that might account for any post-treatm
This preliminary study shows that: (i) The conventional SIs tested in this study do inhibit FeS scale formation; (ii) A clarification phenomenon

sition on the temperature profile of a conventional producing well. The low thermal conductivity of scale deposits increases the temperature o
 of water cuts. Introduction The most common method for preventing scale formation is by applying a scale inhibitor (SI) squeeze treatme
adsorption property since it carries a special function group to have a good affinity to the reservoir rock. This special function group plays a k

 to better determine the main features of the transport and retention mechanism of the system. Novel core flood experiments with tracers in b
hibits either (a) adsorption only or (b) coupled adsorption/precipitation. Experimentally it is straightforward to determine which regime the syst
 centrations and pH values.�These results significantly extend previous work and are presented under the following two headings:� S

uch as inorganic scale control.� This paper describes the potential risks posed specifically to intelligent completions by scale deposition
er injection has had on the produced brine chemistry. The main impact is that scale inhibitor squeezes have only been required for carbonate
om the water and oleic phases) viscosity effects and wellbore friction.� Of particular interest is the relationship between inhibitor solubility
 ion waters. The current study extends the method and derives formulae for calculation of two scale damage coefficients from just pressure d
d and formation waters and also from just pressure drop measurements during two corefloods with two different ratios “formation water
 ar from the field returns that the use of seawater rather than marine diesel improved chemical placement and extended treatment life. The th


alysis. Evaluation of suspended solids in terms of amount mineral type composition and texture has been used along with brine chemistry t
r rock as they are displaced away from the wellbore resulting in the inhibitor front propagating more slowly than the saturation front - usually
nalyze placement both in the laboratory and by numerical modeling before we apply a scale inhibitor squeeze. An analysis of viscosified SI a
 ssure drop measurements during coreflood. The proposed method can be extended for axi-symmetric flow around the well allowing calcu

 centrations and on well clean-up time. Specifically we model the effects of surfactant injection on the reduction of residual water and oil satu
scale growth in oilfield production systems. Introduction Oilfield scales are a conglomeration of several different scales i.e. calcium carbona
nt buffer-band to separate the incompatible waters.�Phosphonate based scale inhibitor treatments either encapsulated chemical applied
d a recent model to simulate the impact of a surfactant on improved inhibitor retention which used data derived from laboratory experiments.
d utilizing the right salt concentration in the drilling fluid can suppress the pore pressure increase and stabilize the wellbore. Drilling in gas hy
 at real conditions the well could scale up. Field examples are given where sulphate scale was observed downhole and in the tubing around th
 been demonstrated. An opportunity for reducing the man-hours required to derive an isotherm has been identified. The water production an

 /Ca ratio is < 0.1.�Over geological time frames the reservoir rock and formation brine will come into chemical equilibrium the Mg/Ca an
ant gas and water coning issues and its interaction with the regional aquifer. This paper will highlight techniques that were critical in creating
m. The technologies required for this project included the software systems and the integration of these with remote intelligent field sensors a
phase three-dimensional black oil simulator was constructed accounting for the oil swelling and viscosity reduction due to dissolution of liqu
ow - and to date there appears to have been little systematic effort towards modelling the wide range of behaviours seen in or inferred from
ction data the steady-state relative permeabilities calculated from such models commonly predict much slower gas saturation build-up than t
 ing STARS (a three phase multi-components reservoir simulator) to optimize a baseline SAGD process and wind-down process with CO2ï¿
bined with this set up is a new dynamic test -rig at HPHT conditions directly testing the efficiency of the thermally aged products. Further an

  IFT below one mNm-1 and five velocity levels below 200 md-1. The results indicate that at the highest IFT inertia is dominant at low conde
pt of flow-unit or hydraulic unit was proposed first by C.L. Hearn1 in 1984. A flow unit is defined as a series of reservoir rocks that are continu
plots correlating petrophysical parameters and the frequency histograms suggest the presence of distinctive reservoir trends. These discrimi
 ity values on cores with different characteristics become more similar if expressed in terms of fractional flow instead of the commonly used s
illary pressure data and core properties for a well in one of the North Sea reservoirs were used with rock permeability varying from less than
  both samples. Determination of wettability using ESEM method is very cost effective. It is unlike other traditional methods. It doesn’t use

 lue is clearer in wells where the gas or water constraint is reached early in the well life causing cessation of production. The ICV control stra
 n of fluids using artificial lift including: scale; solids production; high GOR; early high water production; and also very high CO2 (80%). Solids
ells were added during the development of the field hence increasing the depletion rate. In this study after gathering necessary reservoir flui

 imulator/optimiser which in turn reconfigures the intelligent well completion zones by use of Individual Control Valves (ICVs) and wellhead o

 ons have become common during recent years and the additional investment in such completions can only be justified if it is shown to be pa
 A comparison of simulated flow performance showed that well locations selected using PPM technique exhibited consistently better perform
p termed the Productivity Potential Map (PPM) is based on fundamental petroleum engineering principles. It is generated from the numeric
 nstrate the method by applying it to the UKCS Schiehallion reservoir updating the operator’s model. We consider a number of paramete
ted probability distribution of the parameters we then took the best models from the history-matching process and made predictions to deter
 orithms: Hamiltonian Monte Carlo (HMC) algorithm Particle Swarm Optimization (PSO) algorithm and the Neighborhood Algorithm (NA). HM


g faults by adding new data to our observed dataset and compare this to a single history match where all data is used. We demonstrate the m
cts robust information from this ensemble in a Bayesian framework. The aim is to forecast hydrocarbon production accurately and to assess

he high-dimensional parameter space. We present examples of using both the Neighbourhood Algorithm (NA) and a Genetic Algorithm (GA)


 s futher significant complication of grid is undesirable. Also numerical problems with system of linear eqations solution in case of very thin fra
bsequently will be the basis for determining the coarse grid scheme. It considers the balance of all forces including gravity viscous and capill
 er five-spot pattern waterflooding models. The petrophysical properties to be adjusted in this paper are coarse-scale relative permeabilitie
 resistance. The main conclusions are:          For the constant Kr simulation a constant composition expansion (CCE) data of the flowing com
sate in the perforated region was studied in this work using a finite-element modeling approach. The model allows for changes in fluid proper
ple points etc. The new model was used to demonstrate the effect of water production in an oil and water production environment on the valv
 phase changes in an intelligent completion will be presented. Reservoir and sandface temperature performance is also analyzed and couple
was then applied to a short-time-scale data set from an Argentinean field and a large-scale data set from a North Sea field. The simulation re
oped which is based on finite-difference methods and accounts for the combined effects of coupling and inertia using our recently developed
OR) and oil recovery was studied using horizontal well pair scheme. The experimental results indicated that vertical fractures improved SAG
n NFR controls oil recovery and NFR often exhibit power-law fracture length distributions i.e. they do not possess an REV and highly permea

gn of the next Phase development wells. While the new technologies that are emerging for deepwater primarily encompass the areas of dril
rst characterize the formation for reservoir heterogeneity the fluid properties and well productivity to evaluate the well dynamic performance
ropic and locally heterogeneous permeability distribution was upscaled to different upscaling ratios by means of analytical (static) and numer

ase flow properties: this is undertaken at two PVT extremes (fluid samples separated by a depth interval of 200m from the top and bottom o
ven in the few cases where they are refined enough to include viscous or gravitational forces have perhaps their greatest limitation in the nu

 f the complexity of some reservoir models a systematic approach may be necessary to understand what is going on in the system. Develop
on. The introduction of chemical reaction calculations into streamline simulation models presents a very significant opportunity for improving
odel (finer in vertical direction) was constructed with the resolution closer to well logs. Several simulation models were constructed by the com
e mesh nodes to concentrate them in regions of sharp discontinuity and Equi-distribute a measure of error-estimate (monitor function) over th
  The new upscaling method Well Drive Upscaling (WDU) employs the wells and the actual reservoir boundary conditions (e.g. faults and p
 The rock matrix composition determines together with irreducible water saturation diffusion paths and therefore the degree of supersatura
 ecomposed in various ways. The principal components of the matrix when interpolated with appropriate spatial correlation functions have in
servoir rock. Thus the recovery from a reservoir rock affected by diagenesis based on the aforementioned effects of diagenesis on reservoir
d scale. � In this work we found that at early stage we have oil swelling and gravity drainage followed by a slow extraction mechanism whi
g for more than 40 years (Stalkup 1983).� In a first-contact miscible (FCM) displacement the gas and oil mix instantly in all proportions.ï¿

her than remediation. A combination of the low geomechanical strength of these reservoirs and other rock characteristics has led to the ado
tures; open and closed fractures are observed in core whilst mud losses suggest some fractures are conductive in the subsurface. The perm
ve proposed ways to obtain the input data in particular the mechanical parameters of the set cement. Because typically these papers have a
eld life. The monitoring of inter-well fluids would characterize any pre-mature water breakthrough to allow planning and design of appropriate

ntication will allows greater confidence to be placed in the data they supply. This paper discusses how authentication is achieved by comparin
e process. Of these flow rate and fluid type (phase) are two of the most fundamental measurements. Over the years many instruments hav
 nd accurate method for determining IW fraction in field produced water analysis is required to match the modelled IW fractions.� When th
w approach which will allow for continuous reservoir system response analysis and interpretation. Therefore the information derived from su
ustrated by use of two three and four zone completions in synthetic reservoirs.� A more complex field based example will also be employ

ay (Mcf/D) (median 236 Mcf/D) occurred an average of 1.2 years after the well was placed on production. The average well declined at a rat
openhole completion. The highest cleanup efficiency is predicted to be achieved by an intelligent completion employing both sensors and IC


environment when the signal is perturbed by outliers or by random noise levels up to the control error limits. The value of these control error l

ttributed to higher natural fracture/fissure density in the lower-porosity higher-modulus zones. Production data indicate that these natural fra

 tive permeability with interfacial tension (IFT) and velocity for these low IFT systems. They also require data that are not readily available in
 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




known. In this work we report a series of steady state gas-condensate relative permeability values for a proppant filled and a sand packed fr
 tion along the wellbore and therefore change the wellbore performance. When two-phase flow is involved especially gas-liquid flow the pre
 +1BU have done in gas condensate wells in the Monagas Field Venezuela. The results have shown that the wells in this field produce unde
 ms to balance the horizontal well’s inflow profile and minimize the annular flow at the cost of a limited extra pressure drop. Fractured an
 e would be their installation across zones showing early water or gas break-though. This allows “Value being “Added to the reservo
 d when producing these reservoirs with a horizontal IW using a range of “Reactive and “Proactive choking policies. An example of
ervoir under consideration was assumed in previous works. Using this assumption quasi steady state model for reactive flow around produc
ld data) fraction of produced water in the injected mixture and barium concentration in produced/re-injected water. The theoretical param

esign criteria consider a minimum critical velocity to avoid sand deposition. The specification of minimum flow for cleaning the ECP and pre

 d by a joint venture between BG Exploration & Production India Limited (BGEPIL) ONGC and Reliance Industries Limited (RIL). In 2002 BG
ains together and in fact become a sand-stabilizing agent.� The proposed approach is used in discussing sanding at several wells in two
e fractures. To achieve this goal it was decided to conduct a field trial with a newly developed acid system. The new acid system is an ester
  r fluid properties and reservoir layout. On the other hand the polymer viscosifying effect is not such an influencing factor and neither are the
 id's production to be reduced. Knowledge of the influx time and source permits both production optimisation and improved reservoir sweep e
  DHFC reduces the number of injection wells by using one wellbore to enable conformed injection into multiple intervals. This eliminates the
 eservoir simulator which includes our in-house relative permeability (kr) correlation accounting for the coupling (increase in kr by an increas
 cription. While we briefly discuss all relevant data the focus of this paper is primarily on integrating seismic amplitude response with pressur

r draw downs and build ups. Results such as pressure distributions field saturation maps and the distribution of streamlines can all be produ
oblems not only for single phase flow in heterogeneous formation but also for multi-phase (heterogeneous fluid properties) flow in heterogen
 features diagnose key flow regime for reservoir description and act as checkmate/alternative to the derivative approach to interpret comple

 a high permeable reservoir with high degree of heterogeneities with high skin and high wellbore storage 2) Partial penetration behavior due
e into the transient pressure response as a result of equivalent constant flowing rate. This technique can also be used to derive the transient
 ement can be more accurate and realistic. In contrast to the data obtained from the traditional well test such as DST pressure data from PD
dictions. This then provides a numerically structured approach to adjustments that need to be made to data so that history matching of simu
 ng the short term (1-50yr) and storage distributions in the long term (1 000 â€

 The main problems experienced were injectivity (WAG SWAG and FAWAG projects) injection sy
 as good as the Hydro model. The Sachdeva model and the Perkins model both have average error
   Heat transfer across the insulation of pipelines presents a
   mono-bore commingle production was thought to be an option. Also in-
oils for alkaline and surfactant processes but in order to be useful measure
m industry has devoted much effort to developing computational methods to mode


ogy a number of methods have been developed for reservoir-flui

 ive" Inflow Control Devices (ICDs). ICVs were initially employed for controlled commingled produc
ow Control Valves (ICVs) control the contribution from ind
 ity and risks) and novel solids lifting and erosion assessment models to achieve bet
 emulsion-scale-inhibitor-delivery systems originally designed to control sca
 e of other chemical families) of these samples. These were sugge
ents the most significant technical challenge when performing scale
  p run time by inhibiting scale formation was via a Scale Inhibitor Squeeze applicat
 hloride were used in the tests. All three new chemicals showed improved inh
 ater with or without the need to scale inhibitor squeeze). In the case
  ust be considered and it is not clear how low the sulphate concentration
 hat might account for any post-treatment differences. In addition approaches to mathema
 tion; (ii) A clarification phenomenon was observed after sul

deposits increases the temperature of the producing fluid in the scaled
 scale inhibitor (SI) squeeze treatment. In this process a scale inhibitor s
This special function group plays a key role for the newly developed scale

 re flood experiments with tracers in both the aqueous and oleic phases have been performed and are
 d to determine which regime the system is in as explained below. We present
 er the following two headings:� Scale inhibitor/carbonate/pH interactions in s

 ent completions by scale deposition. The potential benefits to sca
 ave only been required for carbonate scales. The modelli
 ationship between inhibitor solubility in the carrier and in si
mage coefficients from just pressure drop measurements during two corefloo
 different ratios “formation water : seawater. This paper extends the previou
nt and extended treatment life. The theory behind this phenomenon is


een used along with brine chemistry to improve our understanding of the locati
wly than the saturation front - usually referred to a
ueeze. An analysis of viscosified SI applications for linear and radial s
c flow around the well allowing calculation of both sulphate scaling

  duction of residual water and oil saturations and th
 different scales i.e. calcium carbonate barium s
 ither encapsulated chemical applied in the rathole or squeezed
derived from laboratory experiments. The focus of this p
 bilize the wellbore. Drilling in gas hydrate bearing sedim
 downhole and in the tubing around the safety valve even if the inhi
n identified. The water production and injection profile in a well is

 chemical equilibrium the Mg/Ca and Na/Ca ratios in the brine being
 hniques that were critical in creating an integrated simulation model o
with remote intelligent field sensors and data transmission systems. The
 ty reduction due to dissolution of liquid CO2. The results indicate that
 f behaviours seen in or inferred from laboratory tests. To
 slower gas saturation build-up than that found experimentally. Some pr
s and wind-down process with CO2�Injection. The baseline process was operated until matur
   thermally aged products. Further analytical aspect

 IFT inertia is dominant at low condensate to gas flow rat
es of reservoir rocks that are continuous laterally and vertically and has sim
ctive reservoir trends. These discriminations are also represent
 flow instead of the commonly used saturation. This would lower the numbe
  permeability varying from less than 1 mD to over 1000 mD
raditional methods. It doesn’t use any chemical or even generat

on of production. The ICV control strategy chosen
 nd also very high CO2 (80%). Solids issues are exacerbated on
er gathering necessary reservoir fluid production and

Control Valves (ICVs) and wellhead or manifold in order

only be justified if it is shown to be paid-back by improved overall project eco
  exhibited consistently better performance and minimum variance. STOIIP and PPM tec
 les. It is generated from the numerical reservoir models developed from
 . We consider a number of parameters to be uncertain. The reservoir’s net to gross is
ocess and made predictions to determine the most likely outcomes. We have foun
he Neighborhood Algorithm (NA). HMC is a Markov Chain Monte Carlo (MCMC)


 l data is used. We demonstrate the method by applying it to the UK Contin
 production accurately and to assess the related uncertainty by means o

m (NA) and a Genetic Algorithm (GA) to generate history-matched reser


 ations solution in case of very thin fracture cells should be solve
 s including gravity viscous and capillary that contribute to fluid flow i
e coarse-scale relative permeabilities. Coarse-scale models have
ansion (CCE) data of the flowing composition accurately re
del allows for changes in fluid properties and accounts for the
 r production environment on the valve’s mixing temperature and the tubing
ormance is also analyzed and coupled with the intelligent well temperature mode
  a North Sea field. The simulation results and field applicat
d inertia using our recently developed generalized correlation.
  that vertical fractures improved SAGD. Maximum oil re
  possess an REV and highly permeable fractures can extend over

primarily encompass the areas of drilling and completions
 aluate the well dynamic performance (transient pressu
means of analytical (static) and numerical single-phase (pre

 l of 200m from the top and bottom of the oil bearing column) and for two
 aps their greatest limitation in the number of pores that can

at is going on in the system. Developing these interpretation skills req
 significant opportunity for improving the accuracy of such calculati
  models were constructed by the combined application of different up
or-estimate (monitor function) over the meshes. Solution will advance more rapidly on
oundary conditions (e.g. faults and physical boundaries of the geological mod
 therefore the degree of supersaturation in the
e spatial correlation functions have indicated the importance of
 ed effects of diagenesis on reservoir rock porosity an
 by a slow extraction mechanism which recovers the int
d oil mix instantly in all proportions.� No capillary forces exist so in principle

ock characteristics has led to the adoption of frac-pack completio
onductive in the subsurface. The permeability range in the tight san
ecause typically these papers have addressed only one or two
w planning and design of appropriate remedial well interventio

uthentication is achieved by comparing the soft (computed) sensor value
 ver the years many instruments have been used to collect and process flow data
e modelled IW fractions.� When this is achieved it is pos
efore the information derived from such analysis can reflect the r
 d based example will also be employed to illustrate th

 n. The average well declined at a rate of 45% per year after entering the decline phase with ver
 etion employing both sensors and ICVs. The well’s full production


 its. The value of these control error limits must be increased as the step

 n data indicate that these natural fractures or fissures do not me

 data that are not readily available in particular the pressure profile (the two-ph
 use of the fracture-flow theory and state-of-the-art fracture-production




  proppant filled and a sand packed fracture with
ed especially gas-liquid flow the pressure distribution in
at the wells in this field produce under the Non-Darcy flow
ed extra pressure drop. Fractured and more hetero
alue being “Added to the reservoir management process by
 ve choking policies. An example of successful “Proactive Control is when t
model for reactive flow around production well is formulated. We obtained va
 ected water. The theoretical parameter of the size of

 m flow for cleaning the ECP and prevent the deposition of sand in the annular

 Industries Limited (RIL). In 2002 BGEPIL acquired the interests of Enron
 ssing sanding at several wells in two different fields.� These wells have been
 m. The new acid system is an ester of an organic acid in the form of soli
 nfluencing factor and neither are the she
 tion and improved reservoir sweep efficiency; proc
multiple intervals. This eliminates the need for injection wells de
 oupling (increase in kr by an increase in velocity and interfacial
 mic amplitude response with pressure transient

 ution of streamlines can all be produced through the developed s
ous fluid properties) flow in heterogeneous formation. Thi
rivative approach to interpret complex features. Result fr

e 2) Partial penetration behavior due to asphaltene plu
  also be used to derive the transient flowing rate due
 such as DST pressure data from PDG is large in quantity (long t
data so that history matching of simulation models can be achieved.

				
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