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					  Nov-09
NOTES:

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

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



                      Total number of papers published post 2005 =             10,000

                                                                   35% of papers published categorised
                                Paper
Organisation             Source No.            Chapter                       Section
SHELL                      SPE    96400   Reservoir Management               4D-Seismic
TOTAL                      SPE   124596   Reservoir Management               Alwyn Field
Heriot Watt University     SPE   116659   Reservoir Management               Artificial Lift
SCHLUMBERGER              IPTC    12029   Reservoir Management               Artificial Lift

Imperial College          IPTC    12365   Reservoir Management            Attic Oil Recovery
BP                         SPE   113479   Reservoir Management                BP's TDRM
BP                         SPE    96610   Reservoir Management                Case Study
Imperial College           SPE    96610   Reservoir Management                Case Study
SHELL                      SPE   101863   Reservoir Management                Case Study
SHELL                      SPE   110360   Reservoir Management       Development Optimisation
TOTAL                      SPE   106841   Reservoir Management       Development Optimisation
SHELL                      SPE   128348   Reservoir Management       Development Optimisation
SHELL                      SPE   121909   Reservoir Management       Development Optimisation
SHELL                      SPE   110019   Reservoir Management       Development Optimisation
SCHLUMBERGER               SPE   104041   Reservoir Management                 EOR/IOR
CHEVRON                    SPE            Reservoir Management     Gas Condensate Development
SCHLUMBERGER              IPTC    12225   Reservoir Management          Gas Lift Optimisation
SHELL                     IPTC    12225   Reservoir Management          Gas Lift Optimisation
TOTAL                     IPTC    11565   Reservoir Management               Gas Storage
TOTAL                      SPE   117172   Reservoir Management                Gas storage
Heriot Watt University     SPE   111102   Reservoir Management               Gas Storage
SCHLUMBERGER               SPE   126064   Reservoir Management               Heterogeneity
SCHLUMBERGER               SPE   120803   Reservoir Management               Heterogeneity
TOTAL                      SPE   110296   Reservoir Management             Integrated Asset
MARATHON                   SPE   103116   Reservoir Management             Integrated Study
Heriot Watt University     SPE   107197   Reservoir Management              Intelligent Well
SCHLUMBERGER               SPE    99317   Reservoir management           Low Pressure Gas
SCHLUMBERGER               SPE   123711   Reservoir Management               Methodology
BP                         SPE   101808   Reservoir Management        Modelling - Assisted HM
SHELL                      SPE   110379   Reservoir Management Modelling - Coupled Fracture/Reservoir
SCHLUMBERGER               SPE   122339                     Modelling - Coupled Surface/Reservoir Model
                                          Reservoir Management
SCHLUMBERGER               SPE   122421                     Modelling - Coupled Surface/Reservoir Model
                                          Reservoir Management


CHEVRON                   IPTC    11219   Reservoir Management     Modelling - Experimental Design
SHELL                      SPE   109826   Reservoir Management     Modelling - Experimental Design


CHEVRON                   SPE    100656   Reservoir Management     Modelling - Experimental Design


CHEVRON                   SPE    102988   Reservoir Management     Modelling - Experimental Design


CHEVRON                   SPE     89755   Reservoir Management     Modelling - Experimental Design
BP                        SPE    101909   Reservoir Management      Modelling - Integrated Asset

CHEVRON                   SPE    102557   Reservoir Management       Modelling - Integrated Asset
SCHLUMBERGER              SPE   102557   Reservoir Management    Modelling - Integrated Asset
SCHLUMBERGER             IPTC    11594   Reservoir Management    Modelling - Integrated Asset

CHEVRON                   SPE   128335   Reservoir Management    Modelling - Integrated Asset
SHELL                    IPTC    12327   Reservoir Management    Modelling - Integrated Asset
BP                       IPTC    11751   Reservoir Management    Modelling - Integrated Asset
CONOCO                   IPTC    11115   Reservoir Management    Modelling - Integrated Asset
SHELL                     SPE   114805   Reservoir Management    Modelling - Integrated Asset
SCHLUMBERGER              SPE   100984   Reservoir Management    Modelling - Integrated Asset
SCHLUMBERGER              SPE   101491   Reservoir Management    Modelling - Integrated Asset
BP                       IPTC    11475   Reservoir Management    Modelling - Integrated Asset
SCHLUMBERGER              SPE   121489   Reservoir Management    Modelling - Integrated Asset
SCHLUMBERGER              SPE   117633   Reservoir Management    Modelling - Integrated Asset
SCHLUMBERGER              SPE   112223   Reservoir Management    Modelling - Integrated Asset
Heriot Watt University    SPE   107171   Reservoir Management    Modelling - Integrated Asset
SCHLUMBERGER              SPE    99469   Reservoir management    Modelling - Integrated Asset
SCHLUMBERGER              SPE   109260   Reservoir Management    Modelling - Integrated Asset
SCHLUMBERGER              SPE   112209   Reservoir Management    Modelling - Integrated Asset
SHELL                     SPE   102913   Reservoir Management   Modelling - Rubust Otimisation
TOTAL                     SPE   128894   Reservoir Management      Multi-layered Reservoir
SHELL                     SPE   105357   Reservoir Management    Multiple Field Development
CONOCO                    SPE   117433   Reservoir Management     Performance Evaluation
SHELL                     SPE   111922   Reservoir Management       Phased Development
SHELL                     SPE   101017   Reservoir Management      Pressure Management
SHELL                     SPE   113068   Reservoir Management      Pressure Management
BP                       IPTC    11650   Reservoir Management      Pressure Management
TOTAL                     SPE    90129   Reservoir Management     Probablistic Performance
BP                        SPE   119607   Reservoir Management              Process
SHELL                     SPE   113527   Reservoir Management              Process
BP                        SPE   112802   Reservoir Management              Process
SHELL                     SPE   118290   Reservoir Management              Process
TOTAL                     SPE   115963   Reservoir Management              Process
SHELL                     SPE   121786   Reservoir Management     Produced Water Injection
Heriot Watt University    SPE   104608   Reservoir Management     Produced Water Injection
TOTAL                     SPE   108010   Reservoir Management     Produced Water Injection

CHEVRON                  IPTC    11551   Reservoir Management   Produced Water Management
TOTAL                     SPE   111973   Reservoir Management   Produced Water Management
CONOCO                    SPE   102439   Reservoir Management   Produced Water Management
SCHLUMBERGER              SPE   102439   Reservoir Management   Produced Water Management

CHEVRON                   SPE    98567   Reservoir Management   Produced Water Management
CHEVRON                   SPE   108893   Reservoir Management   Produced Water Management
SCHLUMBERGER              SPE   116218   Reservoir Management   Produced Water Management
SHELL                    IPTC    11624   Reservoir Management   Produced Water Management
SHELL                     SPE   111997   Reservoir Management      Production Optimisation
SCHLUMBERGER              SPE   120664   Reservoir Management      Production Optimisation


CHEVRON                   SPE   116528   Reservoir Management      Production Optimisation
SCHLUMBERGER              SPE   116528   Reservoir Management      Production Optimisation
SHELL                    IPTC    11644   Reservoir Management      Production Optimisation
SHELL                    SPE    122553   Reservoir management       Production Optimisation
SCHLUMBERGER             SPE     99338   Reservoir Management      Productivity Improvement
SHELL                    SPE    119098   Reservoir Management               Real Time
BP                       SPE    123923   Reservoir Management         Recovery Optimisation
SCHLUMBERGER             SPE    107702   Reservoir Management          Reserves Evaluation
SHELL                    SPE     92795   Reservoir Management           Reservoir Souring
SHELL                    SPE    105784   Reservoir Management           Reservoir Souring
SHELL                    SPE    106178   Reservoir Management           Reservoir Souring
SHELL                    SPE    117951   Reservoir Management           Reservoir Souring
SHELL                    SPE    118798   Reservoir Management           Reservoir Souring
SHELL                    SPE    121891   Reservoir Management   Shell's Adjoint Simulation Method
SHELL                    SPE    119156   Reservoir Management   Shell's Adjoint Simulation Method
SHELL                    SPE    102389   Reservoir Management            Sour Reservoir
SHELL                    SPE    109246   Reservoir Management            Sour Reservoir

CHEVRON                   SPE   107732   Reservoir Management           Sour Reservoir
SHELL                     SPE   109011   Reservoir Management             Surveillence
SHELL                     SPE   108651   Reservoir Management             Surveillence
SHELL                    IPTC    12344   Reservoir Management            Thin Oil Rim
CONOCO                    SPE   100984   Reservoir Management            Thin Oil Rim
Heriot Watt University    SPE   115744   Reservoir Management       Uncertainty Management


CHEVRON                  IPTC   11540    Reservoir Management       Uncertainty Management


CHEVRON                   SPE   120102   Reservoir Management       Uncertainty Management
BP                        SPE   102123   Reservoir Management       Uncertainty Management
SCHLUMBERGER              SPE   103028   Reservoir Management         Value of Information
SHELL                     SPE   102310   Reservoir Management       Waterflood Management
BP                        SPE   112311   Reservoir Management       Waterflood Management
SHELL                     SPE   112940   Reservoir Management       Waterflood Management
SHELL                     SPE   105764   Reservoir Management       Waterflood Optimisation
SHELL                     SPE   123563   Reservoir Management       Waterflood Optimisation
BP                       IPTC    11276   Reservoir Management       Waterflood Performance

CHEVRON                  SPE    101028   Reservoir Management           Well Intervention
SCHLUMBERGER             SPE    108693   Reservoir Management     Well Placement Optimisation
SCHLUMBERGER             SPE    108737   Reservoir Management     Well Placement Optimisation
CHEVRON                  SPE     98198   Reservoir Management     Well Placement Optimisation
Heriot Watt University   SPE    102903   Reservoir Management     Well Placement Optimisation
Heriot Watt University   SPE     99877   Reservoir Management     Well Placement Optimisation
SCHLUMBERGER             SPE     98198   Reservoir Management     Well Placement Optimisation
SCHLUMBERGER             SPE     93444   Reservoir Management     Well Placement Optimisation
SCHLUMBERGER             SPE    110927   Reservoir Management     Well Placement Optimisation
SCHLUMBERGER             SPE    122338   Reservoir Management     Well Placement Optimisation
        Subject
      Draugen Field
       Life of Field
        Orito Field
     Selection Criteria

    Slim SMART Wells
        Case Study
        Schiehallion
        Schiehallion
     West Salym Field
         Deepwater
       ElginFranklin
   Integrated Teamwork
       Process Mode
        Thin Oil Rim
       Mature Fields

        Surveillence
        Surveillence
         Case Study
       Pecorade Field
Well Performance Analysis
      Well Placement
Well Placement Optimisation
         Sendji Field
      East Kamennoye
          Feasibility
   Wellsite Compression
         Life of Field
 Uncertainty Management
 Fractured Water Injection
  Production Optimisation
        SMART wells


 Development Optimisation
     Steam Injection


        Tahiti Field


        Tahiti Field


       Thin Oil Rim
 Development Optimisation

 Development Optimisation
Development Optimisation
  Gas Lift Optimisation

  Infill Well Performance
         Karstification
     Large Well Count
     Large Well Count
Multiple Field Development
 Production Optimisation
 Production Optimisation
  Reservoir Performance
       Steam Injection
 Uncertainty Management
          Workflow




Development Optimisation
         Life of Field
      Integrated Study
 Novel Statistical Analysis
         Case Study
Mutilayered Water Injection
       Waterflooding

   Multiple Reservoirs
      Gas Supply
      Gas Supply
     Gas to Products
           GTL
  Subsea Searation Unit
      Core Testing
  Permeability Reduction
  Permeability Reduction

   Greater Burgan Field
    Total's Approach
       XJG Fields
       XJG Fields




Automatic Process Control
  Gas Lift Optimisation


      Mature Fields
      Mature Fields
      Mature Fields
             Workflow
         Integrated Study

          Harding Field
      Lower Vicksburg Sands
           Deepwater




            Simulation
   Well Placement Optimisation
           South Oman



          Draugen Field
      Production Optimisation
     Concurrent Oil/Gas Wells
               IOR
         Completion Type


        Multiple Reservoirs


       Quantifying Uncertainty
       Russian Mature fields
             Framework
              Fractures
            October Field
   Well Placement Optimisation
odelling - Adjoint Simulation Method
        Optimised Simulation
            Valhall Field

       Candidate Selection
       LWD Interpretation
       LWD Interpretation
    Production Potential maps
    Production Potential maps
    Production Potential maps
    Production Potential maps
    Real Time Pressure Data
        Selection Criteria
          Thin Oil Rim
                                              Title
Improved Reservoir Management Through Integration of 4D-Seismic Interpretation, Draugen Field, Norway
Maximising Recovery From Mature North Sea Assets by the Implementation of Production Optimisation Initiatives
Artificial Lift Optimization in the Orito Field
Selection Criteria for Artificial Lift Technique in Bokor Field
New Technology Applications For Improved Attic Oil Recovery: The World's First Slim Smart
Completions
Assisted History Matching as a Useful Business Tool: An Example from Trinidad
Reservoir Management in a Deepwater Subsea Field--The Schiehallion Experience
Reservoir Management in a Deepwater Subsea Field--The Schiehallion Experience
Reservoir Management of West Salym Oil Field
Development of World-Class Oil Production and Water Injection Rate and High Ultimate-Recovery Wells in Deepwater Turbidit
Identifying the Optimum Development Plan for the Western Area of Elgin/Franklin in the North Sea
Key Elements of Successful Well and Reservoir Management in the Bonga Field, Deepwater Nigeria
Changing the Operation of Oil and Gas Fields From “Harvest to “Process Mode
Gannet A: Critical New Reservoir Insight Through Seamless Cross-Discipline Integration
New Life for a Mature Oil Province via the Integration of Improved Recovery Methods
Engineer Your Gas/Condensate Systems, Reservoir to Sales Meter
An Integrated Approach to Field Surveillance Improves Efficiency in Gas Lift Optimization in Bokor Field, East Malaysia
An Integrated Approach to Field Surveillance Improves Efficiency in Gas Lift Optimization in Bokor Field, East Malaysia
Converting the P�corade Oil Field Into an Underground Gas Storage
Converting the Pecorade Oil Field Into an Underground Gas Storage
Performance Analysis of Horizontal Wells for Underground Gas Storage in Depleted Gas Fields
Differentiating Well Placement Expectations in Saudi Arabia with Production from Stringer Sand Reservoirs
Implementing the Optimum Well Placement Strategy for Horizontal Injectors Drilled in Highly Heterogeneous Reservoirs of Cen
Production Optimization by Real-Time Modeling and Alarming: The Sendji Field Case
Multidisciplinary Teamwork Results in Dramatically Improved Production-East Kamennoye, Western Siberia
A Rigorous Stochastic Coupling of Reliability and Reservoir Performance When Defining the Value of Intelligent Wells
Improved Production in Low-Pressure Gas Wells by Installing Wellsite Compressors
An Integrated Computer Based Method to Maximize Infill Drilling, Sidetracking, and Workover Potential in Multiple Stacked Hyd
Enhancing Field Management in Siberia by Quantifying Production Uncertainties
Waterflooding Under Dynamic Induced Fractures: Reservoir Management and Optimization of Fractured Waterfloods
Flaring, Gas Injection and Reservoir Management Optimization: Preserving Reservoir Energy Maximizes Recovery and Prolong
Coupling a Reservoir Simulator With a Network Model to Evaluate the Implementation of Smart Wells on the Moporo Field in V
The Jurassic-Age Marrat Reservoir at Humma Field, Partitioned Neutral Zone (PNZ), Saudi Arabia
and Kuwait—Utilization of a Probabilistic, Two Stage Design of Experiments Workflow for
Reservoir Characterization and Management
Peace River Carmon Creek Project—Optimization of Cyclic Steam Stimulation Through Experimental Design

Tahiti: Development Strategy Assessment Using Design of Experiments and Response Surface
Methods


Tahiti Field: Assessment of Uncertainty in a Deepwater Reservoir Using Design of Experiments


Production Strategy for Thin-Oil Columns in Saturated Reservoirs
Screening of Field Development Options by Simulation Study To Improve Recovery From Lower Southern Units of Complex Ca

Integrated Optimization of Field Development, Planning, and Operation
Integrated Optimization of Field Development, Planning, and Operation
A New Approach to Gas Lift Optimization Using an Integrated Asset Model

A Practical Approach to Initial Production (IP) Rate Estimation for Infill Oil Wells
Integrated Modeling of Karstification of a Central Luconia Field, Sarawak
Role of Integrated Asset Modeling in Optimizing Na Kika Production
Reservoir Optimization and Monitoring: Mauddud Reservoir—Bahrain Field
The Integrated Use of New Technology in the Development of the Sakhalin II Project
Identifying the Improved-Oil-Recovery Potential for a Depleted Reservoir in the Betty Field, Offshore Malaysia
An Approach for Production Enhancement Opportunities in a Brownfield Redevelopment Plan
The Impact of Exceeding Predicted Performance in Kepler Field, Deepwater Gulf of Mexico—A Multi-Discipline Approach to U
Energy Balance in Steam Injection Projects Integrating Surface-Reservoir Systems
A Successful Process for Embracing Uncertainty and Mitigating Risk - From Geological Understanding to Development Plan O
Breaking the Barriers-The Integrated Asset Model
Successful Application of a Robust Link to Automatically Optimise Reservoir Management of a Real Field
From Reservoir Through Process, From Today to Tomorrow—The Integrated Asset Model
Integration of Production and Process Facility Models in a Single Simulation Tool
Integrated Studies on a Conveyor Belt—A New Concept of Study Workflows Based on Stochastic Principles
Robust Waterflooding Optimization of Multiple Geological Scenarios
Obagi – Present and Future Challenges of a Mature Oil Field
An Integrated Approach To Efficiently Unlock the Resource Potential in a Large Cluster of Fields
An Unconventional But Definitive Analysis of a Field's Production Improvement
Using Phased Development as Reservoir Management Technique To Improve Efficiency and Reduce Operational Cost: Ogbot
Rapid Pressure Support for Champion SE Reservoirs by Multilayer Fractured Water Injection
Reservoir Pressure Management Using Waterflooding: A Case Study
Integration of Reservoir Planning and Surveillance : History to Prediction
Partial Probabilistic Addition: A Practical Approach for Aggregating Gas Resources
Holistic Approach for Regional Depletion Plan Supporting Gas Supply in the Nile Delta of Egypt
A Global Gas Distribution Model with Transport Constraints: Methodology and Some Scenarios
The End of Stranded Gas: The Emergence of the Gas to Products (GTP) Option
Pearl GTL - Assuring Success from the Outset
Multiphase Loop Tests for Subsea Separation-Unit Development
Establishing Water Injection Dynamics by Leading-Edge Coreflood Testing
Permeability Damage Due to Water Injection Containing Oil Droplets and Solid Particles at Residual Oil Saturation
Internal Formation Damage Properties and Oil-Deposition Profile Within Reservoirs During PWRI Operations

Effluent Water Disposal Experiences in the Greater Burgan Field of Kuwait
Emerging Issues in Produced Water Management: TOTAL E&P NORGE’s Approach
Production Diagnostics and Water Control for the XJG Fields, South China Sea
Production Diagnostics and Water Control for the XJG Fields, South China Sea

Constructed Treatment Wetlands for the Treatment and Reuse of Produced Water in Dry Climates
Produced-Water Management Alternatives for Offshore Environmental Stewardship
The Integrated Approach to Formation Water Management: From Reservoir Management to Protection of the Environment
Produced Water Management: Is it a Future Legacy or a Business Opportunity for Field Development
Closing the Loop for Improved Oil and Gas Production Management
Production Enhancement for Khafji Field Using Advanced Optimization Techniques


Horizontal Well Best Practices to Reverse Production Decline in Mature Fields in South China Sea
Horizontal Well Best Practices to Reverse Production Decline in Mature Fields in South China Sea
Increasing Oil Production in a Mature Field by Rigless Intervention–A Multiwell Case Study
Shell Experiences Using Lagosa to Improve Production Operations and Gas Marketing Performance
Transforming Data Into Decisions To Optimize the Recovery of the Saih Rawl Field in Oman
Closed Loop Reservoir Management
Harding Central—Achieving 74% Recovery
A Unique Workflow for Reserves Evaluation in Lower Vicksburg Sands
Use of Nitrate To Mitigate Reservoir Souring in Bonga Deepwater Development, Offshore Nigeria
One Year Experience With The Injection of Nitrate To Control Souring in Bonga Deepwater Development Offshore Nigeria
Nitrate-Based Souring Mitigation of Produced Water—Side Effects and Challenges From the Draugen Produced-Water Reinje
Challenges in Highly Sour Gas Environment Containing Elemental Sulphur
Understanding of Oilfield Souring and Effective Monitoring: Two Cases Study
Impact of Mutual Solvent Preflush on Scale Squeeze Treatments: Extended Squeeze Lifetime and Improved Well Clean-up Tim
Automatic Well Placement Optimization in a Channelized Turbidite Reservoir Using Adjoint Based Sensitivities
Achieving the Vision in the Harweel Cluster, South Oman
Development of Highly Contaminated Gas and Oil Fields, Breakthrough CO2/H2S Separation Technologies

Improving Reserves and Production Using a CO2 Fluid Model in El Trapial Field, Argentina
Understanding a Teenager: Surveillance of the Draugen Field
The Value of Surveillance and Advanced Logging Applications for Brownfield Optimization
Concurrent Oil & Gas Development Wells: A Smart Well Solution to Thin Oil Rim Presence in Gas Reservoirs
Identifying the Improved-Oil-Recovery Potential for a Depleted Reservoir in the Betty Field, Offshore Malaysia
Impact of Reservoir Uncertainty on Selection of Advanced Completion Type


Modeling Uncertainties of a Gas

Quantifying Uncertainty in Carbonate Reservoirs—Humma Marrat Reservoir, Partitioned Neutral
Zone (PNZ), Saudi Arabia and Kuwait
Russian Mature Fields Redevelopment
Better Valuation of Future Information Under Uncertainty
Application of Smart, Fractured Water Injection Technology in the Piltun-Astokhskoye Field, Sakhalin Island, Offshore Russia
Environmentally Friendly and Economic Waterflood System for October Field at Gulf Of Suez, Egypt
The Omar Field (N.E. Syria) is Overcoming Its Mid-Life Crisis
Optimal Waterflood Design Using the Adjoint Method
Optimization of Smart Wells in the St. Joseph Field
Reservoir Management Aspects of Early Waterflood Response After 25 Years of Depletion in the Valhall Field
Using Neural Networks for Candidate Selection and Well Performance Prediction in Water-Shutoff
Treatments Using Polymer Gels—A Field Case Study
Latest Generation Horizontal Well Placement Technology Helps Maximize Production in Deep Water Turbidite Reservoirs
Brenda Field Development: A Best Practice in Horizontal Well Placement Leading to Optimal Reservoir Drainage
Closing the Loop Between Reservoir Modeling and Well Placement and Positioning
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
Closing the Loop Between Reservoir Modeling and Well Placement and Positioning
Using Real-Time Pressure Data for Well Placement Planning
Unlocking the Potential of Mature Fields - An Innovative Filtering and Analysis Approach to Identify Sidetracking Candidates in
Optimizing Horizontal Well Placement and Reservoir Inflow in Thin Oil Rim Improves Recovery and Extends the Life of an Agin
                                Author                                      Abstract
                                                                         Summary 4D-seismic
P.L. Mikkelsen, SPE, Consultant; K. Guderian, SPE, Norske Shell; and G. du Plessis, StatoilHydro interpretation plays a key ro
Masud J. Akhtar, SPE, Total E&P UK Limited                               Abstract Oil was first discovered in the North Sea
                                                                         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
                                                                         Abstract As production Sdn Bhd, and Patrick von
Mahmoud A. Wahba, Maharon Jadid, Ibrahim B. Subari, and M. Nazli B. Abu Talib, Petronas Carigalideclines and watercut incr

                                                                             Abstract Smart completions passive inflow contro
Stig Lyngra, SPE, Abdulkareem M. Al-Sofi, SPE, Uthman F. Al-Otaibi, SPE, Mohammed J. Alshakhs, SPE, and Ahmad A. Al-A
                                                                             Abstract The goal
Greg J. Walker, Molyama Kromah, Hung Pham, Deji Adeyeye, Arlene Winchester, SPE, BP of all history matching for the res
                                                                             Summary The Schiehallion field has experienced
Alastair Govan, SPE, Tim Primmer, Cameron Douglas, SPE, Neil Moodie, Merv Davies, and Ferry Nieuwland, SPE, BP
                                                                             Summary The Schiehallion field has experienced
Alastair Govan, SPE, Tim Primmer, Cameron Douglas, SPE, Neil Moodie, Merv Davies, and Ferry Nieuwland, SPE, BP
                                                                             Abstract The West Salym oil
Dmitry Svirsky, Ad Hagelaars, Joost Zegwaard and Howard Mackay, Salym Petroleum Development N.V. field in West Siberia
                                                                             Summary Bonga field in Offshore Nigeria produc
                                                                                         Bonga Van deepwater Nigeria
Solomon O. Inikori, SPE, and Bert Coxe, Shell E&P Technology, and Ebenezer Ageh and JaapField,Der Bok, Shell Nigeria E&P
                                                                             Abstract The Western Area Development plc
P. Naylor, RPS Energy; J. Cutler, Total E&P U.K. plc; M.K. Denham, RPS Energy; and P.C.D. Ribeiro, Total E&P U.K. (WAD) in
                                                                             Abstract Production from the deepwater Bonga tu
S. Sathyamoorthy, O. Olatunbosun, D. Sabatini, U. Orekyeh, and E. Olaniyan, Shell Nigeria Exploration & Production Company
Ron Cramer, Shell Global Solutions, and George Joel Rodger, P.E., WeatherfordAbstract In the O&G industry the nature of well an
Joanne de Jonge and Jakko van Waarde, Shell UK                               Abstract The thin oil rim of the Gannet-A turbidite
                                                                             Abstract Breathing A. Presser, a mature Energia
W. Gaviria, SPE, and J.G. Flores, SPE, Schlumberger, and J. Lorenzon, SPE, J.L. Alvarez, and new life intoPetrobras oil field is
Shah Kabir, Chevron Energy Technology Company                                Abstract Exploitation of gas/condensate reservoirs
                                                                             and G. Bakar, SPE, Petronas Carigali; and J. Liew
G. Kartoatmodjo, R. Strasser, and F. Caretta, SPE, Schlumberger; M. Jadid Abstract Proper fieldwide production surveillance
                                                                             and G. Bakar, SPE, Petronas Carigali; and J. Liew
G. Kartoatmodjo, R. Strasser, and F. Caretta, SPE, Schlumberger; M. Jadid Abstract Proper fieldwide production surveillance
Philippe Coffin and Genevi�ve Lebas / TOTAL                                Abstract The need for additionnal Underground Ga
Philippe Coffin and Genevi�ve Lebas, TOTAL                                 Summary The need for additional underground ga
                                                                             Corporation
A. Suat Bagci, Heriot-Watt University, and Bulent Ozturk, Turkish Petroleum Abstract Underground gas storage is a common ac
                                                                             Abstract Saudi Arabia is blessed with the world’
Phil Warran, SPE, Nidal Mishrafi, SPE, and Saleh M. Dossari, SPE, Saudi Aramco; Parvez J. Butt, SPE, Mohan Javalagi, and W
                                                                             Abstract Targeting thin sand bodies while drilling a
Abdel Nasser Abitrabi B., Ali Rabba, Waleed Amoudi, and Abdallah M. Behair, Saudi Aramco; M. Javalagi, W. Al-alqum, P. But
                                                                             Summary Digital technologies and Pierre Valette,
Jacques Danquigny, Renaud Da�an, Marc Tison, and Ronald Herrera, TOTAL; and Alain-Serge Ndombi can improve oil pro
                                                                             Abstract The Vikulov formation in and J. Housma
D.J. Mack, SPE, and M.R. Bitter, Marathon Oil Co.; R. Galchenko and V. Meyer, KMNGG (now with Marathon);the Tyumen Dis
G.H. Aggrey and D.R. Davies, Heriot-Watt University                          Abstract Long term equipment reliability frequently
N. Behl, K.E. Kiser, and J. Ryan, Schlumberger IPM                           Abstract Production from low-pressure gas wells
                                                                             Abstract A novel workflow methodology and Faus
Torsten Friedel, Ramiro Trebolle, Stephen Flew, William Belfield, Juergen Meyer, Charles Curteis, Nalom Syaifullah, that cover
                                                                             Abstract An analysis of production
D.E. Tipping, SPE, and M.N. Deschenya, TNK-BP, and F. Deimbacher, SPE, and D. Kovyazin, Schlumberger data from a Low
                                                                             Abstract It is well B.V., J.D. Jansen, Delft Univers
P.J. van den Hoek, R. Al-Masfry, and D. Zwarts, Shell International Exploration and Productionestablished within the Industry th
                                                                             Abstract Reservoir Schlumberger a standard ind
J. Moreno, A. Badawy*, G. Kartoatmodjo, H. AlShuraiqi, F. Zulkhifly, L. Tan, and T. Friedel, SPE,management is * PETRONAS
                                                                             Abstract Pursuing new alternatives to develop and
A. Alvarez, E. Guerra, A. Gammiero, C. Velasquez, J. Perdomo, and R. Hernandez, PDVSA, and�N. Rodriguez and�M. In
W. Scott Meddaugh, SPE, Chevron Energy Technology Company; David
Barge, SPE, Saudi Arabian Chevron; and W.W.�(Bill) Todd, SPE, and
Stewart Griest, Chevron Energy Technology Company                            Abstract The Jurassic-age Humma Marrat carbona
                                                                             Abstract Peace River Carmon Creek is a 100% Sh
Paul Frantisek Koci, SPE, and Junaid Ghulam Mohiddin, SPE, Shell International E&P
P.E. Carreras, SPE, Chevron Energy Technology Co., and S.E. Turner,
SPE, and G.T. Wilkinson, SPE, Chevron North America Exploration and
Production Co                                                                Abstract Tahiti field in deepwater Gulf of Mexico i
P.E. Carreras, SPE, and S.G. Johnson, SPE, Chevron Energy Technology
Co.; and S.E. Turner, SPE, Chevron North America E&P Co., Chevron
Corp.                                                                        Abstract Tahiti prospect in deepwater Gulf of Mex

C.S. Kabir, SPE, Chevron Energy Technology Company; M. Agamini, SPE,
Chevron Nigeria Limited; and R.A. Holguin, SPE, Chevron North America Summary Maximizing oil recovery in thin and ultra
Zahid Bhatti, Shahin Negahban, and Mohamed Shuaib, ADCO               Abstract Major contribution to oil production has be

B. Gűyagűler, SPE, Chevron, and K. Ghorayeb, SPE, Schlumberger            Abstract Field management (FM) is the simulation
B. Gűyagűler, SPE, Chevron, and K. Ghorayeb, SPE, Schlumberger             Abstract Field management (FM) is the simulation
                                                                             Abstract
Fernando Gutierrez, Aron Hallquist, Mack Shippen and Kashif Rashid, Schlumberger One of the most common methods of incr
Obor Eruvbetine, Olufemi Odusote, Inegbenose Aitokhuehi, Moses Imogu,
and Oyie Ekeng, Chevron Nigeria Ltd.                                         Abstract Asset development teams have the respo
M. Kosters, P.F. Hague, R.A. Hofmann, and B.L. Hughes, Sarawak Shell Berhard Abstract It is well established that some of the car
                                                                             Abstract BP uses Integrated Asset Models (IAM) in
B. Arias, SPE, A. Chitale, SPE, S. Bishop, SPE, A. Carroll, SPE, J. Colbert, SPE, D. Braaten, SPE; BP America, A. Al-Ameri, A
                                                                             Abstract Ayda Abdulwahab, BAPCO
Ali E. AL-Muftah, BAPCO; William Vargas, PETE Schlumberger, Huston; CRK Murty,For a matured oil field like Bahrain Field w
                                                                              and Pius Cagienard, Shell E&P the world’s la
Mike Gunningham and Chris Varley, Sakhalin Energy Investment Company, Abstract The Sakhalin II ProjectServices (RF) B.V
                                                                             Abstract A reservoir Bhd.; andE. Kasap*, S. Yuso
T. Friedel, SPE, Schlumberger; G.J. Sanza, M.I. Ali, and A. Embong, SPE, Petronas Carigali Sdn simulation model calibrated w
                                                                             Abstract Betty is an oil field discovered in Kasap a
Antonio Cuauro, SPE, Schlumberger, Mohd Izat Ali, Maharon Bin Jadid, SPE, Petronas Carigali Sdn. Bhd.; and Ekrem 1968 an
D.W. Schott, SPE, N. Bassett, and P.G. Belvedere, BP America                 Abstract Kepler Field is located in Mississippi Cany
E. Valbuena, J.L. Bashbush, and A. Rincon, Schlumberger                      Abstract Steam injection projects consume consid
                                                                             Abstract Schlumberger and studies aim at synerg
Emad Elrafie, Isabelle Zabalza-Mezghani, Tariq Abbas, Saudi Aramco, Yakov Kozlov,Integrated reservoir Roderick Craghill, Pa
                                                                             Abstract The objective Al-Kinani, Richard Torren
�ystein Tesaker, Alf Midtb� �verland, and Dag Arnesen, StatoilHydro; Georg Zangl, Andreasof this paper is to highlight
                                                                             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 Simulation technology from Information
A. Howell, Schlumberger Information Solutions; M. Szatny, Aspen Technology Inc.; and R. Torrens, Schlumbergerreservoir thr
                                                                             Abstract Traditionally in PEMEX
Fernando L. Morales and Juan Cruz Vel�zquez, Schlumberger, and Aar�n Garrido Hernandez, the upstream business op
T. Graf, R. Dandekar, and C. Amudo, SPE, Schlumberger                        Abstract With multi-processor cluster computing m
                                                                             Summary Dynamic optimization of waterflooding u
G.M. van Essen, SPE, M.J. Zandvliet, SPE, P.M.J. Van den Hof, and O.H. Bosgra, Delft University of Technology; and J.D. Jan
                                                                             Abstract E&P Nigeria
N. Guillonneau, G. Fontaine, J.Y. Gory, S. Iwuoha, H. Ahmed, D. Ekpenyong, TOTAL OBAGI is an onshore oil field located on
                                                                               Bulushi, Andres E. Cerutti, Madelon P.Y. Nijman,
Martin A. Kraaijveld, Jon B. Hognestad, Ajay Samantray, Pius Udeh, WaleedAbstract An integrated study on a cluster of 23 fiel
R. Schulz and L. Harms, ConocoPhillips                                       Abstract Production results from capital or operati
                                                                             Abstract The search for optimal development of a
Abu Ikponmwosa, Reservoir Engineer, Shell Petroleum Development Company, Port Harcourt
                                                                             Summary The Champion field is a large oil field of
Gerald Sommerauer, SPE, and Christoph Zerbst, SPE, Brunei Shell Petroleum Co. Sdn. Bhd.
                                                                             Abstract Ltd.
Anish Phade, SPE, Reliance E&P; and Yash Gupta, SPE, Shell Technology India Pvt. As a rule the reservoir pressure depletio
Greg J. Walker, Simon R. Bishop, Glyn J.J. Williams, Chris Reddick, SPE, BP  Abstract The concept of depletion planning covers
Pierre Delfiner, SPE, and Robert Barrier, Total                              Summary The portfolio of gas sources to supply a
Mohamed Samy M. Hussien, BP Egypt                                            Abstract This paper shows practical example in th
                                                                             Abstract Natural gas resources are unevenly distrib
J.T. van Berkel and L.P. Roodhart, SPE, Shell International Exploration and Production
Theo H. Fleisch, BP                                                          Abstract The world has an abundant supply of low
Andy Brown, Qatar Shell GTL Limited                                          When completed Pearl GTL will be the world’
                                                                              TOTAL
P. Pagnier, C. No�k, and P. Maurel, IFP, and A. Ricordeau and J.L. Volle,Abstract As flow assurance is a critical point challe
                                                                             R.A. Hofland, Shell International of water being P
L. Costier*, P.J. van den Hoek, C. Davidson, Mei Ding, J.T.M. vanden Berg, Abstract The increasing amountsExploration and pr
                                                                             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
                                                                              Total E&P
Jalel Ochi, Pascal Rivet, Jean-Claude Benquet, and Jean-Louis D�tienne,Abstract To predict correctly injectivity for Produce
Hamad Al-Ajmi, SPE, Issa Al-Jadi, SPE, Feras Al-Ruhaimani, SPE, Kuwait
Oil Company; Wahyu Budiarto, SPE, Chevron                                    Abstract This paper presents the process of candid
                                                                             Abstract The E&P Norge AS
Pierre Goud, Stig Helland, Alexandre Goldszal, Ulf E. Moltu, and Laurence Pinturier, Total Norwegian Continental Shelf (NCS)
                                                                             Abstract The China National Offshore Oil Corporat
Zhizhuang Jiang and Zhang Tao, ConocoPhillips, China Inc., and Khong Chee Kin and Robert North, Schlumberger China Inc.
                                                                             Abstract The China National Offshore Oil Corporat
Zhizhuang Jiang and Zhang Tao, ConocoPhillips, China Inc., and Khong Chee Kin and Robert North, Schlumberger China Inc.

N. Nijhawan and J.E. Myers, Chevron Corp.                                 Abstract When water is scarce its value increase
Akshay Sahni, Chevron and Steven T. Kovacevich, Chevron Corp.             Abstract As the hydrocarbon production in the Gul
                                                                          Abstract Pablo Espinel, AGIP Oil Ecuador, water
Jose G. Flores, SPE, and Jon Elphick, SPE, Schlumberger, and Francisco Lopez andThe production of large volumes of an EN
                                                                          Abstract The volume of produced water worldwide
Zara Khatib, Technology Marketing Manager, Shell International, ME, Caspian and South Asia
                                                                          Abstract Willem van Lienden, Petroleum Develop
Freek van Dijk and Keat Choon Goh, Shell Global Solutions International BV, and Jan Well and Facility Operations make opera
                                                                          Abstract The
M.A. Al-Khaldi and E.O. Ghoniem, Al-Khafji Joint Operations, and A.A. Jama, Schlumbergergas lift by limited capacity of 25 MM
You Hongqing, Wei Ping, Tian Xiang, Xu Xiang Dong, Lian JiHong, Thanh
Tran, Yoseph J. Partono : CACT, Jeffrey Kok, Liu Yang, Sarfraz Balka:
Schlumberger                                                              Abstract The Huizhou 6S and 3S oil fields in the Pe
                                                                          Abstract The Huizhou 6S and 3S oil fields in Liu Ya
You Hongqing, Wei Ping, Tian Xiang, Xu Xiang Dong, Lian JiHong, Thanh Tran, Yoseph J. Partono : CACT, Jeffrey Kok, the Pe
                                                                          Abstract
Vivek Garg, ONGC Ltd., Shubhranshu Ashesh, Kapil Seth, Amit Govil, Schlumberger Reviving production from brown fields is
John D. Hudson, Shell Global Solutions (US), Inc.                             Abstract The promise of improved production perf
                                                                              Abstract This
G.C. Dozier, SPE, Schlumberger, and P. Giacon, SPE, Petroleum Development of Oman paper will illustrate the collaborative
                                                                              (DUT); S.D. Douma, SPE, and management SPE
J.D. Jansen, SPE, Shell Intl. E&P (SIEP) and Delft University of Technology Abstract Closed-loop reservoir D.R. Brouwer, is a c
P. Zhang and S. Green, BP                                                     Abstract Harding Central is a high permeability tur
                                                                              Abstract Palacio, Schlumberger Data workflow fo
Li Fan, Ronald B. Martin, Baljit Sehbi, Keith W. Owen, W.K. Atwood, and Juan Carlos This paper presents a uniqueand Consult
                                                                              Summary Jean Christophe Noirot, in deep water
Cor Kuijvenhoven, SPE, Andrew Bostock, and Dave Chappell, Shell Intl. E&P B.V., andThe Bonga field located SPE, and Arfa
                                                                              Abstract The Bonga field which is located in Nige
Cor Kuijvenhoven, SPE, Shell Intl. E&P B.V., and Jean Christophe Noirot, SPE, Paul Hubbard, and Lukman Oduola, Shell deep
                                                                              Aquateam A/S; C. Kuijvenhoven, SPE, Shell Intl. E
E.A. Vik, SPE, A.O. Janbu, F. Garshol, L.B. Henninge, and S. Engebretsen, Abstract� Currently the application of nitrate/ni
Magdy Girgis, Shell Global Solutions                                          BACKGROUND To compete with more convention
                                                                              Abstract In the X oilfield Sultanate Oman, water
Ardian Nengkoda, Musallam Mandhari, Mohammed Hajri, Hilal Barhi, and Liali Qasmi, Petroleum Developmentof Omanand Ro
                                                                              Abstract The most common
O. Vazquez, SPE, E. Mackay, SPE, K. Sorbie, SPE, Heriot-Watt University and M. Jordan, SPE, Nalco method for preventing
                                                                              Abstract Economic constraints impose
David Casti�eira, Faruk O. Alpak, and Detlef Hohl, SPE, Shell International Exploration and Production Inc. usdc stringent lim
                                                                               Oman
M. O'Dell, SPE, H. Soek, SPE, and S. van Rossem, Petroleum DevelopmentAbstract With high GOR and sour gas in South Om
Theo Klaver, Shell Global Solutions International BV                          Abstract Description Shell Global Solutions Intern
M.A. Crotti, Inlab S.A.; Gustavo Fernandez, Chevron Argentina; and Martin
Terrado, Chevron Energy Technology Co.                                        Abstract The El Trapial field is a 1.2 B bbl OOIP as
                                                                              Abstract Production from
K. Langaas, SPE, A.D. Grant, N.A. Horvei, A. Cook, H.M. Klokk, and K.B. Flatval, SPE, Norske Shell Draugen started in 1993
                                                                              Abstract and Zouhir Zaouali, SPE, Schlumberger
Bababola Akiode, Vikas Bhushan, and Robert Lee, SPE, Shell UK, and Parijat MukerjiThere has been a tremendous growth in
                                                                              Abstract For a number
Sascha van Putten, SPE, and Marc Naus, SPE, Shell International Exploration and Production B.V. of gas supply projects feed
                                                                              Abstract A reservoir Bhd.; andE. Kasap*, S. Yuso
T. Friedel, SPE, Schlumberger; G.J. Sanza, M.I. Ali, and A. Embong, SPE, Petronas Carigali Sdn simulation model calibrated w
                                                                              Abstract 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
D.F. Frizzell, M.J. Sibley, B. Cotner, S.P. McCartney, G.R. Schmidt, SPE,
and R. Burkes, AICHE; J.C. Phelps, SEG, Chevron; and M. Tosdevin, and
J. Mazloom, SPE, Sasol Petroleum International                                Abstract A primary objective of any project evaluat
W. Scott Meddaugh, SPE, and Stewart Griest, Chevron Energy
Technology Company, Houston, TX, and David Barge, SPE, Saudi Arabian
Chevron, Houston, TX                                                          Abstract The Jurassic-age Humma Marrat carbona
Miljenko Cimic, SPE, TNK-BP Management                                        Abstract Redevelopment of mature oil fields is bec
                                                                              Abstract In conditions of high Bailey, SPE, B. and
M. Prange, SPE, Schlumberger-Doll Research; M. Armstrong, SPE, Cerna, Ecole des Mines de Paris; W. demand for rigs Coue
                                                                              Abstract This paper discusses
D.J. van Nispen, SPE, J. Hunt, SPE, A. Hartwijk, and A. Trofimov, SPE, Sakhalin Energy Investment Co. the application of n
                                                                              Abstract October field is one of the major fields in G
Mamdouh M Ibrahim (Gupco), James W Styler (BP), Hesham L Shamma (BP),Mamdouh A Elsherif (Gupco), Essam M AboEla
                                                                              Abstract With an approximate STOIIP of 760 MMb
J. Neidhardt, H. Farran, I. Gonzalez, and P. Vledder, Shell Syria; and Y. Doughry, Al Furat Petroleum Company
                                                                               TNO Built Environment problem how to operate
J.F.B.M. Kraaijevanger, Shell Intl. E&P B.V.; P.J.P. Egberts and J.R. Valstar,Abstract We address theand Geosciences; and H.t
                                                                              Abstract The St. Joseph field has been on produc
G.M. van Essen, SPE, Delft University of Technology (TU Delft); J.D. Jansen, SPE, TU Delft and Shell International Exploration
G. Tjetland, SPE, T.G. Kristiansen, SPE, and K. Buer, BP Norway               Abstract Valhall is a fractured chalk reservoir in the
A. Saeedi, SPE, Chevron Corp., and K.V. Camarda and J.T. Liang, SPE,
The U. of Kansas                                                              Abstract Using actual field cases a neural-networ
Raphael Altman, Paolo Ferraris, and Fabricio Filardi, Schlumberger            Abstract This account describes how advanced w
                                                                              Abstract Skinner, SchlumbergerData & Consulting
Ken Halward, Joe Emery, and Rod Christensen, Oilexco; Daniel Bourgeois and Grant In 2006 Oilexco North Sea Limited deve
N. Liu, Chevron ETC, and Y. Jalali, SPE, Schlumberger                         Abstract We present a methodology of converting
                                                                              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
N. Liu, Chevron ETC, and Y. Jalali, SPE, Schlumberger                         Abstract We present a methodology of converting
                                                                              Abstract C.L. placement decisions are routinely m
M. Parker, Kerr McGee; R.N. Bradford, Callon Petroleum; and C. Corbett, R.N. Heim, Well Isakson, S.S. Broome, and E. Proa
                                                                              Abstract
Patrick W. von Pattay, SPE, Jeff Hamer, SPE, and Ralf Strasser, SPE, Schlumberger This paper presents an innovative filterin
                                                                              Abstract Magna Bela,* H. AlShuraiqi,** J.C. Moren
G. Kartoatmodjo, C. Bahri,* A. Badawy,* N. Ahmad, J. Moreno, B. Wu, F. Zulkhifly, S. Planning of infill drilling in oil rim reservoi
 c interpretation plays a key role in the reservoir management of the Draugen field situated offshore Norway. High-quality time-lapse seismic
  discovered in the North Sea in the 1970’s and some of platforms that were erected during that era are still producing albeit the productio
 ld located in the South of Colombia near the Ecuadorian border has been in production since 1967 and is operated by the Colombian state
 on declines and watercut increases wells are often converted from gas lift to electrical submersible pumps (ESPs).� ESPs are an attracti

pletions passive inflow control devices (ICD) and maximum reservoir contact wells (MRC) are some of the more recent technology advancem
 all history matching for the reservoir models is to generate accurate predictions. There is also an assumption that a better history match shou
 hallion field has experienced many reservoir management challenges since first production in 1998. Dynamic data such as formation pressu
 hallion field has experienced many reservoir management challenges since first production in 1998. Dynamic data such as formation pressu
  alym oil field in West Siberia is a new development recently brought on stream in this mature petroleum basin. The field contains some two b
eld, Offshore Nigeria
n Area Development (WAD) involves the Glenelg and West Franklin undeveloped discoveries which are located in the UKCS Central Graben
  rom the deepwater Bonga turbidite reservoirs was started in November 2005. As with all waterflood and Enhanced Oil Recovery schemes â
  industry the nature of well and reservoir operations are slowly but relentlessly changing. The traditional operations sequence of events is to
 rim of the Gannet-A turbidite field in the Central North Sea has been produced since 1993 though 11 long horizontal wells supported by a str
 ew life into a mature oil field is a challenge that has been facing national and private oil companies for almost as long as the oil industry has b
   of gas/condensate reservoirs presents considerable challenge from day-to-day reservoir-management's perspective. Initially uncertainty an
dwide production surveillance for artificial lift is critical in brown field operations to ensure optimum field production and efficiency. Using appr
dwide production surveillance for artificial lift is critical in brown field operations to ensure optimum field production and efficiency. Using appr
 r additionnal Underground Gas Storage (UGS) in Europe and in France is increasing. TOTAL has therefore undertaken feasibility studies to
 for additional underground gas storage (UGS) in Europe and in France is increasing. TOTAL has therefore undertaken feasibility studies to c
 d gas storage is a common activitity in countries with major transport and distribution gas pipeline infrastructures which allows to efficiently r
 a is blessed with the world’s largest onshore and offshore reservoirs. Currently Saudi Aramco is aggressively pursuing production increm
hin sand bodies while drilling across heterogeneous sandstone reservoir is a major challenge that requires integrated reservoir engineering f
 hnologies can improve oil production and reduce operating costs. In this prospect TOTAL launched a corporate program called Field Monito
   formation in the Tyumen District of southwestern Siberia consists of incised-valley deposits and shallow-marine delta-front sands which for
equipment reliability frequently controls the Value created by Intelligent Well Technology. One of the barriers to intelligent well deployment is t
  from low-pressure gas wells was improved by widespread/extensive installation of well site compression in the Waddell Ranch Project. The
 kflow methodology that covers the entire cycle of field development maximizes the production potential and can increase reserves in stacked
  of production data from a Lower Cretaceous western Siberia oilfield operated by TNK-BP suggested that the final recovery factor would not
 ablished within the Industry that water injection mostly takes place under induced fracturing conditions. Particularly in low-mobility reservoirs
management is a standard industry practice to maximize oil recovery; however in mature fields the full potential is often not realized. Unlike g
  w alternatives to develop and produce sands B1 and B4 together belonging to the reservoir VLG-3729 of Moporo Field located in western V


c-age Humma Marrat carbonate reservoir is mainly located in the southwest corner of the Partitioned Neutral Zone (PNZ) between Saudi Ara
 Carmon Creek is a 100% Shell owned ultra-heavy oil lease located in north-western Alberta Canada approximately 700 km northwest of E


 n deepwater Gulf of Mexico is a three-way anticlinal structure trapped against salt with primary hydrocarbon-bearing turbidite sands ranging


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


g oil recovery in thin and ultrathin (< 30 ft) oil columns is a challenge because of coning or cresting of unwanted fluids regardless of well orie
bution to oil production has been mostly from the highly prolific upper Southern units in a giant complex carbonate reservoir in the middle-eas

gement (FM) is the simulation workflow through which predictive scenarios are carried out to assist in field development plans surface facility
gement (FM) is the simulation workflow through which predictive scenarios are carried out to assist in field development plans surface facility
most common methods of increasing production in oil fields is through the continuous injection of lift gas into the tubing.� The injected gas

 opment teams have the responsibility of identifying evaluating and executing infill well opportunities. In maturing these projects realistic fore
 ablished that some of the carbonate fields in the Central Luconia Gas Province Sarawak Malaysia have been subjected to karstification as
egrated Asset Models (IAM) in many of its producing assets to improve its understanding of field performance to predict fluid flow behavior t
ed oil field like Bahrain Field with a long production history it is required to identify underperforming areas infill wells and upgrade the reserve
  n II Project the world’s largest E&P project is currently developing 2 oil and gas fields offshore Sakhalin Island off the east coast of ma
 simulation model calibrated with 25 years of production history was used to determine a cost effective reservoir management and productio
oil field discovered in 1968 and produced since 1978. With the objective of rejuvenating the asset a multidisciplinary optimization team was b
  is located in Mississippi Canyon Block 383 in 5400’ water depth approximately 140 miles southeast of New Orleans Louisiana USA (F
 tion projects consume considerable amounts of energy to generate steam.�� Understanding where the heat goes at various times and
eservoir studies aim at synergizing all disciplines to form a reservoir understanding and best strategy to field development. Handling uncertain
ve of this paper is to highlight the necessary steps for the successful use of integrated asset modeling. It presents the full workflow for optimz
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
 technology from reservoir through process facility has advanced so much that field development strategies can be developed within a new
  in the upstream business operational decisions are made separately at the reservoir production and surface facility levels using only their r
processor cluster computing modular stochastic workflows and a dedicated project team the turn-around time for project execution has been
  ptimization of waterflooding using optimal control theory has significant potential to increase ultimate recovery as has been shown in various
n onshore oil field located on OML58 85 km north-west of Port-Harcourt Nigeria. It is composed of 26 stacked reservoir levels with an estim
ed study on a cluster of 23 fields in South Oman was performed in the Petroleum Development Oman (PDO) Study Center in order to derive
results from capital or operational investments are often difficult to identify and quantify due to a field’s decline and other factors that intro
  for optimal development of a field involves proper knowledge and implementation of Reservoir management techniques. Drawing from the e
  pion field is a large oil field offshore Negara Brunei Darussalam. This paper discusses the (for us) novel application of water injection-induce
  e reservoir pressure depletion occurs with a continuous production over a period of time. This leads to high Gas-Oil Ratio and low productio
   of depletion planning covers a variety of time scales and levels of investment and has to cope with a level of risk in outcome that the operat
 lio of gas sources to supply a liquefied-natural-gas (LNG) project may involve many diverse fields each with its range of uncertainty and deg
shows practical example in the direction of building “holistic regional depletion plan by applying “fully holistic and “fully probabilisti
 resources are unevenly distributed around the world. Will we be able to grow transport capacity sufficiently quickly to transfer ever-increasing
 as an abundant supply of low cost natural gas in remote locations. The monetization of these stranded gas resources requires new technolo
 arl GTL will be the world’s largest GTL plant. It is the single largest energy project within the borders of Qatar as well as Shell’s larg
urance is a critical point challenging offshore field development led TOTAL and IFP to manage a large R&D program on multiphase flow beh
 ng amounts of water being produced from oilfields and the increasing need or necessity to return it to the reservoir it ori-ginated from are po
   of produced water is of increasing importance as water cuts continue to increase worldwide. It provides an environmentally acceptable solu
 orrectly injectivity for Produced Water Re-Injection (PWRI) a good description of the formation damage by oil and solid particles have to be

 resents the process of candidate well selection design execution and evaluation that lead to the successful implementation of acid fracturin
gian Continental Shelf (NCS) is subject to stringent requirements regarding offshore discharges. Focus has previously been on dispersed oil
National Offshore Oil Corporation (CNOOC) Shell and ConocoPhillips China Inc. (COPC) are partners in the development of the XJG oil fie
National Offshore Oil Corporation (CNOOC) Shell and ConocoPhillips China Inc. (COPC) are partners in the development of the XJG oil fie

 r is scarce its value increases. Produced water is the largest byproduct in oil and gas production and as a field matures the ratio of water
ocarbon production in the Gulf of Thailand has matured managing associated produced water has become a focus of attention. Produced w
 on of large volumes of water is common in wells producing from strong aquifer reservoirs such as most of the fields in the Oriente basin of E
 of produced water worldwide from O&G industry is still increasing at a fast rate about 10% per year. The Water to Oil ratios ranged from <1
acility Operations make operating decisions based on processing huge amounts of data.� However there is a practical limit to the number
 t by limited capacity of 25 MMSCF/D was introduced for Khafji field in 1988 which could successfully sustain target rate until mid of 2004. A


u 6S and 3S oil fields in the Pearl River Basin Offshore South China Sea are mature fields which have produced 40% to 60% of their origina
u 6S and 3S oil fields in the Pearl River Basin Offshore South China Sea are mature fields which have produced 40% to 60% of their origina
oduction from brown fields is a major focus of activity for oil and gas companies. This paper outlines the workflow and procedures adopted to
e of improved production performance and consistent delivery against market and regulatory commitments is driving the need for better deci
 will illustrate the collaborative approach taken by an integrated team (operator and service company) charged to demonstrate within a one-
  reservoir management is a combination of model-based optimization and data assimilation (computer-assisted history matching) also refer
ntral is a high permeability turbidite reservoir in the Central North Sea.� It has been produced with water injection for pressure support and
presents a unique workflow for gas reserves evaluation in fields with commingled production from several low permeability reservoirs. The w
a field located in deep water off the Nigerian coast needs pressure support to effectively recover hydrocarbons. The strategy is to inject 300
field which is located in deep water off the Nigerian coast started oil production at the end of 2005. In order to sustain production seawater
 y the application of nitrate/nitrite is considered one of the most promising souring mitigation solutions during Produced Water Re-Injection (P
ompete with more conventionally produced gas wet sour gas is transported from the well head to the gas sweetening units in carbon steel p
eld Sultanate of Oman water has been injected since June 2001 for EOR purposes. The water supply sources was used through 4 dedicate
 mmon method for preventing scale formation is by applying a scale inhibitor squeeze treatment. In this process a scale inhibitor solution is i
onstraints impose stringent limits on the number of wells that can be drilled in deepwater developments. Thus optimal placement and opera
 OR and sour gas in South Oman re-injection schemes were considered for the recently discovered reservoirs of the Harweel Cluster in Sou
  Shell Global Solutions International B.V (“Shell)[1] has been involved for many years in the development of new technologies to separat

 al field is a 1.2 B bbl OOIP asset located onshore in Argentina South America. The field was discovered in 1991. Water injection started in 1
 rom Draugen started in 1993. In its 14th year Draugen faces declining oil and increasing water production and is around halfway in its produ
been a tremendous growth in the number of high-angle and horizontal wells in the past decade. Coupled with the increase in water cut from v
 er of gas supply projects feeding LNG export schemes there exists a challenge that key gas reservoirs have associated underlying oil rims.
 simulation model calibrated with 25 years of production history was used to determine a cost effective reservoir management and productio
mance prediction is a key Petroleum Engineering task. However large discrepancies between Petroleum Engineering models and reality still


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


c-age Humma Marrat carbonate reservoir was discovered in 1998. Eleven wells have been drilled to date including several horizontal comple
ment of mature oil fields is becoming increasingly important in Russia and worldwide. An extensive application of new ideas coupling reservo
  of high demand for rigs and other scarce equipment it may be appropriate and more advantageous for a client to agree to a forward contra
discusses the application of new technologies and surveillance requirements with particular reference to fractured waterflood developments
d is one of the major fields in GOS Egypt operating at 100 000 BFPD using 185 MMSCF gas lift injection gas though 50 active producing wel
roximate STOIIP of 760 MMbbls the Omar field is the largest field in Al Furat Petroleum Company's portfolio. The field – located in the Eu
 the problem how to operate the injectors and producers of an oil field so as to maximize the value of the field. Instead of agressively produc
eph field has been on production since September 1981 under natural depletion supported by crestal gas injection. As part of a major redeve
ractured chalk reservoir in the Norwegian sector of the North Sea which has been producing under compaction drive since 1982. Continuous

 l field cases a neural-network model was developed to identify candidate wells and predict well performance for water shutoff treatments us
nt describes how advanced well placement technology helped to optimize horizontal well position and maximize hydrocarbon production in de
exco North Sea Limited developed the Brenda field in the Central North Sea. A total of over 8000 ft of horizontal section has been drilled in th
  a methodology of converting standard reservoir models to maps of production potential for screening regions that are most favorable for we
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
  a methodology of converting standard reservoir models to maps of production potential for screening regions that are most favorable for we
ment decisions are routinely made on the basis of simulation models that are created before production operations begin. Real-time downho
presents an innovative filtering and analysis approach to identify candidates for sidetracking in mature water flooded fields.� It targets bypa
 infill drilling in oil rim reservoirs is a challenging task. In the case of thin oil rims with large gas caps early gas breakthrough and gas cycling
way. High-quality time-lapse seismic surveys conducted in 1990 1998 2001 and 2004 have all shown sharp resolution for the areal and ver
 are still producing albeit the production has dwindled significantly. With the technical costs on the rise oil & gas operators are constantly on th
  is operated by the Colombian state oil company Ecopetrol (originally discovered and exploited by Texaco). Petrominerales signed an Increm
mps (ESPs).� ESPs are an attractive alternative since they can achieve lower bottom hole flowing pressures.� This can accelerate prod

 he more recent technology advancements employed to enhance recovery and extend the life of mature oil fields in Saudi Arabia. This paper
 ption that a better history match should lead to a more accurate prediction which can lead an asset team to concentrate on a single model.
namic data such as formation pressures pressure-transient analysis interference testing tracer analysis and 4D seismic need to be interpre
namic data such as formation pressures pressure-transient analysis interference testing tracer analysis and 4D seismic need to be interpre
  basin. The field contains some two bln stb of oil in place. First oil was produced in 2004 and peak production is expected in 2012 at over 10

  located in the UKCS Central Graben to the west of the Elgin/Franklin (E/F) asset. E/F is one of the largest high pressure high temperature
  Enhanced Oil Recovery schemes ‘world-class’ Well and Reservoir Management (WRM) is the foundation of a successful project. A
                                                      OnePetro
 operations sequence of events is to drill complete and then flow wells to production at a reasonable rate " and the process will yield what M
ng horizontal wells supported by a strong aquifer and sizeable gas cap. The original zero development strategy called for zero net-voidage of
 most as long as the oil industry has been in existence. Oil production from mature fields accounts for approximately 70% of the worldwide oi
s perspective. Initially uncertainty and variability of liquid content and volume of reserves in each reservoir pose difficulty in designing surfac
production and efficiency. Using appropriate processes tools and technology production surveillance is able to be conducted in efficient man
                                                                                         OnePetro
production and efficiency. Using appropriate processes tools and technology production surveillance is able to be conducted in efficient man
 ore undertaken feasibility studies to convert the P�corade depleted oil field situated in South West France into an UGS. The P�corad
ore undertaken feasibility studies to convert the depleted P�corade oil field situated in South West France into an UGS. The P�corade
 ructures which allows to efficiently resolving demand seasonality problems. The first ever underground gas storage project in Turkey is bein
gressively pursuing production increment ventures one of the main components being the development of stringers which are present amon
es integrated reservoir engineering formation evaluation geological and geophysical contributions.� The objective of this paper is to exem
                                                                                         OnePetro OnePetro
orporate program called Field Monitoring" to capitalize affiliate previous experiences. For gas-lifted wells it resulted in the development of the
w-marine delta-front sands which form oil reservoirs in the area of the Krasnoleninsk dome.� Reservoir quality varies considerably depend
                                                                                         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
 n in the Waddell Ranch Project. The Project was implemented in three phases over a period of three years beginning in June 2000.�A to
 and can increase reserves in stacked reservoirs. The approach will potentially reduce associated costs risks and uncertainties in spite of c
at the final recovery factor would not exceed 15% with one of the waterflood development plans under consideration. Such a plan clearly left
Particularly in low-mobility reservoirs large fractures may be induced during the field life. This paper presents a new modeling strategy that c
otential is often not realized. Unlike greenfield developments mature oil fields deal with existing infrastructure and fluid export schemes with
 of Moporo Field located in western Venezuela different exploitation schemes were evaluated where intelligent completions have been highl


 utral Zone (PNZ) between Saudi Arabia and Kuwait. The reservoir was discovered in 1998. The reservoir depth is about 9000 ft subsea. The
 pproximately 700 km northwest of Edmonton (Fig. 1). It holds nearly eight billion barrels of 7�API oil in place spread over 370 km2. The C


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


                                                                                 OnePetro
 sands ranging from 24 000 to 27 000 ft TVD. The field contains several hydrocarbon-bearing turbidite sands. The discovery well was drilled


wanted fluids regardless of well orientation. Significant oil is left behind above the well completion even for horizontal wells when bottom- or
carbonate reservoir in the middle-east region. The water front advanced much faster in highly permeable upper units than the lower units and

 ld development plans surface facility design/de-bottlenecking uncertainty/sensitivity analysis and instantaneous/lifetime revenue optimizatio
 ld development plans surface facility design/de-bottlenecking uncertainty/sensitivity analysis and instantaneous/lifetime revenue optimizatio
 into the tubing.� The injected gas reduces the bottomhole pressure thereby allowing more oil to flow into the well.� The optimal amoun

maturing these projects realistic forecasts are needed. An intrinsic part of these forecasts is the initial rate of production which influences th
                                                    OnePetro
  e been subjected to karstification as demonstrated by sometimes severe drilling losses. Although significant progress has been made mapp
  ance to predict fluid flow behavior troubleshooting and optimizing both short and long term reservoir and well performance issues. BP’s
                                                                                         OnePetro
  s infill wells and upgrade the reserves. This paper describes the application of a practical process (1) to develop systematic workflow for pr
 khalin Island off the east coast of mainland Russia. This is a challenging area for exploration and development with 4.5 Billion BOE (675 Mil
 reservoir management and production strategy which optimises future recovery from an oil rim reservoir in the Betty Field offshore Malaysia
 tidisciplinary optimization team was built. The standard practices for production enhancement opportunities include logging nodal analysis a
 t of New Orleans Louisiana USA (Figure 1). Placed on production in April 2004 the main reservoir the K1 Sand was developed with two h
                                                    OnePetro
 e the heat goes at various times and places during the process provides the means to improve the performance of a project.�� Enhanc
                                                                                         OnePetro
 ield development. Handling uncertainty and risk using probabilistic approach is a challenge since it becomes quickly overwhelming. This pap
   presents the full workflow for optimzing production and injection cycle times with the help of a simplified reservoir model (SRM) through the
 el for modern well or field development architecture requires coupling of the reservoir simulator with the well/surface facility network model w
  gies can be developed within a new systematic workflow using existing applications from many E&P departments. Detailed production data
urface facility levels using only their respective knowledge experience and engineering tools without limited coordination between them som
  d time for project execution has been significantly reduced.� Using these concepts it is now possible to conduct integrated studies succe
covery as has been shown in various studies. However optimal control strategies often lack robustness to geological uncertainties. We pres
  tacked reservoir levels with an estimated total OOIP of 1.2 Gbbls. It was discovered in 1964 and has been producing since 1966 through 12
PDO) Study Center in order to derive a coherent view on the cluster development as well as to write (waterflood) FPDs for the individual field
™s decline and other factors that introduce noise in the data. This was the case with a series of operational improvements in a tight gas field
                                                                                         OnePetro OnePetro
 ment techniques. Drawing from the experiences of brown fields in the Southern swamp area various techniques were identified to optimize t
 l application of water injection-induced multilayer fractured injection into three shallow reservoirs in the Champion Southeast (CPSE) field. Fr
high Gas-Oil Ratio and low production rates. Thus it is important to manage the pressure of reservoir and stabilize it. For this certain IOR tec
  vel of risk in outcome that the operations team seeks to reduce through surveillance. One approach to bring surveillance and planning toget
  with its range of uncertainty and degree of maturity. For project approval it is necessary to aggregate the reserves/resources of all these fie
 fully holistic and “fully probabilistic modeling at the cost of the classic “precision modeling that tends to include more physics. The app
  tly quickly to transfer ever-increasing volumes of conventional natural gas from locations where it is found to where it is consumed in the 21s
gas resources requires new technologies and new large markets. GTP technologies including the well known GTL (Gas to Liquids) process
s of Qatar as well as Shell’s largest equity investment ever. In spite of the various challenges that are intrinsic to a project of this nature
R&D program on multiphase flow behaviour. One of the objectives is to improve the understanding of the behaviour of gas/oil/water mixtures
he reservoir it ori-ginated from are posing a challenge to the industry. A fundamental question in Produced Water Reinjection (PWRI) is: “
                                                                                         OnePetro
   an environmentally acceptable solution to the disposal of produced water and contributes to pressure maintenance when injection takes pla
   by oil and solid particles have to be introduced in simulators for both fractured and non fractured flows. It is well known that the complex me

                                                                                       treatment
ssful implementation of acid fracturing treatment in Marrat field. The acid fracturingOnePetro is quite challenging due to presence of high pre
has previously been on dispersed oil concentration (OIW) in produced water (PW) discharge but management tools like the calculation of th
 in the development of the XJG oil fields in the South China Sea. The XJG fields are in a mature production phase and challenge COPC (the
 in the development of the XJG oil fields in the South China Sea. The XJG fields are in a mature production phase and challenge COPC (the

 s a field matures the ratio of water to oil produced increases. Excess produced water is the main reason for abandoning wells and declarin
 me a focus of attention. Produced water management in an offshore environment requires innovation both from a surface facility and subsu
                                                                                           OnePetro
t of the fields in the Oriente basin of Ecuador and neighboring Mara��n and Putumayo basins in Peru and Colombia respectively. In m
e Water to Oil ratios ranged from <1 to up to 40 depending on maturity of the field with the lowest ratios generally observed in the Middle Eas
here is a practical limit to the number of optimization moves an operator can make (due to: changing operating constraints plant disturbance
ustain target rate until mid of 2004. Artificial Lift is part of the long term production sustainability solutions for Khafji Field necessitated by the


 roduced 40% to 60% of their original oil in place since 1991. Currently the field production is rapidly declining and water production is increas
 roduced 40% to 60% of their original oil in place since 1991. Currently the field production is rapidly declining and water production is increas
 workflow and procedures adopted to increase oil production by rigless intervention from seven wells on an offshore platform of a brown field
nts is driving the need for better decision making within daily operations.� In addition tighter integration between EP sources and markets
                                                  OnePetro
harged to demonstrate within a one-year time period measurable improvement in well productivity in the Saih Rawl field of Oman. Althoug
assisted history matching) also referred to as ‘real-time reservoir management’ ‘smart reservoir management’ or ‘closed-lo
                                                                                     OnePetro OnePetro
ter injection for pressure support and gas injection for disposal of evolved gas since 1996.� The initial oil in place has been tightly constrai
al low permeability reservoirs. The workflow was originally developed for gas reserves evaluation of the Lower Vicksburg (LV) sands and the
carbons. The strategy is to inject 300 000 BWPD of seawater from the start of oil production. During the field development in 1999 it was con
 rder to sustain production seawater injection started from the beginning of the oil production at a rate of 300k bwpd. During the field develop
uring Produced Water Re-Injection (PWRI). Norske Shell tested nitrate based souring mitigation as part of a PWRI feasibility study in the Dra
as sweetening units in carbon steel pipelines. Sour gas corrosion can lead to pipeline pinhole leaks which pose hazardous consequences to
ources was used through 4 dedicated injection wells at a maximum total rate of 4000 m3/d in early 2003. By end of April 2003 the injection
process a scale inhibitor solution is injected down a producer well into the near wellbore formation. Commonly scale treatments comprise th
  Thus optimal placement and operation of wells have a major impact on the project rewards. Well-placement in deepwater developments is
ervoirs of the Harweel Cluster in South Oman. With the light oil and very high pressure re-injected associated gas is nearly miscible with the
 ment of new technologies to separate CO2 and H2S from highly contaminated natural gas streams. This program has been significantly acc

d in 1991. Water injection started in 1993 with current infill drilling and development of some areas still taking place. This field consists of sev
on and is around halfway in its production life. The field development with water injection and relatively few wells has proved to be very succe
 with the increase in water cut from various brownfield environments these high angle wells present us with complex reservoir and productio
have associated underlying oil rims. Without due consideration to these oil rims regulator approvals to move ahead with the gas projects ma
                                                                                      OnePetro
reservoir management and production strategy which optimises future recovery from an oil rim reservoir in the Betty Field offshore Malaysia
 Engineering models and reality still frequently occur; despite the continuous increase in the complexity and predictive quality of reservoir mo


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


e including several horizontal completions. The gross reservoir interval is about 235 m (730 feet) thick. The reservoir produces from three int
cation of new ideas coupling reservoir management and production enhancement of mature oil fields is outlined in this paper. Discrepancie
  a client to agree to a forward contract for a service to be performed at a future date at some specified price. In this case the service provide
 fractured waterflood developments highlighting specific considerations for the Piltun-Astokhskoye field and the harsh and sensit
 gas though 50 active producing wells and 11 injection wells with 2 water source wells. Most of the reservoirs are waterflood. October field is
tfolio. The field – located in the Euphrates Graben 45km SE of DeirEzZor - was discovered in 1987 and holds a maximum undersaturated
e field. Instead of agressively producing and injecting fluids at maximum rate aiming at large short term profits we are after optimizing the tot
 s injection. As part of a major redevelopment study the scope for water flooding was addressed using 'smart' completions with multiple inflow
paction drive since 1982. Continuous drilling has taken place the last 25 years to both develop the field and replace failing wells. A water inje

 ance for water shutoff treatments using polymer gels. A feedforward-backpropagation algorithm was used to develop the neural networks. T
aximize hydrocarbon production in deep water turbidite reservoirs. The deep reading directional electromagnetic tool a latest-generation LW
orizontal section has been drilled in three horizontal production wells all within Palaeocene-aged Balmoral turbidite sandstones below a Sele
 gions that are most favorable for well placement.�A technique is developed to apply this method to the problem of field development whe
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
 gions that are most favorable for well placement.�A technique is developed to apply this method to the problem of field development whe
 operations begin. Real-time downhole pressure data and surface flow rate information can provide a significant set of calibration informatio
 ater flooded fields.� It targets bypassed reserves to improve production and ultimate recovery from such fields at once.� The method is
 y gas breakthrough and gas cycling can cause serious problems especially in a co-mingled production environment and heterogeneous geo
sharp resolution for the areal and vertical definition of the water movement toward the producing wells. Excellent reservoir properties with re
 & gas operators are constantly on the lookout for cheap and simple solutions. These help not only to increase the hydrocarbon production f
co). Petrominerales signed an Incremental Production Contract agreement in April 2001 to participate with Ecopetrol in increasing production
ssures.� This can accelerate production and improve recovery. This paper outlines the workflow used for candidate screening completion

 oil fields in Saudi Arabia. This paper illustrates a progression of technology in the most mature field operated by Saudi Aramco. In this field
m to concentrate on a single model. The assisted history match techniques allow us to generate multiple models that satisfy the surveillance
s and 4D seismic need to be interpreted with great care—Schiehallion has examples in which the data have been invaluable and others in w
s and 4D seismic need to be interpreted with great care—Schiehallion has examples in which the data have been invaluable and others in w
uction is expected in 2012 at over 100 000 stb per day. Whilst the field is in an early development stage it is crucial that reservoir manageme

 est high pressure high temperature producing asset in the world and involves gas condensate reservoirs at 1 100bara and 190degC. The W
 oundation of a successful project. A comprehensive WRM plan was defined for Bonga very early in the project and its implementation from

 rategy called for zero net-voidage of gas through re-injection of produced gas into the gas cap. A full gas cap blowdown is currently being pl
pproximately 70% of the worldwide oil production. Unfortunately more often than not mature oil fields equate to high cost and low productivit
 oir pose difficulty in designing surface facilities. Of course contractual obligations dictate that the required gas volumes are delivered daily w
 able to be conducted in efficient manner. These tools play an important role in well diagnostics to cater for appropriate production optimizatio

rance into an UGS. The P�corade field offers some good characteristics to become an UGS but is also deep (2500 m) and countains hy
ance into an UGS. The P�corade field offers a number of positive characteristics which make it a good candidate for UGS but it is also
 gas storage project in Turkey is being carried out in the KM field with injection and withdrawal operations. Optimization of gas storage field w
 of stringers which are present among all the major offshore oil fields. One of the technology contributions to Saudi Aramco’s effort is pro
The objective of this paper is to exemplify geosteering challenges when drilling horizontal power water injector across Permian eolian sandst

oir quality varies considerably depending on the depositional facies.� In places high permeability channels and bars were deposited wher

ears beginning in June 2000.�A total of 63 wells have been tested with well site compression; there are now 52 permanently installed com
 risks and uncertainties in spite of complex geological structures and drainage patterns. The new workflow encompasses planning from con
onsideration. Such a plan clearly left scope for improvement. However since there were limited surveillance data to infer current depletion fro
sents a new modeling strategy that combines fluid-flow and fracture-growth (fully coupled) within the framework of an existing ‘standardâ€
 cture and fluid export schemes with capacities designed for peak production sometimes decades ago and/or different production techniques
elligent completions have been highlighted. A pilot well with inflow control valves (ICVs) was proposed with the goal of maximizing the well oi


ir depth is about 9000 ft subsea. The gross reservoir interval is approximately 730 ft thick (110 ft net). The lowermost Marrat E zone contribu
n place spread over 370 km2. The Carmon Creek Project targets possibly about half of that oil for development by cyclic steam stimulation


002 and two appraisal wells were drilled soon afterwards. Due to significant uncertainties remaining after appraisal probabilistic methods w




 for horizontal wells when bottom- or edge-water invasion occurs. Two depletion strategies may be enacted to improve recovery of the rema
e upper units than the lower units and has created uneven water sweep in southern part of the field. Reservoir management program has be

ntaneous/lifetime revenue optimization from a hydrocarbon field. This involves among others the usage of reservoir simulators surface-netw
ntaneous/lifetime revenue optimization from a hydrocarbon field. This involves among others the usage of reservoir simulators surface-netw
 into the well.� The optimal amount of lift gas to inject into individual wells depends on a number of factors including inflow performance tu


 cant progress has been made mapping and predicting these karstification features on seismic there is quite some uncertainty left on the ex
nd well performance issues. BP’s use of IAM technology is typically fit for purpose with model complexity dictated by factors such as ass

 pment with 4.5 Billion BOE (675 Million tonnes oil equivalent) of oil and gas in place. This paper will outline how new technologies have ass
r in the Betty Field offshore Malaysia. The reservoirs consist of good quality sands in a coastal depositional environment with an anticlinal st
 ies include logging nodal analysis and well engineering technologies. Usually the older the field the more challenging to achieve additional
  K1 Sand was developed with two high rate horizontal wells ramped up to full rate over a period of three months (Figure 2). Due to low impe


d reservoir model (SRM) through the set up of an integrated asset model (IAM) to validate the SRM results and control the actual production
 well/surface facility network model when making choices as to the reservoir and production management strategies to be employed. Such c
epartments. Detailed production data from many sources can be used within simulation models to give a good representation of future field
 ited coordination between them sometimes bypassing important considerations from other components of the overall production system ou
  to conduct integrated studies successively in a continuous chain of studies as if they were on a conveyor belt.� For example field develo
  to geological uncertainties. We present an approach to reduce the effect of geological uncertainties in the field-development phase known a
 en producing since 1966 through 123 wells and 257 completions. 21 layers have been developed. With a global recovery to-date of 50% an
 terflood) FPDs for the individual fields. The study combined conventional and state-of-the-art workflows and was conducted by a large integr

chniques were identified to optimize the value of a project aimed at further development of the field; these include phased development focu
Champion Southeast (CPSE) field. Fractured water injection means that the bottomhole injection pressure is allowed to exceed the formation
 d stabilize it. For this certain IOR techniques are employed; waterflooding being one of them. This paper discusses waterflooding as a soluti
bring surveillance and planning together in a quantitative manner is to use a series of discrete reservoir descriptions. There have been some
he reserves/resources of all these fields into project-level representative numbers either deterministic or probabilistic. Arithmetic addition of
nds to include more physics. The approach came as a result of the oil industry low return on investment (ROI) that averaged at 7%. Determin
nd to where it is consumed in the 21st century and for how long? On a world scale the crucial question for now is not how much gas there is
known GTL (Gas to Liquids) process finally emerge as options to efficiently convert this resource into clean high value fuels and chemicals.
 e intrinsic to a project of this nature Shell and Qatar Petroleum are confident in their ability to manage construction successfully. Pearl GTL
  behaviour of gas/oil/water mixtures in separation tanks. In the framework of a joint project a new test facility platform GOwSP (Gas Oil wate
 ed Water Reinjection (PWRI) is: “How clean is clean ? or perhaps even more succinct : “How clean is fit for purpose ? There is no u

 It is well known that the complex mechanisms of the formation of an external filter cake and of a deep internal damage should be better und


gement tools like the calculation of the Environmental Impact Factor (EIF) have also shown the important contributions of naturally occurring
 ion phase and challenge COPC (the field operator) with surface fluid handling capacity issues as a result of high water cuts. Additionally the
 ion phase and challenge COPC (the field operator) with surface fluid handling capacity issues as a result of high water cuts. Additionally the

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

generally observed in the Middle East. In this paper average volumes of produced water worldwide per nations and per companies are pres
erating constraints plant disturbances or interactions fundamental process delays and dynamics and the remoteness of wells).� Automa
s for Khafji Field necessitated by the increase of field water cut and depletion of reservoirs.� In order to make up for production decline in K


lining and water production is increasing. However through reservoir surveillance data geologic and reservoir modeling significant recovera
lining and water production is increasing. However through reservoir surveillance data geologic and reservoir modeling significant recovera
 an offshore platform of a brown field located off the west coast of India. The field under study was discovered in 1987 and put on productio
he Saih Rawl field of Oman. Although the field has been producing for more than five years the results shown are based on a one-year app

 l oil in place has been tightly constrained by high quality seismic high density of well penetration and various dynamic data. The production d
 Lower Vicksburg (LV) sands and the paper illustrates the key steps in the methodology. Developing Lower Vicksburg sands has been a grea
  field development in 1999 it was concluded that Bonga was expected to suffer from reservoir souring and that mitigation would be necessar
 f 300k bwpd. During the field development it was concluded that seawater injection in Bonga would result in reservoir souring and that mitiga
  of a PWRI feasibility study in the Draugen field. Prior to the pilot the application of both nitrite and nitrate had been tested on Draugen using
 h pose hazardous consequences to people wild life and pollution to the environment. Corrosion is usually controlled through chemical inhibi
  3. By end of April 2003 the injection water source was switched to produce water and separated at in line separator. The production wells su
mmonly scale treatments comprise the following stages: preflush main scale inhibitor pill overflush tubing displacement and shut-in followed
 ement in deepwater developments is a challenging optimization problem. Manual approaches to its solution can be cumbersome even with g
 ciated gas is nearly miscible with the reservoir oils. A program of study was planned to coincide with further appraisal and bringing some of t
 s program has been significantly accelerated in recent years and major milestones have been achieved. The program focuses on technology

aking place. This field consists of several sandstone reservoirs with average permeability and porosity of 75 mD and 17% respectively. One u
ew wells has proved to be very successful. This paper shows how well and reservoir surveillance has been set-up in the Draugen field. Intere
 with complex reservoir and production management challenges. Fit for purpose production logging technology is helping to provide a better u
move ahead with the gas projects may be delayed and can erode project value. In order to optimize the development of both oil and gas hydr

 and predictive quality of reservoir models. To-day’s field development decisions are still made with a high level of uncertainty in the unde




The reservoir produces from three intervals – Marrat A Marrat C and Marrat E. The partially dolomitized lowermost Marrat E interval contri
s outlined in this paper. Discrepancies in the pressures production and injection data can create significant errors in reservoir simulation mod
price. In this case the service provider is contractually bound to provide the service at the pre-agreed price within a specified time window re
 and the harsh and sensit
rvoirs are waterflood. October field is located 21 miles from the west shoreline in the Gulf of Suez. With time the performance of the produc
nd holds a maximum undersaturated oil column of more than 500m with two original oil-water contacts of 3750 and 3778 meters subsea. The
profits we are after optimizing the total value (e.g. discounted oil volume) over the whole lifecycle of the field. An essential tool in tackling this
 mart' completions with multiple inflow control valves (ICVs) in the wells to be drilled for the redevelopment. Optimal control theory was used
and replace failing wells. A water injection pilot led to sanctioning of a waterflood project which began injection in the crest of the field in early

 ed to develop the neural networks. The before and after treatment data for 22 wells treated with polymer gels in the Arbuckle formation in ce
magnetic tool a latest-generation LWD (Logging While Drilling) measurement was the technology differentiator for optimizing well placement
 al turbidite sandstones below a Sele shale cap rock. To maximize reserves recovery the horizontal drainholes not only had to cut as much o
he problem of field development where field production profile moves through successive phases of buildup plateau and decline.�This re
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
he problem of field development where field production profile moves through successive phases of buildup plateau and decline.�This re
 gnificant set of calibration information early in the life of the reservoir. In this paper we describe a method for comparing a set of assumed r
uch fields at once.� The method is based on production engineering concepts it is very time efficient and requires only a minimum of data
 environment and heterogeneous geological conditions. For the last years high resolution geological models have been widely used to plan n
Excellent reservoir properties with relatively few high-rate wells and an expected recovery factor exceeding 60% make Draugen one of the be
crease the hydrocarbon production from a well but also helps in improving the overall field recovery factor. However sometimes expensive w
 ith Ecopetrol in increasing production from the field. Under the terms of the agreement Petrominerales invest 100% of any development acti
d for candidate screening completion selection and ESP system design of the first such conversion on the Bokor Field offshore East Malay

erated by Saudi Aramco. In this field one of the challenges is to maximize production from the inadequately swept attic oil zone resulting from
e models that satisfy the surveillance 1 and understand a range of outcomes for a set of models. What we need is to provide assurance tha
 have been invaluable and others in which the data are ambiguous or misleading. It is essential to integrate several data types to obtain relia
 have been invaluable and others in which the data are ambiguous or misleading. It is essential to integrate several data types to obtain relia
 it is crucial that reservoir management and data acquisition processes are put in place to allow efficient future field development and optimis

rs at 1 100bara and 190degC. The WAD is at similar conditions and two drilling strategies involving up to five new wells were proposed: Stra
project and its implementation from start-up has demonstrated tremendous value. More than 220 MMstb have been produced as of March

as cap blowdown is currently being planned to commence in 2008. In order to predict field behaviour in this high production rate environment
quate to high cost and low productivity making mature fields unattractive when competing for resources with other options in a company’
ed gas volumes are delivered daily with spare capacity in hand. Management issues of this type occur in the backdrop of potential loss of we
 or appropriate production optimization for the field.� The Bokor field is located 45 km off the coast of Sarawak East Malaysia. The reserv

also deep (2500 m) and countains hydrogen sulphide. This paper describes the different challenges faced by the project: the sizing of the
ood candidate for UGS but it is also deep at 2500 m and contains hydrogen sulphide. This paper describes some of the challenges faced by
 s. Optimization of gas storage field was enabled by an improved reservoir and geologic description including the evaluation of deliverability a
ns to Saudi Aramco’s effort is proactive geo-steering using Directional and Deep Resistivity technology to maximize the net sand delivere
 jector across Permian eolian sandstone reservoirs with high degree of structural and reservoir uncertainty. The integrated reservoir manage

nnels and bars were deposited whereas the more distal sands have much lower permeability and must be fracture stimulated to produce eco

 are now 52 permanently installed compressors. The candidates were selected by testing the wells in the low-pressure area and additional w
 flow encompasses planning from concept selection to preparation of well proposals during the implementation work. Scalable to any given s
 nce data to infer current depletion from the 8 oil bearing beds considerable uncertainty existed in locating the remaining reserves. This prom
mework of an existing ‘standard’ reservoir simulator. We demonstrate the coupled simulator by applications to five-spot pattern flood m
 nd/or different production techniques.� Substantial increases in producing gas-oil ratios and water production can occur over the lifetime
with the goal of maximizing the well oil production avoiding cross-flow minimizing operational risks and well interventions(coil-tubing operatio


 he lowermost Marrat E zone contributes 80-90% of the production based on PLT data. The productivity of the Marrat E is dominated by a for
 lopment by cyclic steam stimulation (CSS). There are growth plans for a significant increase in oil production over the next five years. The p


 ter appraisal probabilistic methods were used to assess development alternatives. In this study the classical experimental design method




cted to improve recovery of the remaining oil. In the first option a conventional horizontal is completed below the gas/oil contact (GOC). Onc
ervoir management program has been implemented to reduce production from wells that are located near the water finger area to achieve a

  of reservoir simulators surface-network simulators process-modeling simulators and economics packages.��� We present a com
 of reservoir simulators surface-network simulators process-modeling simulators and economics packages.��� We present a com
ctors including inflow performance tubing and surface hydraulics.� Additionally careful consideration must be given to operating constrain


quite some uncertainty left on the exact size and occurrence of these features. Furthermore there is little known about the impact of karstifica
exity dictated by factors such as asset size and complexity of the problem. The paper will describe how the modeling approach taken by ass

 line how new technologies have assessed and realized the Project’s potential. Integrated Reservoir Modeling utilizing modern seismic
onal environment with an anticlinal structure terminated at the crest with a growth fault. The history match confirmed that A6.0 reservoir unlik
ore challenging to achieve additional reserves. This paper outlines an integrated approach for achieving these opportunities reducing the ris
e months (Figure 2). Due to low impedence contrast between wet sands and shales the aquifer was not identified initially. Low primary recov


lts and control the actual production performance. A discusson of the theory of the IAM as well as the steps to set up a SRM and IAM are pr
nt strategies to be employed. Such close coupling is not currently readily available; particularly when the reservoir simulator the well/surface
 a good representation of future field wide behavior. In this paper a fictional case study of a reservoir that has been producing for some 12 y
s of the overall production system outside of their specific domain. For example a common practice in the oil industry is to generate a produ
 or belt.� For example field development planning studies for ten reservoirs some with history of more than 20 years have been generate
 he field-development phase known as robust optimization (RO). RO uses a set of realizations that reflect the range of possible geological str
  a global recovery to-date of 50% and an average producing water-cut of 75% OBAGI can be considered as a mature oil field. Current activ
 and was conducted by a large integrated team over a period of three years. The study was conducted in four phases: screening full field mo

se include phased development focus on areas of highest potential implementation of reservoir surveillance accelerated production lower
 e is allowed to exceed the formation’s fracture pressure. Thereby an unpropped fracture is created which propagates depending on the
 r discusses waterflooding as a solution for a pressure management program. This work represents results of the strategic IOR program in a
descriptions. There have been some recent advances in quantifying the value of surveillance1 2 and in developing depletion options3 4 5 tha
  probabilistic. Arithmetic addition of all low estimates (1P or P90) and all high estimates (3P or P10) is known to overstate the range of unce
 (ROI) that averaged at 7%. Deterministic methods usually ignore the full uncertainties distribution associated risks the diversification effects
 or now is not how much gas there is overall but the transport capacity linking regions with high gas resources to regions with a high consum
 ean high value fuels and chemicals. This change was brought about by technology developments over the last two decades. Over the last tw
construction successfully. Pearl GTL is a fully integrated upstream/downstream world-scale project in Ras Laffan Industrial City 80 km north
acility platform GOwSP (Gas Oil water Separation Platform) was implemented in 2006 on the IFP-Lyon site. The issue consists in improving
 ean is fit for purpose ? There is no universal correct answer to this question as it depends on specific variables largely intrinsic properties o

nternal damage should be better understood. In a previous published work1 we attempted to quantify the petro-physical external filter cake p


t contributions of naturally occurring dissolved components and production chemicals. Even if the legislation seeks a balance between techn
lt of high water cuts. Additionally there are no more slots available in the existing platforms for infill drilling. Typical completions include san
lt of high water cuts. Additionally there are no more slots available in the existing platforms for infill drilling. Typical completions include san

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

 nations and per companies are presented a case for change in management of produced water is made Shell’s integrated water mana
he remoteness of wells).� Automatic Process Control enhances the speed and accuracy with which decisions can be made and is essentia
 o make up for production decline in Khafji Field and to sustain the field target rate and defer large investments associated with exploration an


servoir modeling significant recoverable oil was identified in shaly sandstone reservoirs and attic structural locations of clean sandstone rese
servoir modeling significant recoverable oil was identified in shaly sandstone reservoirs and attic structural locations of clean sandstone rese
 overed in 1987 and put on production in 1994. The main reservoir is Middle Eocene carbonate deposit which is characterized by the presen
 shown are based on a one-year application of a systematic approach to field optimization. This process is the dynamic integration of historic

 rious dynamic data. The production data show that we have already recovered 70% of the oil initially in place by end of 2008.� We expect
wer Vicksburg sands has been a great challenge to all operators in the region not only because of the high drilling and completion cost but a
 nd that mitigation would be necessary. Initial data gathering indicated that the H2S content resulting from reservoir souring was not expecte
  lt in reservoir souring and that mitigation was necessary. Initially the selected strategy for Bonga seawater injection was to control reservoir
  e had been tested on Draugen using a Souring Mitigation Cabinet (SMC) specially developed to mimic the microbial activity in the near well r
 lly controlled through chemical inhibition in combination with frequent batching and pigging programs. In the presence of elemental sulphur c
ne separator. The production wells suddenly turned to produced high H2S while the well injectivity decline around 50% and levels have caus
ng displacement and shut-in followed by back-production of the well. For some years the industry has applied mutual solvent chemicals in th
  ion can be cumbersome even with good use of engineering judgment: (a) There often exist many combinations of well locations subject to in
  her appraisal and bringing some of the reservoirs onto production. After five years of study and simultaneously three years of development a
    The program focuses on technology solutions that are critical to develop (stranded) contaminated hydrocarbon gas and oil fields. Several k

 75 mD and 17% respectively. One unique challenge of El Trapial field is that the light oil coexist with gas that contains high CO2 concentrat
en set-up in the Draugen field. Interesting features of this set-up are Structured and automatic data integration. Information providers for th
nology is helping to provide a better understanding of fluid movement enabling higher confidence decision making leading to successful inte
development of both oil and gas hydrocarbon resources a novel concurrent oil and gas development concept is proposed. In this concept th

a high level of uncertainty in the underlying data and its economic impact. The degree of data uncertainty is greatest during the exploration s




ed lowermost Marrat E interval contributes 75-85% of the total production from zones averaging 20-25% porosity and 10-100 mD permeabilit
ant errors in reservoir simulation models. Uncertainty should be acknowledged and accounted for during the history matching and reservoir s
ce within a specified time window regardless of the prevailing price and availability. This paper presents a mathematically consistent framew

  time the performance of the producing wells showed a significant decline in productivity which was attributed to reservoir pressure decline.
 f 3750 and 3778 meters subsea. The oil production almost exclusively originates from two sandstone formations: the Cretaceous sheet-like s
 field. An essential tool in tackling this optimization problem is the adjoint method from optimal control theory. Starting from a base case reser
  nt. Optimal control theory was used to optimize monetary value over the remaining producing life of the field and in particular to select the o
 jection in the crest of the field in early 2006. The predictions of Valhall waterflood performance need to cover a wide range of parameters inc

r gels in the Arbuckle formation in central Kansas were used to train and verify the neural networks. Polymers and gels have been used exte
entiator for optimizing well placement in a number of deep water horizontal wells. The new directional measurement is highly sensitive to res
 nholes not only had to cut as much of the good reservoir sand as possible but as the Brenda field depends on water drive as its main produ
dup plateau and decline.�This results from successive drilling and commissioning of wells at a prescribed frequency (e.g. quarterly) until
 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
dup plateau and decline.�This results from successive drilling and commissioning of wells at a prescribed frequency (e.g. quarterly) until
 od for comparing a set of assumed reservoir parameters especially the presence of a connected aquifer and its size with a set of simulatio
 and requires only a minimum of data which makes it in most cases more suitable than other methods. The approach provides a filtering co
 dels have been widely used to plan new wells trajectories. However the dynamic behavior of the reservoirs was widely ignored. These effec
 ng 60% make Draugen one of the best performing fields offshore Norway. The field has a simple geology; however the reservoir structure is
or. However sometimes expensive well interventions are necessary in order to better understand the problems faced and then use the data
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
the Bokor Field offshore East Malaysia.� A brief description of each methodology is outlined potential benefits and challenges are discus

tely swept attic oil zone resulting from a significant permeability contrast with the underlying high-permeability zone. Since 1995 a progressio
we need is to provide assurance that we are searching correctly for the range in outcomes to understand the interaction between uncertaint
ate several data types to obtain reliable conclusions. This paper describes some of the highlights and pitfalls experienced in Schiehallion. Sc
ate several data types to obtain reliable conclusions. This paper describes some of the highlights and pitfalls experienced in Schiehallion. Sc
 future field development and optimise oil recovery. The paper focuses on four main aspects of the West Salym development: project mana

o five new wells were proposed: Strategy-A: Drilling from the existing E/F platforms Strategy-B: Drilling from a new wellhead platform (WHP)
tb have been produced as of March 2009 from 13 subsea producers and reservoir pressures have been maintained by water injection from

his high production rate environment and maximise oil and gas recovery significant effort has gone into the static and dynamic re-modelling
with other options in a company’s portfolio of investments. The re-development project presented in this and its companion paper1 (SP
n the backdrop of potential loss of well deliverability owing to condensate banking in the well vicinity or from pure depletion standpoint when
 Sarawak East Malaysia. The reservoir sands are highly unconsolidated at the top of the structure and gaining consolidation with depth.�

ced by the project: the sizing of the working volume (volume of gas which can be stored and cycled each year) which required the acquisitio
 bes some of the challenges faced by the project including: The sizing of the working volume (volume of gas which can be stored and cycle
uding the evaluation of deliverability and storage capacity in the reservoir. Based on available information and those generated by simulation
 gy to maximize the net sand delivered from each well. The drilling of development wells in sand stringers involves very thin and sinuous targ
nty. The integrated reservoir management team has utilized the geological and seismic impedance to locate a power water injector in the so

be fracture stimulated to produce economically.� To compound the situation the Vikulov sands are in the transition zone and in many pla

e low-pressure area and additional wells highlighted by the Moving Domain study.�Compressors were installed on successful test candid
ntation work. Scalable to any given size of hydrocarbon prospect and number of infill wells the computational method incorporates cross-dis
ng the remaining reserves. This prompted an examination of the reservoir and well characteristics to quantity these uncertainties in the reser
pplications to five-spot pattern flood models addressing various aspects that often play an important role in waterfloods: shortcut of injector a
 oduction can occur over the lifetime of the field. Falling reservoir pressures cause not only a drop in manifold pressures and the need for arti
well interventions(coil-tubing operations) leading to better reservoir management.� To evaluate the intelligent completion technology an I


of the Marrat E is dominated by a forty-foot thick largely dolomitized interval with 15-20% porosity and 20-100 mD permeability. The upper z
ction over the next five years. The purpose of this study was to optimize CSS well configuration and steaming strategy for each distinct rese


assical experimental design method was applied and reasonable P10 P50 and P90 reservoir simulation models were designed. Next we lo




 elow the gas/oil contact (GOC). Once the well waters out the well is recompleted in the gas zone. Completion occurs either at the crest for a
ear the water finger area to achieve an even water flood advance. However the current situation has raised some issues concerning the optim

 ages.��� We present a comprehensive portable flexible and extensible FM framework completely decoupled from surface and su
 ages.��� We present a comprehensive portable flexible and extensible FM framework completely decoupled from surface and su
 must be given to operating constraints including cost handling capacities compression requirements and the availability of lift gas.� In tr


e known about the impact of karstification on GIIP and water breakthrough. For the field with the largest discovered GIIP in the Central Luco
 the modeling approach taken by assets with a large well count but low individual well production rates differs from the approach taken by ass

 r Modeling utilizing modern seismic processing and interpretation to evaluate short medium- and long-term subsurface uncertainties and t
 h confirmed that A6.0 reservoir unlike all others in the field which co-exist within a stacked sequence is surprisingly isolated from the surrou
  these opportunities reducing the risk on oil recovery associated with the various enhancement initiatives. The objectives of this paper are to
  identified initially. Low primary recovery was expected. Space was allocated on the Na Kika semi-submersible platform for possible waterfloo


teps to set up a SRM and IAM are presented in this paper. The steps are described in context of an actual field operation. A WAG cycle optim
e reservoir simulator the well/surface facility simulator and potentially the optimiser programs are provided by different suppliers. We have
at has been producing for some 12 years will be examined. The wells are all producing into a sub-sea manifold and then tied back via a 60k
 he oil industry is to generate a production forecast derived from a reservoir-based model without taking into account surface facility constrai
 e than 20 years have been generated within one year. The three main enabling technologies for the rapid execution of integrated studies ar
ct the range of possible geological structures honoring the statistics of the geological uncertainties. In our study we used 100 realizations of a
ed as a mature oil field. Current activities are driven by two main objectives: to sustain short term production level and to identify potential r
n four phases: screening full field modelling infra-structure development and FDPs for the 6 large fields and the writing of appraisal / develop

 ance accelerated production lower operating cost etc. Reservoir management is an ongoing continuous cradle-to-grave process which ta
  which propagates depending on the injection water’s leakoff rate into the formation. The project is part of a larger secondary recovery im
ults of the strategic IOR program in a mature field showing importance and influence of each decision made during project implementations.
 developing depletion options3 4 5 that span the range from pattern balance to new field development. Previous work has generally been bas
  nown to overstate the range of uncertainty. On the other hand independent probabilistic addition tends to produce unrealistically narrow ran
 ciated risks the diversification effects and the interdependencies among the chosen assets. In addition it loses the proper interaction betwee
ources to regions with a high consumption but insufficient local gas resources like North America Europe and East Asia. To analyze the gas
 the last two decades. Over the last two years we have seen financial project commitments of over $20billion for GTL projects alone. Less w
Ras Laffan Industrial City 80 km north of Doha Qatar. It will have the capacity to produce 140 000 barrels a day (b/d) of GTL products – ga
site. The issue consists in improving the design of separator as operators are now faced with more difficult operating conditions related to de
 ariables largely intrinsic properties of a reservoir its produced fluids and the contaminants that eventually end up in the produced water. PW

e petro-physical external filter cake properties. In this paper results from core flood experiments (CFE) aimed to quantify the internal damage


ation seeks a balance between technical feasibility and economic cost it is believed that regulators may wish to move to requirements where
ng. Typical completions include sand-control devices such as gravel packs and fracture packs inside 9 5/8-in casing with zones separated b
ng. Typical completions include sand-control devices such as gravel packs and fracture packs inside 9 5/8-in casing with zones separated b

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

de Shell’s integrated water management strategy principles and applications are discussed supported by field cases impact of new tech
ecisions can be made and is essential for optimization.� However the advantages of automatic process control are often underestimated;
 ments associated with exploration and drilling new wells as well as commissioning new facility expansions Production Optimization and de-b


 ral locations of clean sandstone reservoirs. As a result a comprehensive portfolio of prospects has been built for a robust development prog
 ral locations of clean sandstone reservoirs. As a result a comprehensive portfolio of prospects has been built for a robust development prog
 which is characterized by the presence of vugs dissolution channels fractures (both vertical and horizontal) and hence high permeability st
s is the dynamic integration of historical data and new information technologies and engineering diagnostics to systematically identify laye

place by end of 2008.� We expect the reservoir to achieve 74% recovery without further infill drilling by the end of field life. We attribute th
 gh drilling and completion cost but also due to the high risk and uncertainty involved in the process. To make wise investments in such a diff
 m reservoir souring was not expected to exceed 50 parts per million(volume-based) [ppm(v)] in the gas phase. Initially nanofiltration to reduc
 ter injection was to control reservoir souring with biocide and handle low levels of H2S with sour service materials and scavenging facilities to
 he microbial activity in the near well reservoir. From this pre-study the dosage of nitrate was selected based upon bio-available carbon and t
  the presence of elemental sulphur corrosion rate can exceed 30 mm/y. Most of the mitigation methods designed to manage and maintain th
ne around 50% and levels have caused concern for on going Field Development scenarios. Meanwhile in opposite in Y oilfield when discov
pplied mutual solvent chemicals in the preflush stage of such treatments to (i) avoid emulsion formation or water blocking thus avoiding slow
 inations of well locations subject to investigation; (b) There is need to optimize operational constraints for every well-placement scenario; (c)
neously three years of development and two years of production from a Phase 1" project a Phase 2 production and miscible gas injection de
ocarbon gas and oil fields. Several key technical challenges in the development of highly contaminated gas & oil fields have been overcome

as that contains high CO2 concentrations greater than 75%. This is observed in both dissolved gas and in gas caps in various blocks of the f
 egration. Information providers for the important subsurface risks and uncertainties have been mapped which has resulted in a better under
 on making leading to successful interventions. Production logging in high angle and horizontal wells that produce mixtures of fluid phases is
 ncept is proposed. In this concept the gas cap and oil rim are produced simultaneously from the start of production through a single well con

ty is greatest during the exploration stage but decreases as the reservoir development plan is executed and production data is obtained. Sta




 porosity and 10-100 mD permeability. Productive intervals in the Marrat A and C zones average 15-20% porosity and 0.5-2 mD permeability
 the history matching and reservoir simulation process. In many cases large amounts of historical data were collected but much is either inac
s a mathematically consistent framework using decision trees conditional probabilities and Monte Carlo simulation to appropriately value fut

 buted to reservoir pressure decline. So a study was done and resulted in selecting a waterflooding technique for reservoir pressure mainten
rmations: the Cretaceous sheet-like shallow marine Lower Rutbah (RUL) and the Triassic coastal fluvial plane Mulussa F (MUF) formation. T
eory. Starting from a base case reservoir simulation run this extremely efficient method makes it possible to compute the sensitivities of the
 field and in particular to select the optimal number of ICVs the optimal configuration of the perforation zones and the optimal operational st
 over a wide range of parameters including the fault and fracture pattern the initial present day and future chalk properties the chemistry an

ymers and gels have been used extensively in field applications to suppress excess water production and improve oil productivity.� Field e
easurement is highly sensitive to reservoir boundaries and therefore gives early warning of conditions requiring steering adjustments while d
nds on water drive as its main production mechanism it was essential the wells were placed as close as possible to the top of the reservoir to
 ribed frequency (e.g. quarterly) until the total well ‘budget’ for the field is exhausted and eventual termination of wells as they reach p
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.
 ribed frequency (e.g. quarterly) until the total well ‘budget’ for the field is exhausted and eventual termination of wells as they reach p
er and its size with a set of simulation models to assist with well placement decisions. In the South Timbalier 316 block a delineation well
 The approach provides a filtering concept to select all wells that might have bypassed reserves in their drainage area and provides a step by
oirs was widely ignored. These effects are related for instance to interference phenomena which directly impact the optimum number of infill
gy; however the reservoir structure is relatively uncertain because of the low number of well penetrations for calibrating the structure. Fortun
 oblems faced and then use the data acquired to study and then implement a more long-term/ permanent solution. The purpose of this pape
 . The Orito reservoir is a multi layered reservoir with three production intervals: Pepino Villeta and Caballos at depths of 3000 ft TVD and 70
al benefits and challenges are discussed and an assessment is presented of the life-cycle economics leading to final recommendation. Vario

ability zone. Since 1995 a progression of new technology deployment has taken place to improve oil recovery from this thin attic oil zone. Th
nd the interaction between uncertainty surveillance and the business decision. This paper describes an example for the Mahogany field in T
 tfalls experienced in Schiehallion. Schiehallion Background The Schiehallion field is situated on the Atlantic margin of the United Kingdom C
 tfalls experienced in Schiehallion. Schiehallion Background The Schiehallion field is situated on the Atlantic margin of the United Kingdom C
st Salym development: project management well and reservoir surveillance reservoir management and petroleum resources maturation. In

rom a new wellhead platform (WHP) which would be constructed over West Franklin Strategy-A involved high step-outs of more than 4 000
n maintained by water injection from the start of production in 13 subsea high rate water injectors allowing high field production rates to be s

 the static and dynamic re-modelling of the reservoir.� This effort has demonstrated that over the production life complexity of the high q
n this and its companion paper1 (SPE 104034) looked at the technical and business opportunities for two main re-development components
rom pure depletion standpoint when the well penetrates a small-fault block. Distinguishing the reason for premature rate decline has a profo
gaining consolidation with depth.� Almost all intervals are produced in non-commingled production mode with dual string arrangements.ï¿

ch year) which required the acquisition and processing of a new 3D seismic program and the construction of specific geological and reservo
of gas which can be stored and cycled each year) which required the acquisition and processing of a new 3D seismic program and the cons
n and those generated by simulation model KM field is the best candidate for underground gas storage. The KM offshore natural gas field w
rs involves very thin and sinuous targets. These targets are the channel sand stringers and contain a substantial amount of hydrocarbons. O
cate a power water injector in the southwestern flank of the field to support pressures during production from offset wells.� Seismic imped

 the transition zone and in many places wet sands are in close proximity to the oil-productive sands.� For this reason many of the initial

 e installed on successful test candidates in phases one and two. Phase three involved expanding the project to test the remaining 39 gas w
tional method incorporates cross-disciplinary software (geomodeling and seismic packages) as well as reservoir production completion and
antity these uncertainties in the reservoir potential and hence ensure the future strategies to increase recovery are viable. To determine the
e in waterfloods: shortcut of injector and producer fracture containment reservoir sweep. We also demonstrate that induced fracture dimens
nifold pressures and the need for artificial lifting technologies but potentially may also lead to the necessity of flaring associated gas if no app
ntelligent completion technology an Integrated Asset Model (IAM) was implemented. This model was divided in two sections: the first section


 0-100 mD permeability. The upper zones contribute 10-20% of the production from thin intervals with 12-15% porosity and 2-5 mD permeab
eaming strategy for each distinct reservoir area by deploying previously improved and history matched simulation models1. A full field static m


n models were designed. Next we looked upon the development plan by performing a second round of design of experiment runs with unco




pletion occurs either at the crest for a small gas-cap reservoir or at the GOC inducing reverse cone for reservoirs with thick-gas columns. A
sed some issues concerning the optimization of recoverable reserves in lower units due to water slumping from upper to lower units uneven

letely decoupled from surface and subsurface simulators. The framework has a clearly defined interface for simulators and external FM algo
 letely decoupled from surface and subsurface simulators. The framework has a clearly defined interface for simulators and external FM algo
 nd the availability of lift gas.� In traditional gas lift optimization projects a gathering network model is used to calculate the optimal amoun


  discovered GIIP in the Central Luconia Province karstification was seen as the largest contributor to GIIP uncertainty. GIIP uncertainty was
 ffers from the approach taken by assets with a few high rate wells. For example BP’s Onshore US business uses IAM for evaluating the

term subsurface uncertainties and to support development planning and reservoir management. The results have been combined into a full
s surprisingly isolated from the surrounding aquifers. Prior to its premature shut-in oil production reached 5000 bopd. However a drastic dec
s. The objectives of this paper are to present (i) how using numerical simulation to support and improve the strategies for production enhanc
ersible platform for possible waterflood facilities. However field performance has exceeded initial predictions. A multi-discipline integration h


ual field operation. A WAG cycle optimization workflow for the Snorre field has been created to demonstrate the advantages of using the SRM
 ded by different suppliers. We have had the opportunity to test a newly developed “link tool to integrate the reservoir simulation model w
manifold and then tied back via a 60km flow line and riser system. The reservoir is in severe decline with field production well below the orig
  into account surface facility constraints that could lead to unrealistic approximations. Restrictions in compression power or pump capacity fo
pid execution of integrated studies are cluster computing and unique modular workflows that are based on stochastic concepts. Clusters hav
 r study we used 100 realizations of a 3D reservoir in a fluvial depositional environment with known main-flow direction. We optimized the rat
 ction level and to identify potential remaining resources for additional developments Appropriate monitoring and global static/dynamic revi
  and the writing of appraisal / development plans for the remaining 17 fields. This paper describes the workflow and learnings of the study. I

 us cradle-to-grave process which targets depletion of reservoirs in a way that maximizes recovery and return on investment. Hydrocarbon w
part of a larger secondary recovery implementation scheme and future efforts to increase economic oil production and ultimate recovery in th
ade during project implementations. The reservoir into consideration is a sandstone reservoir which was producing under a solution gas driv
 revious work has generally been based on a single reservoir description with the assumption that a pattern balance option developed on the
 to produce unrealistically narrow ranges. The correct answer would be obtained by using correlated addition but this requires the estimation
  it loses the proper interaction between the technical and the commercial value drivers. As a result many rated oil companies fall since 1990
 e and East Asia. To analyze the gas situation in the world a gas distribution model was constructed. The model predicts the timing and amo
billion for GTL projects alone. Less well known are rapid advances in gas to chemicals (such as methanol) conversion technologies and incre
 s a day (b/d) of GTL products – gasoil naphtha kerosene normal paraffin and lubricants base oils – as well as 120 000 barrels of oil eq
 ult operating conditions related to deep offshore or difficult crudes. The GOwSP is an industrial closed loop test facility designed for R&D pro
 lly end up in the produced water. PWRI for reservoir management purposes must find the balance between injector plugging and the extent

aimed to quantify the internal damage are presented. In recent published works CFE were performed to examine along rock samples the d


 wish to move to requirements where dispersed oil concentration is not the only parameter to be considered. Furthermore recently develope
 5/8-in casing with zones separated by packers and produced commingled through sliding sleeve doors (SSDs). In the past few years more a
 5/8-in casing with zones separated by packers and produced commingled through sliding sleeve doors (SSDs). In the past few years more a

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

ted by field cases impact of new technology applications on gross water production is illustrated value of beneficial use of produced water is
ess control are often underestimated; hence the discipline is under-staffed and under-utilized. Process Control also plays a crucial role in pla
 ns Production Optimization and de-bottlenecking of the existing production system was found to be the best cost effective solution.� �


n built for a robust development program. Horizontal wells were utilized to improve oil recovery in shaly sands and to reduce water coning in
n built for a robust development program. Horizontal wells were utilized to improve oil recovery in shaly sands and to reduce water coning in
ntal) and hence high permeability streaks that provide conduits for early water breakthrough. This has been primarily responsible for the dec
ostics to systematically identify layer-by-layer key parameters affecting productivity and to optimize performance based on “present-sta

y the end of field life. We attribute this extremely high recovery factor partly to high rock quality with low Sor and more importantly to the goo
 make wise investments in such a difficult environment it is crucial to understand the real value of the remaining reserves. The outcome of a
 phase. Initially nanofiltration to reduce the sulfate level in the seawater was identified to mitigate reservoir souring but because of the high ca
  materials and scavenging facilities topside. The maximum H2S the existing facilities could handle was set at 50 ppm (v). The decision to co
ased upon bio-available carbon and the required stoichiometric concentration of nitrate. During the PWRI pilot corrosion rates were measur
 designed to manage and maintain the integrity of carbon steel downhole tubing and pipelines present in itself some of the toughest technica
 in opposite in Y oilfield when discovered the field was found to be sour hence production facilities were designed for sour service. Occasio
 or water blocking thus avoiding slow well clean-up and also (ii) for enhancing adsorption of the scale inhibitor onto the formation rock. This
or every well-placement scenario; (c) The optimization process has to be repeated for a variety of geologic realizations; (d) Presence of comp
duction and miscible gas injection development has been approved by shareholders and has started. The Phase 2 development is one of the
 gas & oil fields have been overcome with new technologies developed by Shell. These challenges include: contaminant separation at minima

 in gas caps in various blocks of the field. Well documented production data have indicated variations in CO2 concentration in different areas
  which has resulted in a better understanding of the value of surveillance activities. Integration of laboratory data production well test results
 t produce mixtures of fluid phases is challenging because of the associated complex flow regimes that radically change the physics and tech
  production through a single well conduit. As a result significant cost benefits can be realized (i.e. one concurrent smart well can potentially re

 and production data is obtained. Standard probabilistic workflows have been developed to quantify this uncertainty. These workflows are us




% porosity and 0.5-2 mD permeability. The current estimated original oil in place is about 500 million bbls. A volumetric uncertainty look-back
were collected but much is either inaccurate or critical types of data have not been gathered. Lots of Russian fields have great potential using
 simulation to appropriately value future information today. We assume that the client company and the service provider share information on

 nique for reservoir pressure maintenance and increase of the oil recovery factor. The economic success of a waterflood project depends on
 plane Mulussa F (MUF) formation. The Omar Field is formed by an elongated high relief tilted horst block which is internally compartmenta
le to compute the sensitivities of the total (lifecycle) value with respect to all (time-dependent) well control variables in one go at a cost less t
zones and the optimal operational strategies for the ICVs. A gradient-based optimization technique was implemented in a reservoir simulato
re chalk properties the chemistry and temperature of the injected water and the influence of compaction all likely to have an influence on in

nd improve oil productivity.� Field experience has demonstrated that candidate-well selection is critical to the success of gel-polymer treatm
equiring steering adjustments while drilling horizontal wells maximizing well position in the reservoir. This paper shows how thin oil rims fault
  possible to the top of the reservoir to ensure a greater long term field life and given the thin oil column reduce the volume of attic oil. Gener
 l termination of wells as they reach prescribed abandonment criteria.� This method in general results in an irregular well placement patte
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
 l termination of wells as they reach prescribed abandonment criteria.� This method in general results in an irregular well placement patte
mbalier 316 block a delineation well penetrated the steeply dipping B4 reservoir near the oil/water contact. Based on a comparison of down
drainage area and provides a step by step analysis to verify quantify and locate these bypassed reserves.� Further it provides a compreh
   impact the optimum number of infill wells during the concept selection in a field development stage. High resolution geological models toget
s for calibrating the structure. Fortunately the 4D-seismic interpretations have largely compensated for this shortcoming by providing improv
 t solution. The purpose of this paper is to present details on what kind of solutions that have been implemented within the Alwyn field (produ
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
ading to final recommendation. Various lift technologies were considered to replace the existing gas lift system accounting for fluid propertie

 overy from this thin attic oil zone. The technology deployments included among others: recompletion with short-radius horizontal sidetracks
n example for the Mahogany field in Trinidad which is mainly gas with a thin oil rim. As the reservoir pressure is decreasing there is a window
antic margin of the United Kingdom Continental Shelf (UKCS) to the west of the Shetland Islands in water depths of approximately 400 m (F
antic margin of the United Kingdom Continental Shelf (UKCS) to the west of the Shetland Islands in water depths of approximately 400 m (F
d petroleum resources maturation. In the project management section the multi-disciplinary integrated team approach implemented in the sub

ed high step-outs of more than 4 000m which have not previously been attempted under the extreme WAD conditions. The drilling risk asso
 ng high field production rates to be sustained. Well and reservoir performance data obtained during the first three years of production and in

oduction life complexity of the high quality reservoir has been underestimated leading to inadequate historical data acquisition and integratio
 o main re-development components. The first component aims to beat the natural production decline curve via the implementation of a mas
 r premature rate decline has a profound bearing on project economics and asset management. This talk attempts to address various issues
ode with dual string arrangements.� Most strings require artificial lift due to low reservoir pressures and viscous fluid properties.� Gas

on of specific geological and reservoir models the safety and environmental issues such as caprock integrity and sour gas production the
w 3D seismic program and the construction of specific geological and reservoir models. The safety and environmental issues related to ca
  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
bstantial amount of hydrocarbons. Optimal well placement is a requirement for these very thin reservoirs in order to drain them in a cost effe
from offset wells.� Seismic impedance indicated that the target area comprises of beds with high degree of lateral and vertical heterogene

½ For this reason many of the initial completions within the acreage had poor results. To improve field performance a multi-disciplinary tea

project to test the remaining 39 gas wells in the area by leasing compressors. This was done to reduce capital cost take advantage of highe
 eservoir production completion and drilling software. Linkage between the disciplines is close and conducted iteratively operating in parall
ecovery are viable. To determine the uncertainty in predictions it was necessary to create multiple predictive models all matched to observed
onstrate that induced fracture dimensions can be very sensitive to typical reservoir engineering parameters such as fluid mobility mobility rat
sity of flaring associated gas if no appropriate compression facilities are available. Metering and surveillance facilities as well as reservoir ma
vided in two sections: the first section involves the reservoir model using a reservoir simulator which includes the representation of the ICVs


2-15% porosity and 2-5 mD permeability. A two stage design of experiments (DoE) based workflow was used to evaluate and optimize prima
 mulation models1. A full field static model was built comprising over 400 wells. More detailed static sector models were also built for each d


 design of experiment runs with uncontrollable uncertainties and decisions as factors. The goal was to validate that the previously selected m




 reservoirs with thick-gas columns. Alternatively one can skip the initial oil completion where gas disposition is a nonissue. Gravity-stable flo
ng from upper to lower units uneven areal and vertical sweep and uncertainty in the effectiveness of dense intervals within the lower subunit

 for simulators and external FM algorithms. Any black-box simulator or algorithm may become a part of the system by simply adhering to the
 for simulators and external FM algorithms. Any black-box simulator or algorithm may become a part of the system by simply adhering to the
 used to calculate the optimal amount of lift gas to inject into each well based on static boundary conditions at the reservoir and processing f


 IP uncertainty. GIIP uncertainty was large with a 40% difference between high and low cases despite a long history of production. The field
 business uses IAM for evaluating the needs for compression and/or facility optimization while assets in deep water use models to help prote

esults have been combined into a fully integrated production system model from each reservoir to the LNG plant and Oil Export Terminal. Th
 d 5000 bopd. However a drastic decline in reservoir pressure caused the evolution of a large secondary gas cap and a steeply increasing pr
  the strategies for production enhancement opportunities identified by the standard screening exercises in a brown field and (ii) how to optim
 tions. A multi-discipline integration has improved our reservoir description resulting in an expected improved primary recovery increased res


rate the advantages of using the SRM and IAM technology. The optimization process is performed using a SRM able to run a simulation run
rate the reservoir simulation model with a subsurface/surface network model allowing (automatic) optimisation of the full network performan
h field production well below the original design capacity of the production system and surface facilities. Hence further development options
mpression power or pump capacity for example could impose significant limitations over the well and surface network performance that cou
on stochastic concepts. Clusters have been deployed because of its established advantage in improving performance which in this case tran
n-flow direction. We optimized the rates of the eight injection and four production wells over the life of the reservoir with the objective to max
 itoring and global static/dynamic review are the key factors to achieve these objectives. The short term objective is to maintain production b
 orkflow and learnings of the study. Introduction The� cluster of fields in South Oman holds a significant near-term growth potential throug

return on investment. Hydrocarbon was encountered in the Ogbotobo field between depths of 4755 (X sand) to 8684 (Z sand) ft tvss; howe
production and ultimate recovery in the whole Champion field. The main boundary condition for the rapid water injection project is the use of
s producing under a solution gas drive & a very weak aquifer for about 5 years. During the course of production reservoir pressure decrease
 ern balance option developed on the single model is suitable for application in the field. This paper covers the extension to multiple models
 ition but this requires the estimation of all correlations between field-resource estimates. This paper presents a simplified and pragmatic ap
 y rated oil companies fall since 1990 until near future. To achieve more realistic results decision and risk analysis (D&RA) approach togethe
he model predicts the timing and amount of gas shortfall (the difference between demand and available supply) as well as depletion of recove
ol) conversion technologies and increases in plant scales which signifcantly reduce manufacturing costs. These developments transition e.g.
€“ as well as 120 000 barrels of oil equivalent a day of ethane liquefied petroleum gas (LPG) and condensate. The project is being developed
 oop test facility designed for R&D program and for testing multiphase equipment such as separators pumps or flow-meters. The loop includ
ween injector plugging and the extent of induced fractures [1] for which duty the available simulation models have been found to be wanting a

 examine along rock samples the deposition profile of only solid particles. The present work focuses on the oil droplets deposition profile. T


 red. Furthermore recently developed water treatment technologies are currently being installed on the NCS. In relation with the various wat
(SSDs). In the past few years more and more horizontal wells have been drilled and completed with expandable sand screens and premium
(SSDs). In the past few years more and more horizontal wells have been drilled and completed with expandable sand screens and premium

ses the growing need for produced water reuse highlights reuse options and gaps and specifically presents Constructed Treatment Wetlan
ement strategy lies in the ability to accurately forecast future water production. Using historical water production data from existing platforms

of beneficial use of produced water is demonstrated overall considerations for effective water management are introduced and the question
Control also plays a crucial role in plant safety and availability as stable wells or facilities are operated more frequently within the design windo
 best cost effective solution.� �For that purpose general optimization and gas lift allocation models have been built and applied for Kha


sands and to reduce water coning in thin remaining oil columns. Horizontal drilling best practices were applied during well planning and drillin
sands and to reduce water coning in thin remaining oil columns. Horizontal drilling best practices were applied during well planning and drillin
been primarily responsible for the decline in oil production. The average water cut in the field is 80%. The offshore platform on which the rigle
rformance based on “present-state analyses. In doing so the program has produced some of the highest productivity wells in the fieldâ€

 Sor and more importantly to the good understanding and effective management of the reservoir. This paper will summarise key methods by
maining reserves. The outcome of a reserves evaluation depends on the amount and quality of the data the knowledge and experience of t
 ir souring but because of the high capital-expenditure (CAPEX) costs it was dropped and because there were no other proven mitigation te
set at 50 ppm (v). The decision to control reservoir souring with biocide and handle H2S at surface was re-evaluated in 2003 and it was con
RI pilot corrosion rates were measured continuously Downstream (D/S) the Water Injection (WI) pumps in the High Pressure (HP) system a
  itself some of the toughest technical challenges. This paper outlines specific corrosion challenges related to the use of sulphur solvents; fre
 e designed for sour service. Occasional monitoring confirmed high H2S levels to prevail but also showed an alarming increase with time ca
 hibitor onto the formation rock. This paper discusses the effect of a mutual solvent preflush on scale inhibitor squeeze lifetime and also on w
 ic realizations; (d) Presence of complex sub-seismic geologic architecture may render workflows that solely rely on seismic data obsolete. W
 e Phase 2 development is one of the largest petroleum development projects ever undertaken in Oman. This paper describes the strategies
de: contaminant separation at minimal energy consumption and losses at minimum capital investment. This paper will present these challen

 CO2 concentration in different areas of the field. Conventional fluid modeling could not explain the formation of gas caps at dissimilar structu
 ory data production well test results and model-based-rates are enablers for improved production allocation to individual wells. “Data-to-
 adically change the physics and technology of measurement. Depending on the borehole deviation the velocity and fluid holdup of different
oncurrent smart well can potentially replace two conventional dedicated oil and gas wells). Reservoir simulation has demonstrated the ability

 uncertainty. These workflows are usually framed by the reservoir scale development plan and end prior to the well’s detailed completion




s. A volumetric uncertainty look-back (1998-2007) has allowed a historical assessment to be made for porosity and water saturation (Sw) un
ssian fields have great potential using modern techniques but each project has great uncertainty due to data constraints. A strategic goal for
 service provider share information on reservoir uncertainty. The presence of multivariate reservoir uncertainties typically makes such valuat

 s of a waterflood project depends on the additional oil recovery it can achieve relative to increased cost over primary development. it must a
 ck which is internally compartmentalised. Originally the field produced naturally at a peak net oil rate of some 80kbpd but production declin
ol variables in one go at a cost less than that of an extra reservoir simulation run. These sensitivities can be used in an optimization loop to i
 implemented in a reservoir simulator equipped with the adjoint functionality to compute gradients of an objective function with respect to con
n all likely to have an influence on injection sweep and recovery. The Valhall chalk is highly compressible and can be liquefied under certain

  l to the success of gel-polymer treatments. To date most candidate-well selections are based on anecdotal screening guidelines which ofte
s paper shows how thin oil rims faulted reservoirs and those with highly variable structure were able to be developed more efficiently. By red
 reduce the volume of attic oil. Generally the location of the top reservoir is visible on seismic but with significant sub-seismic variations in the
s in an irregular well placement pattern as it attempts to conform to both time-invariant reservoir properties (e.g. permeability field which ma
 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
s in an irregular well placement pattern as it attempts to conform to both time-invariant reservoir properties (e.g. permeability field which ma
act. Based on a comparison of downhole pressure data with data from simulation models the operator concluded that a connected aquifer
es.� Further it provides a comprehensive method to develop a production forecast for a potential sidetrack.� It also presents a set of cr
gh resolution geological models together with reservoir simulation models using parallel computing allow a more sophisticated workflow to op
 his shortcoming by providing improved lateral control for refining the reservoir-simulation models. All of the 4D interpretations conducted so
emented within the Alwyn field (producing since 1987) in the Northern North Sea. These production enhancement measures relate to a numb
 are below the original bubble point pressure. The wells can exhibit a number of challenges for production of fluids using artificial lift including
system accounting for fluid properties well depths productivity index and economic benefit.� Ultimately ESPs were selected. A rigorous

 h short-radius horizontal sidetracks single lateral re-entry sidetracks equipped with passive ICDs and new multilateral MRC wells equipped w
ssure is decreasing there is a window of opportunity to drill an additional well. The first task is to determine the correct value of a new gas w
 ter depths of approximately 400 m (Fig. 1). Together with the smaller satellite Loyal field it is produced through subsea horizontal wells tied
 ter depths of approximately 400 m (Fig. 1). Together with the smaller satellite Loyal field it is produced through subsea horizontal wells tied
am approach implemented in the sub-surface asset and field operations teams is highlighted.� In combination with technology support fro

 AD conditions. The drilling risk associated with Strategy-A was greater than with Strategy-B but to compensate Strategy-A offered the pros
 first three years of production and information from 4 D seismic shot in early 2008 are now used to optimize the planning and drilling of add

 torical data acquisition and integration efforts particularly in the low oil price world in the late 90s. This paper describes how all available sub
urve via the implementation of a massive infill drilling program; the second component aims to maintain production through the integration of
lk attempts to address various issues starting with well productivity and considering various completion options to modeling the coupled rese
 nd viscous fluid properties.� Gas lift is the artificial lift method used in the field. The field gas source is supplied from a nearby field and co

 tegrity and sour gas production the conversion of existing oil&gas well producers into gas injectors and producers the processing of cycled
 d environmental issues related to caprock integrity and sour-gas production. The conversion of existing oil and gas wells into gas injection a
he Marmara sea. The field was initially planned to be developed with 3 wells but recently 2 additional wells were added during the developm
s in order to drain them in a cost effective manner. Conventional well placement has met with limited success in stringers and thus resulted
gree of lateral and vertical heterogeneity.� The team decided first to drill the well utilizing a conventional logging while drilling (LWD) tool to

 performance a multi-disciplinary team was assembled.� The team consisted of a geologist petrophysicist completion production and re

capital cost take advantage of higher gas prices at the time and gather data for proper design and sizing of the compressors. Following s
 ducted iteratively operating in parallel instead of the common sequential and decoupled approach. The method has been successfully teste
ctive models all matched to observed field data. This matching process is extremely time consuming when undertaken manually. Our experie
ers such as fluid mobility mobility ratio 3D saturation distribution (in particular shockfront position) positions of wells (producers injectors)
 nce facilities as well as reservoir management infrastructure are often basic and represent the technology available at the time of the platfor
 ludes the representation of the ICVs through the multi-segment wells option; the second section represents the fluid flow in the well and pipe


 used to evaluate and optimize primary reservoir development. Reservoir uncertainties affecting volume and connectivity were assessed in th
ctor models were also built for each distinct geological area and translated into elements of symmetry thermal simulation models. The choice


validate that the previously selected models reasonably represented P10 P50 and P90 oil recoveries and net present value after including




sition is a nonissue. Gravity-stable flooding is required to maximize reserves. Extensive flow simulations in multiple history-matched models
 nse intervals within the lower subunits. But opportunity still exists to improve the recovery from these units. A series of simulation models we

 the system by simply adhering to the FM interface which is discussed in this paper. The FM framework capabilities are demonstrated on se
the system by simply adhering to the FM interface which is discussed in this paper. The FM framework capabilities are demonstrated on se
ons at the reservoir and processing facility.� However as reservoir conditions change over time lift gas requirements will change as will o


a long history of production. The field has been on production since 1987 and more than 60 % of the GIIP have been produced to date. For t
 deep water use models to help protect and optimize base production. The paper will also discuss how IAM has been at the heart of BP’

NG plant and Oil Export Terminal. The Lunskoye field which is being developed with the highest capacity gas wells in Russia has used the l
y gas cap and a steeply increasing producing gas-oil ratio. The recovery factor for this reservoir stands at 25% significantly less than for the
 in a brown field and (ii) how to optimize redevelopment plan for maximum recovery. First several increased well production opportunities we
oved primary recovery increased reserves and a decision that waterflood is not necessary. The field has greater reservoir energy due to high


g a SRM able to run a simulation run in a matter of minutes and hence being suitable for sensitivity analysis and optimization. The optimized
 isation of the full network performance. The tool supplies the simulation results to the surface network simulator/optimiser which in turn rec
  Hence further development options are being investigated for this asset.�A new nearby reservoir has been discovered. A reservoir sim
urface network performance that could impact long term field management plans if they are not properly identified and solved. PEMEX E&P
g performance which in this case translates into a significant reduction in simulation times.� A modular workflow enables the various tasks
e reservoir with the objective to maximize the average net present value (NPV). We used a gradient-based optimization method in which the
 objective is to maintain production by optimizing the injection capacity. Difficulties to model reservoir performance have resulted in implemen
 ant near-term growth potential through active waterflood implementation and later through polymer flood recovery (Fig.1). The cluster develo

 sand) to 8684 (Z sand) ft tvss; however the major reservoir is the Y (OWCs Ca. 5500 – 5821 ft tvss) which accounts for over 75% of the
d water injection project is the use of existing infrastructure with the exception of three new water pipelines and nine new wells. This paper de
 duction reservoir pressure decreased substantially and went below the bubble point pressure. Waterflooding was considered as the most su
 rs the extension to multiple models where we can seek the optimum choice of things that we can control in the depletion plan across the mu
esents a simplified and pragmatic approach partial probabilistic addition. A hierarchy of “resource containers is defined from individual re
sk analysis (D&RA) approach together with a “holistic strategy (based on the Nobel-Prize wining portfolio theory that has shaped the finan
supply) as well as depletion of recoverable gas resources for the various regions in the world for a 100-year period. To reduce the complexity
. These developments transition e.g. methanol from a chemical to a large scale future fuel and chemical feedstock for other large scale che
nsate. The project is being developed in two phases with the first phase expected to start up around the end of the decade. It is making goo
umps or flow-meters. The loop includes a large three-phase storage tank (10m3). Gas and liquids are flowing separately towards a mixing po
dels have been found to be wanting as they do not adequately describe leak-off dynamics. Recognizing this constraint Shell decided that the

n the oil droplets deposition profile. The mechanisms and laws governing the internal damage with oil are different from those concerning sol


 NCS. In relation with the various water management actors (operators manufacturers researchers authorities) Total E&P Norge’s R&D
pandable sand screens and premium screens. Most of the wells produce 10 000 to 15 000 BFPD using electrical submersible pumps (ESPs)
pandable sand screens and premium screens. Most of the wells produce 10 000 to 15 000 BFPD using electrical submersible pumps (ESPs)

sents Constructed Treatment Wetlands (CTW) as a technology for the treatment of produced water and the facilitation of water reuse. The C
duction data from existing platforms future drilling activities and impact of artificial lift we can generate forecasts of produced water. Current

 ent are introduced and the question whether produced water can become an opportunity and a value creation rather than a legacy in any fie
ore frequently within the design window. Stable operation results in fewer shutdowns less breakdown maintenance less deferment less flar
s have been built and applied for Khafji field as presented by Ghoniem et al1 2. This paper is an extension to the previous papers for Khafji


pplied during well planning and drilling executions such as optimum well designs specific LWD/MWD tool selections low fluid loss drilling flu
pplied during well planning and drilling executions such as optimum well designs specific LWD/MWD tool selections low fluid loss drilling flu
e offshore platform on which the rigless operations were carried out posed a special challenge due to its proximity to two water injector platfo
 ighest productivity wells in the field’s history.   Oman has developed into a fast-paced fracturing arena with challenges similar to those

 aper will summarise key methods by which we have achieved such a high recovery factor namely (1) good well design and placement to en
a the knowledge and experience of the evaluators and the methodology and workflow used during the evaluation process. Although we dea
 re were no other proven mitigation techniques available it was decided to operate without mitigation. The strategy for this project was to let t
 re-evaluated in 2003 and it was concluded that there would be a risk that the maximum allowable H2S content in the facilities (i.e. 50 ppm(v
  in the High Pressure (HP) system and after three months testing significant increases in corrosion rates were seen. These were thought to
ed to the use of sulphur solvents; frequent pigging and inspection programs; corrosion monitoring the use of lined carbon steel materials and
ed an alarming increase with time casting doubts on future integrity assurance. As the materials used in the X and down stream receiving fa
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
olely rely on seismic data obsolete. We developed an adjoint-based optimization algorithm that rapidly identifies alternative optimal well-place
 . This paper describes the strategies employed by the team responsible for developing the reservoirs of the Harweel Cluster. The original vi
 This paper will present these challenges and introduce new technologies that can help to reduce project development cost by as much as 40

 ation of gas caps at dissimilar structural positions nor could it explain the existence of oil legs at pressures below the apparent (predicted) bu
ation to individual wells. “Data-to-information work processes have been mapped and automated as a natural part of the collaborative wo
 velocity and fluid holdup of different phases can change dramatically for a given flow rate. We present examples that encompass various re
mulation has demonstrated the ability of concurrent wells to enable simultaneous oil and gas production with minimal impact on oil recovery. T

  to the well’s detailed completion design. This is despite the fact that expensive advanced completions have become common during re




porosity and water saturation (Sw) uncertainty. This look-back based assessment of porosity and Sw uncertainty allows the impact of increas
data constraints. A strategic goal for Oil Company is mature fields redevelopment using new technology and approaches in order to enhanc
 rtainties typically makes such valuations non-trivial and mostly intractable to current modeling schemes. We demonstrate the approach with

 over primary development. it must aso be operated in an environmentally friendly manner. The water source chosen for a waterflood projec
of some 80kbpd but production declined rapidly because of the lack of any pressure support. Following the implementation of water injection
n be used in an optimization loop to iteratively improve well controls. We implemented the adjoint method and an associated optimization alg
 objective function with respect to control parameters. For computational reasons an initial optimization study was performed on a sector mod
 e and can be liquefied under certain conditions and waterflooding gives additional rock compaction. The fracture network has also been sign

 otal screening guidelines which often results in inconsistent treatment outcomes. With only pretreatment well data as input parameters the
be developed more efficiently. By reducing uncertainties about the reservoir the new technology helped optimize production eliminate sidetr
 nificant sub-seismic variations in the top reservoir topography. Therefore to help optimal well placement Oilexco used a new deep and direc
 ies (e.g. permeability field which may be nonuniform) and time-varying properties (e.g. pressure and saturation field).�As such it is a wel
  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
 ies (e.g. permeability field which may be nonuniform) and time-varying properties (e.g. pressure and saturation field).�As such it is a wel
  concluded that a connected aquifer was present and estimated its size. This information was sufficient for the operator to know that the we
 track.� It also presents a set of criteria to select the most suitable well to sidetrack.� Finally it allows leveraging all associated uncertain
  a more sophisticated workflow to optimize horizontal well placement. Interactive well planning was initially used to optimize the horizontal w
  the 4D interpretations conducted so far have indicated the need for simulation-model changes such as modified reservoir volumes in certain
 ancement measures relate to a number of different disciplines ranging from topsides modifications to well interventions to sub-surface. As th
  n of fluids using artificial lift including: scale; solids production; high GOR; early high water production; and also very high CO2 (80%). Solids
 ely ESPs were selected. A rigorous selection process identified three trial wells on the crest of the shallow ‘A’ sands.� These wells

 ew multilateral MRC wells equipped with intelligent completions. Until 2007 smart completions which are critical for water production contro
mine the correct value of a new gas well to protect against water encroachment. The Mahogany field used BP’s Top Down Reservoir Mo
 through subsea horizontal wells tied back to the Schiehallion floating production storage and offloading (FPSO) vessel. The combination of
 through subsea horizontal wells tied back to the Schiehallion floating production storage and offloading (FPSO) vessel. The combination of
mbination with technology support from world-class technical expert groups this allows effective implementation of surveillance and reservoir

 pensate Strategy-A offered the prospect of lower capex and earlier production. This development decision involved complex interactions be
 mize the planning and drilling of additional wells as part of the Phase 2 development drilling project. Bonga is a ‘brownfield’ that is not

 paper describes how all available subsurface data have been (re-)analysed and integrated resulting in a range of realistic dynamic reservoir
 production through the integration of Improved Oil Recovery (IOR) methodologies. A multi-disciplinary team studied and recommended the i
 options to modeling the coupled reservoir/wellbore/surface network system. In particular we explore how uncertainties in volumetrics and ca
  s supplied from a nearby field and compression facilities in Bokor.� However with ageing compressors and fluctuation in gas availability

  producers the processing of cycled gas (including sour gas treatment) the cost of the project compared to more conventional UGSs. Th
 oil and gas wells into gas injection and production wells. The processing of cycled gas (including sour-gas treatment). The cost of the proje
ells were added during the development of the field hence increasing the depletion rate. In this study after gathering necessary reservoir flui
 ccess in stringers and thus resulted in low production figures. PeriScope has persistently proven that a proactive well placement technology
 al logging while drilling (LWD) tool to geosteer the well in the horizontal section.� The LWD was unable to trace the sand while drilling acr

ysicist completion production and reservoir engineers facilities personnel and service company engineers.� Their task was to better unde

ng of the compressors. Following studies were carried out as part of the project: 1) Compare the response of wells in high-pressure area
e method has been successfully tested in a brown field with 165 stacked reservoirs. Reserves increased significantly compared to the offset f
 en undertaken manually. Our experience shows that one model requires about 9 man-months. As a result we tested a procedure to acceler
 itions of wells (producers injectors) and geological details (e.g. flow baffles). The results presented in this paper are expected to also apply
 gy available at the time of the platform installation. The current paper discusses optimization techniques using dynamic simulation with a co
ents the fluid flow in the well and pipelines from the couple point to the sink including the artificial lift system (Electrical Submersible Pump ES


  and connectivity were assessed in the first stage of the workflow. The second stage of the workflow focused on dynamic uncertainties. The
 ermal simulation models. The choice of design parameters and handling of uncertainties were addressed in a phased manner. First the sm


 nd net present value after including decisions in the design. The validation worked out properly reinforcing the confidence in the model sele




  in multiple history-matched models have shown that the proposed strategy improves recovery significantly. Two field examples are present
 ts. A series of simulation models were built to address above issues. A pilot study was initiated to evaluate the best possible scheme for fut

k capabilities are demonstrated on several examples involving diversified production strategies and multiple surface/subsurface simulators. O
k capabilities are demonstrated on several examples involving diversified production strategies and multiple surface/subsurface simulators. O
as requirements will change as will operating constraints.� The design of the processing facilities will need to accommodate these change


P have been produced to date. For the redevelopment study that kicked off in 2007 a 2006 repeat 3D seismic swath study gave information
AM has been at the heart of BP’s innovative optimization process PTL™ typically resulting in 20 MBOED of incremental production de

 y gas wells in Russia has used the latest sand failure prediction software which can quantify sand production so that gas production is opti
at 25% significantly less than for the best reservoirs in the field. After more than a decade shut-in secondary and tertiary recovery methods
ased well production opportunities were identified based on the standard methodology. Then to reduce uncertainties and risks associated w
s greater reservoir energy due to higher connectivity with the aquifer and higher formation compressibility. Acoustic properties of the Late Mi


ysis and optimization. The optimized WAG injection and production cycle is then carried forward to an IAM in order to accurately determine th
 imulator/optimiser which in turn reconfigures the intelligent well completion zones by use of Individual Control Valves (ICVs) and wellhead o
has been discovered. A reservoir simulation model has been constructed for the new discovery. This second reservoir is a gas condensate
 identified and solved. PEMEX E&P San Manuel complex produces in excess of 276 mmscf/d and 13 100 BOPD from 10 fields (mostly gas
 r workflow enables the various tasks in an integrated study to be assigned to project team members facilitates the flow of task outcomes be
sed optimization method in which the gradients are obtained with an adjoint formulation. We compared the results of the RO procedure to tw
rformance have resulted in implementation of an intensive monitoring program. This is to limit water production and to maintain/increase wat
 d recovery (Fig.1). The cluster development strategy addresses 23 clastic fields with a significant STOIIP base. A large integrated team of P

 which accounts for over 75% of the total field STOIIP. Production commenced from Ogbotobo in 1998 and to date various drilling campaign
 es and nine new wells. This paper describes the following: • Reservoir setting and production history. • Water injection philosophy. â€
oding was considered as the most suitable remedy to restore the reservoir pressure and well productivity considering all the parameters. Va
ol in the depletion plan across the multiple reservoir models that we can’t control. We can use surveillance to try to distinguish between m
ontainers is defined from individual reservoirs to total project level and resources are aggregated from bottom upward using either arithmetic
 folio theory that has shaped the financial markets over the past four decades and recently introduced to E&P) are applied instead of the con
 ear period. To reduce the complexity of the problem the world is split into only ten regions. In each region demand supply and recoverable
 l feedstock for other large scale chemicals such as olefins. Among the many methanol derivatives (olefins gasoline acetic acid hydrogen e
  end of the decade. It is making good progress and is overall more than 50% complete.| The project is currently in full swing both offshore a
owing separately towards a mixing point by the way of a compressor and centrifugal pumps. The mixture is sent to the multiphase equipment
 this constraint Shell decided that there is a need for unambiguous empirical data that do not suffer from the limitations associated with comm

e different from those concerning solid particles. Like solid particles oil tends to deposit preferentially at the core entrance but quickly a movi


horities) Total E&P Norge’s R&D department is strongly involved in the issues related to installation and operation of these technologies
electrical submersible pumps (ESPs). In these commingled completions the water cut rises from a few percent to 80% to 90% within the firs
electrical submersible pumps (ESPs). In these commingled completions the water cut rises from a few percent to 80% to 90% within the firs

d the facilitation of water reuse. The Chevron/Cawelo water reuse project and demonstration CTW located in California’s San Joaquin V
orecasts of produced water. Currently in B8/32 asset we produce about 68 000 bbl/day of water and an additional 20 000 bbl/day of water i

eation rather than a legacy in any field development is addressed. Introduction “There are alternative sources for energy. There are no
aintenance less deferment less flaring lower operational cost and sometimes even higher ultimate recovery.� The impact of process ins
ion to the previous papers for Khafji Field cited above.� The optimization approach presented in this paper is based on a field-wide produc


ool selections low fluid loss drilling fluids real-time geosteering data monitoring and the cleaning of the pay zone during completions were ap
ool selections low fluid loss drilling fluids real-time geosteering data monitoring and the cleaning of the pay zone during completions were ap
s proximity to two water injector platforms. The injection water accumulation in the drainage area covered by the wells of this platform becam
ena with challenges similar to those encountered in the tight gas fields of south Texas in the United States. Well productivity is highly depe

 ood well design and placement to ensure high rate and avoid early coning; (2) 4D seismic used to manage fluid contacts and identify unswep
evaluation process. Although we deal with dry gas reservoirs the challenge lies in the difficulty of solving relatively simple equations that resu
he strategy for this project was to let the reservoir sour and handle the H2S with sour-service materials and scavenging facilities topside. The
 content in the facilities (i.e. 50 ppm(v)) might be exceeded during the life time of the project. Given the positive experience with the injection
es were seen. These were thought to be related with the addition of nitrate to the Produced Water (PW). To investigate this more closely the
se of lined carbon steel materials and some case histories. The paper also addresses the challenges associated with well acidizing on sulph
  the X and down stream receiving facilities are not to be NACE 175 souring compliant and consider H2S released are hazard for safety. Star
d a recent model to simulate the impact of a surfactant on improved inhibitor retention which used data derived from laboratory experiments.
 entifies alternative optimal well-placement scenarios for a given geologic realization. Adjoint-based gradients approximate the sensitivities of
f the Harweel Cluster. The original vision has been bolstered by substantial near field discoveries during the last five years. The appraisal cha
  development cost by as much as 40% compared to conventional technologies� Application External studies (Steiner 2005) estimate a

res below the apparent (predicted) bubble point pressure. A fluid characterization model was performed in the El Trapial field in order to imp
 a natural part of the collaborative work environment between the platform and the offices. Use of time-lapse seismic. Draugen acquired seis
examples that encompass various reservoir management objectives well optimization and flow profiling.� Surveillance logs were acquired
with minimal impact on oil recovery. The proposed concept can significantly impact the portfolio of available gas reservoirs by delivering a co

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




certainty allows the impact of increasing quantity of data changing analytical workflows and updating interpretations to be examined. Based
 and approaches in order to enhance oil production. Brown fields are suffering from serious reservoir management problems and field redev
 We demonstrate the approach with an example involving a decision to be made for a marginal asset on where to place an injector well rela

ource chosen for a waterflood project is usually based on a number of different factors such as scaling tendency rock/fluid compatibility and
he implementation of water injection from 1991 onwards a plateau production of around 60-70kbopd was achieved for some five years (1994
d and an associated optimization algorithm in our in-house reservoir simulator. In addition to conventional well control options based on the w
tudy was performed on a sector model which showed promising results. Introduction St. Joseph is a mature oil field located 135km offshor
 fracture network has also been significantly impacted by stress changes compaction and resulting incremental shear displacement. The ion

nt well data as input parameters the neural networks developed in this work can accurately predict the post-treatment cumulative oil product
optimize production eliminate sidetracks and minimize well construction cost and risk. One of the main challenges of maintaining a horizon
   Oilexco used a new deep and directional LWD measurement in the Bottom Hole drilling Assembly in order to map the relative position of th
aturation field).�As such it is a well placement strategy governed purely by reservoir drainage objectives rather than infrastructure conside
 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
aturation field).�As such it is a well placement strategy governed purely by reservoir drainage objectives rather than infrastructure conside
  for the operator to know that the well would not be needed as a water injector and to justify a sidetrack from the downdip location to an upd
 s leveraging all associated uncertainties by linking the economic analysis to a Monte Carlo simulation which is critical for a sound managem
ally used to optimize the horizontal well location within the 3-D reservoir model ensuring a smooth trajectory near placement to the current o
 modified reservoir volumes in certain areas revised fault transmiss
ell interventions to sub-surface. As these disciplines originate from di
 nd also very high CO2 (80%). Solids issues are exacerbated on
 ow ‘A’ sands.� These wells are currently produced through g

 re critical for water production control in multilateral producers in th
ed BP’s Top Down Reservoir Modeling (TDRMTM) to test a hypoth
  (FPSO) vessel. The combination of water depth with strong winds
  (FPSO) vessel. The combination of water depth with strong winds
entation of surveillance and reservoir management activities in the field.

sion involved complex interactions between conflicting issues and the best way forward
nga is a ‘brownfield’ that is not immune to normal well and asset integrity issues a

a range of realistic dynamic reservoir models and how
eam studied and recommended the implementation of a program to drill a
 w uncertainties in volumetrics and capital and operating
ors and fluctuation in gas availability it is

red to more conventional UGSs. The main benefits expected from the project ar
gas treatment). The cost of the project compared to more conventional UGSs.
 er gathering necessary reservoir fluid production and
proactive well placement technology can be translated into maximum reserv
ble to trace the sand while drilling across the heterogeneous sa

ers.� Their task was to better understand the properties of the Vikulov an

sponse of wells in high-pressure area and low-pressure areas of the reservo
 significantly compared to the offset field development plan (FDP) while wat
 ult we tested a procedure to accelerate the matching using a program with
his paper are expected to also apply to (part
s using dynamic simulation with a coupled surface
em (Electrical Submersible Pump ESP) through a network simul


used on dynamic uncertainties. The results of the workflow defined the P10 P50 a
ed in a phased manner. First the smallest possible element of symmetr


 ing the confidence in the model selection. Finally the polynomial




 ntly. Two field examples are presented to demonstrate t
uate the best possible scheme for future management of lower reservoi

iple surface/subsurface simulators. One real field case that requires advance/compl
 iple surface/subsurface simulators. One real field case that requires advance/compl
 need to accommodate these changes while taking


seismic swath study gave information on the 2006 Gas Water Contact.
MBOED of incremental production delivered per year through identifying and

duction so that gas production is optimized while minimizing sand pro
ndary and tertiary recovery methods investigated
 uncertainties and risks associated with proposed activities fu
y. Acoustic properties of the Late Miocene reservoir rock in the Keple


M in order to accurately determine the well performance and the rese
Control Valves (ICVs) and wellhead or manifold in order
econd reservoir is a gas condensate system much smaller than the
00 BOPD from 10 fields (mostly gas and condensates but also oil fields) thr
cilitates the flow of task outcomes between project team members and creates
he results of the RO procedure to two alternative approaches:
duction and to maintain/increase water injection capacity. For the
P base. A large integrated team of PE staff have spent 3 years to addr

 and to date various drilling campaigns have been carried out to optimize development o
y. • Water injection philosophy. • Design considerations for frac
 y considering all the parameters. Various waterflooding plans were design
 illance to try to distinguish between models if we can identify the su
bottom upward using either arithmetic or probabilisti
  E&P) are applied instead of the conventional deterministic
 on demand supply and recoverable gas resources of the vari
 ns gasoline acetic acid hydrogen etc) there is great promise for dimethyl-ether
 currently in full swing both offshore and onshore. Offshore
  is sent to the multiphase equipment to be tested before coming back to the s
m the limitations associated with commercially available coreflood s

 the core entrance but quickly a moving front of oil drople


n and operation of these technologies. The work described in this study was perf
 percent to 80% to 90% within the first 2 years of production. Typically sidetrac
 percent to 80% to 90% within the first 2 years of production. Typically sidetrac

ated in California’s San Joaquin Valley is presented in order to highl
n additional 20 000 bbl/day of water is expected from new projects and artifici

ve sources for energy. There are no alternatives to fresh water Can Produced Water
covery.� The impact of process instabilities on overall well or facility perfo
paper is based on a field-wide production plann


pay zone during completions were applied to maximize res
pay zone during completions were applied to maximize res
d by the wells of this platform became evident through curr
 ates. Well productivity is highly dependent on hydraulic fract

  ge fluid contacts and identify unswept area for infill target
   relatively simple equations that result from a combination of compl
 nd scavenging facilities topside. The facilities were designed
 ositive experience with the injection of nitrate in oth
   To investigate this more closely the SMC was modified by inc
  sociated with well acidizing on sulphur corrosion in surface and subsurface opera
S released are hazard for safety. Starting December 2005 production chemistr
 derived from laboratory experiments. The focus of this p
 ients approximate the sensitivities of a suitable objective function with r
  the last five years. The appraisal challenges the emerging study results and
 al studies (Steiner 2005) estimate a global (recoverable) resource of some 500 B boe (= 3000

d in the El Trapial field in order to improve the unde
 apse seismic. Draugen acquired seismic of excellent quality in 1
 .� Surveillance logs were acquired in these wells to obtain key inputs for prod
able gas reservoirs by delivering a cost effective technology soluti

only be justified if it is shown to be paid-back by improved overall project eco




 erpretations to be examined. Based on the standard deviation or range of the
management problems and field redevelopment strategies are based on signi
 n where to place an injector well relative to a fault. The exampl

 endency rock/fluid compatibility and possibility of bacterial
 s achieved for some five years (1994-1997) declining to the current net oil product
 al well control options based on the wellâ€
mature oil field located 135km offshore Sabah Malaysia. The oil
 emental shear displacement. The ion content of the inje

post-treatment cumulative oil production of the well one month after treat
   challenges of maintaining a horizontal wellbore inside a thin hyd
 rder to map the relative position of the drainhole to the ov
 es rather than infrastructure considerations which may favor a mo
  exhibited consistently better performance and minimum variance. STOIIP and PPM tec
 les. It is generated from the numerical reservoir models developed from
 es rather than infrastructure considerations which may favor a mo
   from the downdip location to an updip location. When
which is critical for a sound management decision. Whereby
  tory near placement to the current oil-water contact an

				
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