Nov-09
NOTES:
The papers listed here have been obtained by search SPE and IPTC papers post 2005 on the SPE's OnePetro
The papers relating to reservoir engineering have been catergorised for inclusion on the reservoirengineering.org.uk website
The affiiations searched were;
Total No Papers Reservoir Engineering Related
BP 551 175
Shell 575 279
Chevron 482 238
ConocoPhillips 191 68
Marathon 55 37
Total 255 129
Schlumberger 1130 563
Imperial College, London 95 53
Heriot Watt University, Edinburgh 235 175
(Anywhere in Article)
Total 3569 1717
Total number of papers published post 2005 = 10,000
35% of papers published categorised
Paper
Organisation Source No. Chapter
CONOCO SPE 112130 Corporate Process
CONOCO SPE 113933 EOR/IOR
CONOCO SPE 102352 Flow Assurance
CONOCO SPE 116593 Flow Assurance
CONOCO SPE 115672 Flow Assurance
CONOCO SPE 100065 Heavy Oil
CONOCO SPE 112638 Heavy Oil
CONOCO SPE 113173 Heavy Oil
CONOCO SPE 117792 Heavy Oil
CONOCO SPE 117571 Heavy OIl
CONOCO SPE 105392 Heavy Oil
CONOCO SPE 104119 HP/HT
CONOCO SPE 116583 Low Permeability Reservoirs
CONOCO SPE 110542 Reservoir Description
CONOCO SPE 109971 Reservoir Description
CONOCO SPE 110340 Reservoir Description
CONOCO SPE 103803 Reservoir Description
CONOCO SPE 115045 Reservoir Description
CONOCO IPTC 11813 Reservoir Description
CONOCO SPE 103083 Reservoir Description
CONOCO SPE 100307 Reservoir Description
CONOCO SPE 101556 Reservoir Development
CONOCO IPTC 11115 Reservoir Management
CONOCO SPE 117433 Reservoir Management
CONOCO SPE 102439 Reservoir Management
CONOCO SPE 100984 Reservoir Management
CONOCO SPE 117434 Reservoir Modelling
CONOCO SPE 118722 Reservoir Modelling
CONOCO SPE 118752 Reservoir Modelling
CONOCO SPE 119029 Reservoir Modelling
CONOCO SPE 109867 Reservoir Modelling
CONOCO SPE 103670 Reservoir Modelling
CONOCO SPE 90009 Reservoir Modelling
CONOCO SPE 116292 Reservoir Modelling
CONOCO SPE 113474 Reservoir Performance
CONOCO SPE 110132 Reservoir Performance
CONOCO SPE 108699 Reservoir Performance
CONOCO SPE 100607 State of the Nation
CONOCO SPE 103775 State of the Nation
CONOCO SPE 115753 Surveillence
CONOCO SPE 117244 Unconventional Reservoirs
CONOCO SPE 114995 Unconventional Reservoirs
CONOCO SPE 114778 Unconventional Reservoirs
CONOCO SPE 107705 Unconventional Reservoirs
CONOCO SPE 114169 Unconventional Reservoirs
CONOCO SPE 114485 Unconventional Reservoirs
CONOCO IPTC 11333 Unconventional Reservoirs
CONOCO SPE 116688 Unconventional Reservoirs
CONOCO SPE 114172 Unconventional Reservoirs
CONOCO SPE 102094 Unconventional Reservoirs
CONOCO SPE 114912 Well Deliverability
CONOCO SPE 117489 Well Deliverability
CONOCO SPE 114011 Well Deliverability
CONOCO SPE 106050 Well Deliverability
CONOCO SPE 107793 Well Deliverability
CONOCO SPE 114804 Well Deliverability
CONOCO SPE 97121 Well Deliverability
CONOCO SPE 103617 Well Deliverability
CONOCO SPE 107780 Well Deliverability
CONOCO SPE 105541 Well Deliverability
CONOCO SPE 105542 Well Deliverability
CONOCO SPE 121498 Well Deliverability
CONOCO SPE 102802 Well Deliverability
CONOCO SPE 103244 Well Deliverability
CONOCO SPE 77363 Well Deliverability
CONOCO SPE 107978 Well Deliverability
CONOCO SPE 116711 Well Deliverability
CONOCO SPE 117435 Well Testing
CHEVRON SPE 121293 Reservoir Description
CHEVRON SPE 90539 Reservoir Description
CHEVRON SPE 102894 Reservoir Description
CHEVRON SPE 103486 Reservoir Description
CHEVRON SPE 96308 Reservoir Description
CHEVRON SPE 102741 Reservoir Description
CHEVRON IPTC 11488 Reservoir Description
CHEVRON SPE 109810 Reservoir Description
CHEVRON SPE 110515 Reservoir Description
CHEVRON SPE 114183 Reservoir Description
CHEVRON SPE 105087 Reservoir Description
CHEVRON SPE Reservoir Management
CHEVRON IPTC 11219 Reservoir Management
CHEVRON SPE 100656 Reservoir Management
CHEVRON SPE 102988 Reservoir Management
CHEVRON SPE 89755 Reservoir Management
CHEVRON SPE 102557 Reservoir Management
CHEVRON SPE 128335 Reservoir Management
CHEVRON IPTC 11551 Reservoir Management
CHEVRON SPE 98567 Reservoir Management
CHEVRON SPE 108893 Reservoir Management
CHEVRON SPE 116528 Reservoir Management
CHEVRON SPE 107732 Reservoir Management
CHEVRON IPTC 11540 Reservoir Management
CHEVRON SPE 120102 Reservoir Management
CHEVRON SPE 101028 Reservoir Management
CHEVRON SPE 98198 Reservoir Management
CHEVRON SPE 99959 Reservoir Modelling
CHEVRON SPE 112257 Reservoir Modelling
CHEVRON SPE 111921 Reservoir Modelling
CHEVRON SPE 95523 Reservoir Modelling
CHEVRON SPE 107200 Reservoir Modelling
CHEVRON SPE 106176 Reservoir Modelling
CHEVRON SPE 90058 Reservoir Modelling
CHEVRON SPE 90065 Reservoir Modelling
CHEVRON SPE 119138 Reservoir Modelling
CHEVRON SPE 121299 Reservoir Modelling
CHEVRON SPE 110081 Reservoir Modelling
CHEVRON SPE 114983 Reservoir Modelling
CHEVRON SPE 119002 Reservoir Modelling
CHEVRON SPE 119172 Reservoir Modelling
CHEVRON SPE 119165 Reservoir Modelling
CHEVRON SPE 103194 Reservoir Modelling
CHEVRON SPE 118963 Reservoir Modelling
CHEVRON SPE 118839 Reservoir Modelling
CHEVRON SPE 113904 Reservoir Modelling
CHEVRON SPE 102070 Reservoir Modelling
CHEVRON SPE 111916 Reservoir Modelling
CHEVRON IPTC 12572 Reservoir Modelling
CHEVRON SPE 106086 Reservoir Modelling
CHEVRON SPE 106435 Reservoir Modelling
CHEVRON SPE 101144 Reservoir Modelling
CHEVRON SPE 99619 Reservoir Modelling
CHEVRON SPE 84469 Reservoir Modelling
CHEVRON SPE 120053 Reservoir Modelling
CHEVRON SPE 119183 Reservoir Modelling
CHEVRON SPE 96260 Reservoir Modelling
CHEVRON SPE 112124 Reservoir Modelling
CHEVRON SPE 99937 Reservoir Modelling
CHEVRON SPE 99979 Reservoir Modelling
CHEVRON IPTC 11489 Reservoir Modelling
CHEVRON SPE 103258 Reservoir Modelling
CHEVRON SPE 90091 Reservoir Modelling
CHEVRON SPE 121335 Reservoir Modelling
CHEVRON IPTC 12480 Reservoir Modelling
CHEVRON SPE 95557 Reservoir Modelling
CHEVRON SPE 103901 Reservoir Modelling
CHEVRON SPE 102491 Reservoir Modelling
CHEVRON SPE 109686 Reservoir Modelling
CHEVRON SPE 103159 Reservoir Modelling
CHEVRON SPE 107468 Reservoir Modelling
CHEVRON SPE 121393 Reservoir Modelling
CHEVRON SPE 93324 Reservoir Modelling
CHEVRON SPE 100384 Reservoir Modelling
CHEVRON SPE 95528 Reservoir Modelling
CHEVRON SPE 84501 Reservoir Modelling
CHEVRON SPE 128605 Reservoir Modelling
CHEVRON SPE 118969 Reservoir Modelling
CHEVRON SPE 121305 Reservoir Modelling
CHEVRON SPE 92991 Reservoir Modelling
CHEVRON SPE 111571 Reservoir Modelling
CHEVRON SPE 119177 Reservoir Modelling
CHEVRON SPE 114099 Reservoir Modelling
CHEVRON SPE 99833 Reservoir Modelling
CHEVRON SPE 118709 Reservoir Modelling
CHEVRON SPE 93395 Reservoir Modelling
CHEVRON SPE 119190 Reservoir Modelling
CHEVRON SPE 90713 Reservoir Modelling
CHEVRON SPE 103295 Reservoir Modelling
CHEVRON SPE 99465 Reservoir Modelling
CHEVRON SPE 109964 Reservoir Modelling
CHEVRON SPE 81496 Reservoir Modelling
CHEVRON SPE 105208 Reservoir Modelling
CHEVRON SPE 100526 Reservoir Modelling
CHEVRON SPE 92965 Reservoir Modelling
CHEVRON SPE 119171 Reservoir Modelling
CHEVRON SPE 109876 Reservoir Modelling
CHEVRON SPE 89754 Reservoir Modelling
CHEVRON SPE 109262 Reservoir Modelling
CHEVRON SPE 109765 Reservoir Modelling
CHEVRON SPE 109868 Reservoir Modelling
CHEVRON SPE 114697 Reservoir Modelling
CHEVRON SPE 114697 Reservoir Modelling
CHEVRON SPE 100209 Reservoir Performance
CHEVRON SPE 114909 Reservoir Performance
CHEVRON SPE 92973 Reservoir Performance
CHEVRON SPE 122357 Reservoir Performance
CHEVRON SPE 96448 Reservoir Performance
CHEVRON SPE 91393 Reservoir Performance
CHEVRON SPE 106994 Reservoir Performance
CHEVRON SPE 116758 State of the Nation
CHEVRON SPE 113011 State of the Nation
CHEVRON SPE 109670 State of the Nation
CHEVRON SPE 98746 State of the Nation
CHEVRON SPE 83995 State of the Nation
CHEVRON SPE 116580 State of the Nation
CHEVRON SPE State of the Nation
CHEVRON SPE 116916 Surveillence
CHEVRON SPE 107268 Surveillence
CHEVRON IPTC 12628 Surveillence
CHEVRON IPTC 12343 Surveillence
CHEVRON SPE 114981 Surveillence
CHEVRON SPE 114352 Surveillence
CHEVRON SPE 105200 Surveillence
CHEVRON SPE 110097 Surveillence
CHEVRON SPE 97912 Surveillence
CHEVRON SPE 123320 Surveillence
CHEVRON SPE 109608 Surveillence
CHEVRON SPE 102200 Surveillence
CHEVRON SPE 123145 Surveillence
CHEVRON SPE 109855 Unconventional Reservoirs
CHEVRON SPE 96018 Unconventional Reservoirs
CHEVRON SPE 128337 Well Deliverability
CHEVRON SPE 89753 Well Deliverability
CHEVRON SPE 100834 Well Deliverability
CHEVRON SPE 101987 Well Deliverability
CHEVRON SPE 112531 Well Deliverability
CHEVRON SPE 101821 Well Deliverability
CHEVRON SPE 101019 Well Deliverability
CHEVRON SPE 102326 Well Deliverability
CHEVRON SPE 108142 Well Deliverability
CHEVRON SPE 109247 Well Deliverability
CHEVRON SPE 102990 Well Deliverability
CHEVRON SPE 103433 Well Deliverability
CHEVRON SPE 102773 Well Deliverability
CHEVRON SPE 84399 Well Deliverability
CHEVRON SPE 90541 Well Deliverability
CHEVRON SPE 103308 Well Deliverability
CHEVRON IPTC 11332 Well Deliverability
CHEVRON SPE 103266 Well Deliverability
CHEVRON SPE 116764 Well Deliverability
CHEVRON SPE 109588 Well Deliverability
CHEVRON SPE 108088 Well Deliverability
CHEVRON SPE 128334 Well Deliverability
CHEVRON SPE 98563 Well Deliverability
CHEVRON SPE 112394 Well Deliverability
CHEVRON SPE 110395 Well deliverability
CHEVRON SPE 106707 Well Deliverability
CHEVRON SPE 112084 Well Deliverability
CHEVRON SPE 107440 Well Deliverability
CHEVRON SPE 103821 Well Deliverability
CHEVRON SPE 86504 Well Deliverability
CHEVRON SPE 98221 Well Deliverability
CHEVRON SPE 122630 Well Deliverability
CHEVRON SPE 102669 Well Deliverability
CHEVRON SPE 111431 Well Deliverability
CHEVRON SPE 98375 Well Deliverability
CHEVRON SPE 110272 Well Testing
CHEVRON SPE 105134 Well Testing
CHEVRON SPE 113903 Well Testing
CHEVRON SPE 112732 Well Testing
Section Subject
CoP's OOC Ekofisk
WAG Kuparuk Project Performance
Modelling - Slug Tracking Case Study
Network Design Offshore Gas
Subsea Pipelines
Complex Wells Flow Behaviour
Complex Wells
ESP
Reservoir Modelling Reaction-Diffusion Processes
SAGD Expanding Solvent
Thermal Recovery Carbonate Reservoir
Horizontal Well Clean-up
Static Reservoir Model Permeability
Fault Zone Modelling
Formation Evaluation Deep Reading Resitivity
Formation Evaluation LWD
Formation Evaluation Pressure Testing while Drilling
Formation Evaluation Pressure Testing while Drilling
Shared Earth Modelling Seismic Integration
Static Reservoir Model minimodels - SAG
Static Reservoir Model Permeability
Integrated Asset Optioneering Process
Modelling - Integrated Asset Large Well Count
Performance Evaluation Novel Statistical Analysis
Produced Water Management XJG Fields
Thin Oil Rim IOR
Analytical Model SAGD
Complex Reservoir Models Solution Technique
Complex Reservoir Models Solution Technique
Coupled Geomechanical/Compositional Solution Technique
Coupled Geomechanical/Compositional
Gas Lift Optimisation Integrated in Reservoir Simulation
Gridding PEBI
Inflow Profiling Complex wells
Mechanism - Gas Assisted Drainage Physical Models
Mechanisms - Gas Assisted Drainage Visual Models
Naturally Fractured Reservoirs Lab Testing - Transfer Functions
Province Comparison UKCS vs Alaska North Slope
Unconventional Reservoirs China
Water Entry Detection Gas Wells
Bitumen Recovery XSAGD
Coalbed Methane P/z Analysis
Coalbed Methane Permeability
Coalbed Methane Production Analysis
Coalbed Methane Reservoir Management
Coalbed Methane Well Testing
Reservoir Description Pressure Dependent Permeability
Shale Gas Production Analysis
Stimulation
Tar Sands
Artificial Lift Formation Powered Jet Pump
Artificial Lift SAGD
Completion Optimisation Big Bore Design
Fracture Design Candidate selection
Fracture Performance Chalk reservoirs
Fracturing Massive Annular Fracturing
Horizontal Well Openhole
Lab Testing - Fracturing Heterogeneity
Modelling - Acid treatment Horizontal Well
Sand Control Completion Optimisation
Sand Control Failure
Sand Management Clean-out
Sand Management Observations Post-Failure
Sand Management
Skin Factor Model Horizontal wells
Stimulation Acid Fracturing
Water and Condensate Blocks Chemical Treatment
Horizontal WElls Thermal Transient Analysis
Natural Fracture Detection PLT Interpretation
NMR Interpretation
Permeability PLT Interpretation
Permeability PLT Interpretation
Porosity Modelling Carbonate Reservoirs
Relative Permeability Correlation Gas Condensate
Reservoir Connectivity Downhole Fluid Analysis
SCAL Gas Condensate
SCAL Thermal Tests
SCAL Thermal Tests
Static Reservoir Model Case Study
Gas Condensate Development
Modelling - Experimental Design Development Optimisation
Modelling - Experimental Design Tahiti Field
Modelling - Experimental Design Tahiti Field
Modelling - Experimental Design Thin Oil Rim
Modelling - Integrated Asset Development Optimisation
Modelling - Integrated Asset Infill Well Performance
Produced Water Management Greater Burgan Field
Produced Water Management
Produced Water Management
Production Optimisation Mature Fields
Sour Reservoir
Uncertainty Management Multiple Reservoirs
Uncertainty Management Quantifying Uncertainty
Well Intervention Candidate Selection
Well Placement Optimisation Production Potential maps
Adjoint Based Simulation Production Optimisation
Adjoint Based Simulation Well Placement Optimisation
Analytical - Net Voidage Curve Pressure response
Annular Flow Model Two Phase
Assisted HM Justified
Assisted HM Kernel principal component analysis
Assisted HM LBFGS Algorithm
Assisted HM Simultaneous perturbation stochastic approximation
Assisted HM Statistical Moment Equations
Capacitance-Resistive Technique Giant Fields
Capacitance-Resistive Technique Waterflood
Capacitance-Resistive Technique Waterflood
Chemical Flood Simulator Development
Complex Physics Modelling Heavy Oil
Complex Physics Modelling Phase-Component Partitioning
Coupled EOS/Sufactant Model
Coupled Reservoir/Geomechanical Model Ensemble based Application
Coupled Reservoir/Petro Elastic Model 4D Seismic
Coupled Reservoir/Surface Model Deepwater
Coupled Well/Reservoir Thermal
Decline Curve Analysis
Discrete Fracture Modelling Carbonate reservoir
Ensemble based Application Upscaling
Finite Volume Formulation Gridding
Fractional Flow Analysis Horizontal Wells
Gas Condensate Accuracy
Gas Potential Determination
Giant Field
Heterogeneity Modelling Multiscale Finite Volume Formulation
Inflow Performance Temperation Prediction
Injector Producer Modelling Neural-Network
Integrated Asset Probabilistic Production Forecasting
Integrated Asset Probabilistic Production Forecasting
Material Balance Complex Dynamic Behaviour
Material Balance P/Z
Modelling - Assisted Hm Well Placement Optimisation
Modelling - Multilateral Wells Multilayered Reservoirs
Modelling - Optimised Simulation Production Optimisation
Modelling Data Integration History Matching
Naturally Fractured Reservoirs Finite Volume Formulation
Naturally Fractured Reservoirs Upscaling
Naturally Fractured Reservoirs Upscaling
Near Wellbore Stability Geomechanical
Neural-Network History Matching
Parametric Modelling Ensemble based Application
Prediction Uncertainty PUNQ-S3 Problem
Pressure and Rate Interpretation Diagnostic Tool
Probabilistic Production Forecasting Gas Condensate
Probabilistic Production Forecasting
Probabilistic Production Forecasting
Production Constraints Feedback Controllers
Production Optimisation Ensemble based Application
Real Time Updating Ensemble based Application
Real Time Updating Ensemble based Application
Real Time Updating Ensemble based Application
Shared Earth Modelling Deepwater
Simplified Workflow Mature Fields
Simulation Experimental Design
Simulation Finite Volume Framework
Simulation Multi-D Transport Equations Implemented
Steamflood Modelling parameters
Streamline Gridding
Streamline History Matching
Streamline History Matching
Streamline Upscaling
Uncertainty Management Global Optimisation Methods
Uncertainty Management Probablistic Production Forecast
Upscaling Adaptive local-global
Upscaling Adaptive Reconstruction
Water Front Tracking
Wellbore Flow Gas-Condensate
Wellbore Flow Horizontal Wells
Wellbore Flow Temperadture Prediction
Wellbore Flow Two Phase
Wellbore Stability Modelling
Wellbore Stability Modelling
Breakthrough Profiling Temperature Effect
Fault Reactivation Steamflooding
Heterogeneity Statistical Moment Equations
Mechanism Acid Breakthrough
Mechanism Rel. Perm. Hysteresis
Mechanism Water Vaporization
Naturally Fractured Reservoirs Shared Earth Modelling
Decision Making Review
Development Deepwater - GOM
Flow Assurance Deepwater
Fracture Diagnostics Clean-up
Gravel Packing Horizontal Wells
Inflow Performance Analytical
Produced Water Management
4D Seismic Enfield Field
Downhole Sensors Placement
Inflow Profiling PLT Interpretation
Inflow Profiling Temperature Data
PLT Interpretation Gas-Liquid Slipage
PLT Interpretation Multiphase Flow Models
Production Allocation Optimisation
Rate and Pressure Interpretation Downhole Gauges
Steamflood Monitoring Temperature Data
Time Lapsed Logging Formation Evalustion
Water Sweep Efficiency Carbon/Oxygen
Waterflood Monitoring
Well Monitoring Automated
Coal
Well Type Optimisation CBM
Artificial Lift Gas Lift
Completion Optimisation Gas Condensate
Complex Wells Carbonate Reservoir
Formation Damage/High Velocity Flow Productivity Impairment
Fracture Design Frac Fluids
Fracture Design Non-Darcy/Multiphase
Fracture Design Water Control
Fracture Diagnostics Clean-up/Damage Mitigation
Fracture Diagnostics Microseismic Monitoring
Fracture Diagnostics Non-Darcy Effects
Fracture Diagnostics Water Injector Fracturing
Gas Condensate Deliverability Distinguished Lecture
High Velocity Coefficient Two Phase Flow
Inflow Performance Profiling
Inflow Profiling Temperature Data
Intelligent Well Production Optimisation
Liquid Loading Dual Lateral
Liquid Loading
Liquid Loading
Modelling - Coupled Reservoir/Geomechanical Cavity Completion
Perforation Methods Propellant assisted
Perforation Methods
Sand Control Deepwater
Sand Control Deepwater
Sand Control Gravel Pack
Sand Control Horizontal Wells
Sand Control Screen Failure
Sand Control Screenless Completions
Sand Control Steamflood
Stimulation Acid treatment
Stimulation Acid treatment
Stimulation Acid treatment
Stimulation Gas Condensate
Stimulation Surfactant Fracturing
Water Blocking Gas Condensate
Analysis - Fluivial Reservoir PTA/Seismic Attribute
Analysis - Horizontal Wells Carbonate Reservoir
Analysis - Multiphase 2 Phase
Sand Prediction Pre Drill DST Prediction
Title
Online Production Optimisation on Ekofisk
Kuparuk MWAG Project After 20 Years
Pipelines Slugging and Mitigation: Case Study for Stability and Production Optimization
Efficient Conceptual Design of an Offshore Gas Gathering Network
Effect of System Pressure on Restart Conditions of Subsea Pipelines
Rate-Time Flow Behavior of Heavy Oil From Horizontal and Multilateral Wells
The Use of Multilateral Well Designs for Improved Recovery in Heavy-Oil Reservoirs
ESP Operation, Optimization, and Performance Review: ConocoPhillips China Inc. Bohai Bay Project
Accurate Numerical Simulation of Reaction-Diffusion Processes for Heavy Oil Recovery
Expanding Solvent SAGD in Heavy Oil Reservoirs
Application of Thermal Recovery Processes in Heavy Oil Carbonate Reservoirs
Openhole Cleanup of Deep, High-Temperature Horizontal Wells With a Chelant-Based Acid System—Case Histories From In
Modeling Permeability in Tight Gas Sands Using Intelligent and Innovative Data Mining Techniques
Fluid Flow in a Fractured Reservoir Using a Geomechanically-Constrained Fault Zone Damage Model for Reservoir Simulation
A New Azimuthal Deep-Reading Resistivity Tool for Geosteering and Advanced Formation Evaluation
Combining Advanced Real-Time LWD Answers With Accurate and Flexible 3D Rotary-Steerable System for Proactive Reservo
Formation Pressure Testing While Drilling in Bohai Bay's Challenging Environment
Reservoir Fluid Evaluation from Real Time Pressure Gradient Analysis: Discussions on Principles, Workflow, and Applications
Incorporating Seismic Characterization Results into Bul Hanine Geological Model
Permeability Modeling for the SAGD Process Using Minimodels
Permeability Determination of the PL19-3 Field for Geologic Model Input
Field Development Plan by Optioneering Process Sensitive to Reservoir and Operational Constraints and Uncertainties
Reservoir Optimization and Monitoring: Mauddud Reservoir—Bahrain Field
An Unconventional But Definitive Analysis of a Field's Production Improvement
Production Diagnostics and Water Control for the XJG Fields, South China Sea
Identifying the Improved-Oil-Recovery Potential for a Depleted Reservoir in the Betty Field, Offshore Malaysia
A New Analytical Model for Conduction Heating during the SAGD Circulation Phase
Studies of Robust Two Stage Preconditioners for the Solution of Fully Implicit Multiphase Flow Problems
Towards a New Generation of Physics Driven Solvers for Black Oil and Compositional Flow Simulation
A New Solution Procedure for a Fully Coupled Geomechanics and Compositional Reservoir Simulator
Development of a Coupled Geomechanics Model for a Parallel Compositional Reservoir Simulator
Implementation of a Total-System Production-Optimization Model in a Complex Gas-Lifted Offshore Operation
Sequentially Adapted Flow-Based PEBI Grids for Reservoir Simulation
An Interpretation Method of Downhole Temperature and Pressure Data for Flow Profiles in Gas Wells
Range of Operability of Gas-Assisted Gravity Drainage Process
Mechanisms and Performance Demonstration of the Gas-Assisted Gravity-Drainage Process Using Visual Models
Impacts From Fractures On Oil Recovery Mechanisms In Carbonate Rocks At Oil-Wet And Water-Wet Conditions—Visualizin
U.K. North Sea and Alaska North Slope: A Comparative Analysis of Petroleum Provinces
Will the Blossom of Unconventional Natural Gas Development in North America Be Repeated in China?
Field Application of an Interpretation Method of Downhole Temperature and Pressure Data for Detecting Water Entry in Inclined
Thermal Efficiency and Acceleration Benefits of Cross SAGD (XSAGD)
Application of Flowing p/Z* Material Balance for Dry Coalbed-Methane Reservoirs
Predicting Sorption-Induced Strain and Permeability Increase With Depletion for CBM Reservoirs
Production Data Analysis of Coalbed-Methane Wells
Coalbed Methane Pilots: Timing, Design and Analysis
Case Study: Production Data and Pressure Transient Analysis of Horseshoe Canyon CBM Wells
Spatial Variation of San Juan Basin Fruitland Coalbed Methane Pressure Dependent Permeability: Magnitude and Functional F
Production Data Analysis of Shale Gas Reservoirs
Stimulating Unconventional Reservoirs: Lessons Learned, Successful Practices, Areas for Improvement
Quantifying Resources for the Surmont Lease with 2D Mapping and Multivariate Statistics
Formation Powered Jet Pump Use at Kuparuk Field in Alaska
SAGD Gas Lift Completions and Optimization: A Field Case Study at Surmont
Revised Big Bore Well Design Recovers Original Bayu-Undan Production Targets
Horizontal Fracture Stimulation Success in the Alpine Formation, North Slope, Alaska
Well Productivity In North Sea Chalks Related To Completion And Hydraulic Fracture Stimulation Practices
Massive Annular Fracturing Practices in BJC Gas Field, Sichuan, China
Predicting Horizontal-Openhole-Completion Success on the North Slope of Alaska
Laboratory Hydraulic Fracturing Test on a Rock With Artificial Discontinuities
An Acid-Placement Model for Long Horizontal Wells in Carbonate Reservoirs
Magnolia Deepwater Experience—Frac-Packing Long Perforated Intervals in Unconsolidated Silt Reservoirs
Lessons Learned on Sand-Control Failure and Subsequent Workover at Magnolia Deepwater Development
Cleaning Large-Diameter Proppant in Low-Bottomhole Pressure, Extended-Reach Wells With Concentric Coiled Tubing Vacuu
Field and Laboratory Observations of Post-Failure Stabilizations During Sand Production
Use of Reservoir Formation Failure and Sanding Prediction Analysis for Viable Well-Construction and Completion-Design Optio
A New Skin-Factor Model for Perforated Horizontal Wells
Recent Acid-Fracturing Practices on Strawn Formation in Terrell County, Texas
A New Solution to Restore Productivity of Gas Wells With Condensate and Water Blocks
Thermal Transient Analysis Applied to Horizontal Wells
Using PLT Data to Estimate the Size of Natural Fractures
Limits of 2D NMR Interpretation Techniques to Quantify Pore Size, Wettability, and Fluid Type: A
Numerical Sensitivity Study
Permeability From Production Logs - Method and Application
Permeability From Production Logs—Method and Application
3D Porosity Modeling of a Carbonate Reservoir Using Continuous Multiple-Point Statistics
Simulation
Relative Permeability of Gas-Condensate Fluids: A General Correlation
Predicting Downhole Fluid Analysis Logs to Investigate Reservoir Connectivity
Experimental Determination of Relative Permeabilities for a Rich Gas/Condensate System Using
Live Fluid
Oil Recovery and Fracture Reconsolidation of Diatomaceous Reservoir Rock by Water Imbibition at
High Temperature
Alteration of Reservoir Diatomites by Hot Water Injection
The Wafra First Eocene Reservoir, Partitioned Neutral Zone (PNZ), Saudi Arabia and Kuwait:
Geology, Stratigraphy, and Static Reservoir Modeling
Engineer Your Gas/Condensate Systems, Reservoir to Sales Meter
The Jurassic-Age Marrat Reservoir at Humma Field, Partitioned Neutral Zone (PNZ), Saudi Arabia
and Kuwait—Utilization of a Probabilistic, Two Stage Design of Experiments Workflow for
Reservoir Characterization and Management
Tahiti: Development Strategy Assessment Using Design of Experiments and Response Surface
Methods
Tahiti Field: Assessment of Uncertainty in a Deepwater Reservoir Using Design of Experiments
Production Strategy for Thin-Oil Columns in Saturated Reservoirs
Integrated Optimization of Field Development, Planning, and Operation
A Practical Approach to Initial Production (IP) Rate Estimation for Infill Oil Wells
Effluent Water Disposal Experiences in the Greater Burgan Field of Kuwait
Constructed Treatment Wetlands for the Treatment and Reuse of Produced Water in Dry Climates
Produced-Water Management Alternatives for Offshore Environmental Stewardship
Horizontal Well Best Practices to Reverse Production Decline in Mature Fields in South China Sea
Improving Reserves and Production Using a CO2 Fluid Model in El Trapial Field, Argentina
Modeling Uncertainties of a Gas
Quantifying Uncertainty in Carbonate Reservoirs—Humma Marrat Reservoir, Partitioned Neutral
Zone (PNZ), Saudi Arabia and Kuwait
Using Neural Networks for Candidate Selection and Well Performance Prediction in Water-Shutoff
Treatments Using Polymer Gels—A Field Case Study
Closing the Loop Between Reservoir Modeling and Well Placement and Positioning
Production Optimization With Adjoint Models Under Nonlinear Control-State Path Inequality
Constraints
Efficient Well Placement Optimization With Gradient-Based Algorithms and Adjoint Models
Analytical Method for Diagnosing and Predicting Pressure Response With Injection in Waterflood
Reservoirs Using Net Voidage Curve
A Simple Model for Annular Two-Phase Flow in Wellbores
Improved Convergence Efficiency in an Assisted-History-Matching Experiment
A New Approach to Automatic History Matching Using Kernel PCA
An Improved Implementation of the LBFGS Algorithm for Automatic History Matching
A Stochastic Optimization Algorithm for Automatic History Matching
Dynamic Data Integration and Quantification of Prediction Uncertainty Using Statistical Moment
Equations
Improvements in Capacitance-Resistive Modeling and Optimization of Large Scale Reservoirs
The Use of Capacitance-Resistive Models for Rapid Estimation of Waterflood Performance
Field Applications of Capacitance-Resistive Models in Waterfloods
Development of a Three Phase, Fully Implicit, Parallel Chemical Flood Simulator
A General Unstructured Grid, Parallel, Fully Implicit Thermal Simulator and Its Application for Large
Scale Thermal Models
Efficient General Formulation Approach For Modeling Complex Physics
Coupling Equation-of-State Compositional and Surfactant Models in a Fully Implicit Parallel
Reservoir Simulator Using the Equivalent-Alkane-Carbon-Number Concept
Data Assimilation of Coupled Fluid Flow and Geomechanics via Ensemble Kalman Filter
Embedding a Petroelastic Model in a Multipurpose Flow Simulator to Enhance the Value of 4D
Seismic
Recent Advances and Practical Applications of Integrated Production Modeling at Jack Asset in
Deepwater Gulf of Mexico
Transient Fluid and Heat Flow Modeling in Coupled Wellbore/Reservoir Systems
Maximizing the Potential of Decline Curve Analysis
An Innovative Workflow to Model Fractures in a Giant Carbonate Reservoir
Ensemble-Level Upscaling for Efficient Estimation of Fine-Scale Production Statistics
A New Finite-Volume Approach to Efficient Discretization on Challenging Grids
Developing a Fractional Flow Curve from Historic Production to Predict Performance of New
Horizontal Wells, Bekasap Field, Indonesia
High-Resolution Prediction of Enhanced Condensate Recovery Processes
What Is the Real Measure of Gas-Well Deliverability Potential?
Development of a Full-Field Parallel Model to Design Pressure Maintenance Project in the Wara
Reservoir, Greater Burgan Field, Kuwait
Multiscale Finite Volume Formulation for the Saturation Equations
Prediction of Temperature Propagation Along a Horizontal Well During Injection Period
Neural-Network Based Sensitivity Analysis for Injector-Producer Relationship Identification
Increasing Confidence in Production Forecasting Through Risk-Based Integrated Asset Modelling,
Captain Field Case Study
Model-Based Framework for Oil Production Forecasting and Optimization: A Case Study in
Integrated Asset Management
Capturing Complex Dynamic Behaviour in a Material Balance Model
A Straight Line p/z Plot is Possible in Waterdrive Gas Reservoirs
Optimization of Well Placement Under Time-Dependent Uncertainty
Field Applications of a Semianalytical Model of Multilateral Wells in Multilayer Reservoirs
Applications of Optimal Control Theory for Efficient Production Optimisation of Realistic Reservoirs
A Practical Data-Integration Approach to History Matching: Application to a Deepwater Reservoir
Efficient Field-Scale Simulation for Black Oil in a Naturally Fractured Reservoir via Discrete Fracture
Networks and Homogenized Media
Upscaling Discrete Fracture Characterizations to Dual-Porosity, Dual-Permeability Models for
Efficient Simulation of Flow With Strong Gravitational Effects
Development and Application of New Computational Procedures for Modeling Miscible Gas Injection
in Fractured Reservoirs
Modeling Transient Thermo-Poroelastic Effects on 3D Wellbore Stability
Utilization of Artificial Neural Networks in the Optimization of History Matching
A New Method for Continual Forecasting of Interwell Connectivity in Waterfloods Using an Extended
Kalman Filter
Quantifying Uncertainty for the PUNQ-S3 Problem in a Bayesian Setting With RML and EnKF
Diagnosis of Reservoir Behavior From Measured Pressure/Rate Data
Decision Making With Uncertainty While Developing Multiple Gas/Condensate Reservoirs: Well
Count and Pipeline Optimization
Well Performance With Operating Limits Under Reservoir and Completion Uncertainties
Improving Production Forecasts Through the Application of Design of Experiments and Probabilistic
Analysis: A Case Study From Chevron, Nigeria
Feedback Controllers for the Simulation of Field Processes
An Improved Approach for Ensemble-Based Production Optimization
Real-Time Reservoir Model Updating Using Ensemble Kalman Filter With Confirming Option
Some Practical Issues on Real-Time Reservoir Model Updating Using Ensemble Kalman Filter
Generalization of the Ensemble Kalman Filter Using Kernels for Nongaussian Random Fields
The Effect of Geologic Parameters and Uncertainties on Subsurface Flow: Deepwater Depositional
Systems
Reservoir Modeling for Mature Fields—Impact of Work Flow and Upscaling on Fluid-Flow
Response
The Pains and Gains of Experimental Design and Response Surface Applications in Reservoir
Simulation Studies
Adaptive Multiscale Finite-Volume Framework for Reservoir Simulation
Multi-D Upwinding for Multi Phase Transport in Porous Media
Important Modeling Parameters for Predicting Steamflood Performance
Tracing Streamlines on Unstructured Grids From Finite Volume Discretizations
Compressible Streamlines and Three-Phase History Matching
Experiences With Streamline-Based Three-phase History Matching
Upscaling and 3D Streamline Screening of Several Multimillion-Cell Earth Models for Flow
Simulation
Application of Global Optimization Methods for History Matching and Probabilistic
Forecasting—Case Studies
Static and Dynamic Uncertainty Management for Probabilistic Production Forecast in Chuchupa
Field, Colombia
Efficient 3D Implementation of Local-Global Upscaling for Reservoir Simulation
Dynamic Upscaling of Multiphase Flow in Porous Media via Adaptive Reconstruction of Fine Scale
Variables
Real-Time Performance Analysis of Water-Injection Wells
Simplified Wellbore-Flow Modeling in Gas/Condensate Systems
A Dynamic Wellbore Modeling for Sinusoidal Horizontal Well Performance With High Water Cut
A Robust Steady-State Model for Flowing-Fluid Temperature in Complex Wells
A Basic Approach to Wellbore Two-Phase Flow Modeling
Building a Geomechanical Model for Kotabatak Field with Applications to Sanding Onset and
Wellbore Stability Predictions
Building a Geomechanical Model for Kotabatak Field with Applications to Sanding Onset and
Wellbore Stability Predictions
Prediction of Temperature Changes Caused by Water or Gas Entry Into a Horizontal Well
Steam Flooding Field Fault Reactivation Maximum Reservoir Pressure Prediction Using
Deterministic and Probabilistic Approaches
Conditional Statistical Moment Equations for Dynamic Data Integration in Heterogeneous Reservoirs
Models and Methods for Understanding of Early Acid Breakthrough Observed in Acid Core-floods of
Vuggy Carbonates
A New Model of Trapping and Relative Permeability Hysteresis for All Wettability Characteristics
Modeling of Experiments on Water Vaporization for Gas Injection Using Traveling Waves
An Integrated Geological and Engineering Assessment of Fracture Flow Potential in a Middle-East
Carbonate Reservoir
Bridging the Gap Between Real-Time Optimization and Information-Based Technologies
Deepwater Gulf of Mexico Development Challenges Overview
Flow Assurance Challenges in Deepwater Gas Developments
New Findings in Fracture Cleanup Change Common Industry Perceptions
Advances in Horizontal Openhole Gravel Packing
A Comprehensive Comparative Study on Analytical PI/IPR Correlations
The Latest in Ways To Improve Asset Value Through Better Water Management
Integrating 4D Seismic Data with Production Related Effects at Enfield, North West Shelf, Australia
Placement of Permanent Downhole-Pressure Sensors in Reservoir Surveillance
Field Case Histories Demonstrating Critical Role of PLT Flow Model Selection for Improved Water
Shut-off Results in Offshore Thailand
Real-Time Estimation of Total Flow Rate and Flow Profiling in DTS-Instrumented Wells
Appropriate Assessment of Gas-Liquid Slippage – A Critical Step from a Good Production Logging
Survey to a Successful Workover for Gas Wells
Field Case Histories Demonstrating the Critical Roles Played by Multiphase Flow Models in
Appropriate Production Log Interpretation
A New Rate-Allocation-Optimization Framework
Analyzing Simultaneous Rate and Pressure Data From Permanent Downhole Gauges
Fiber-Optic Distributed-Temperature-Sensing Technology Used for Reservoir Monitoring in an
Indonesia Steamflood
Time Lapse Neutron Logging Improves Formation Evaluation and Reduces Rig Time in the Gulf of
Thailand
Vertical Sweep Evaluation in the Lost Hills Diatomite Waterflood Using Carbon/Oxygen Logs
Waterflooding Surveillance and Monitoring: Putting Principles Into Practice
Automated, By Exception" Well Surveillance: A Key to Maximizing Oil Production"
Sorption-Induced Permeability Change of Coal During Gas-Injection Processes
A Parametric Study on the Benefits of Drilling Horizontal and Multilateral Wells in Coalbed Methane
Reservoirs
A Simple Operational Approach To Ascertain the Viability of Your Offshore Gas Lift Project Before
Fully Committing: The Meji Jacket X and Y Pilot Case
Exploring Reservoir Engineering Aspects of Completion in Gas/Condensate Reservoirs: West
African Examples
Application of a Maximum Reservoir Contact (MRC) Well in a Thin, Carbonate Reservoir in Kuwait
Effects of Formation Damage and High-Velocity Flow on the Productivity of Slotted-Liner Completed
Horizontal Wells
Weighted Frac Fluids for Lower-Surface Treating Pressures
Designing Hydraulic Fractures in Russian Oil and Gas Fields to Accommodate Non-Darcy and
Multiphase Flow
Water Control and Fracturing: A Reality
New Results Improve Fracture Cleanup Characterization and Damage Mitigation
Hydraulic Fracture Diagnostics In The Williams Fork Formation, Piceance Basin, Colorado Using
Surface Microseismic Monitoring Technology
Quantifying Non-Darcy Effects on the Productivity of a Cased-Hole Frac Pack (CHFP) Well
The Resiliency of�Frac-Packed Subsea Injection Wells
Deliverability of Gas-Condensate Reservoirs—Field Experiences and Prediction Techniques
Effect of Wettability on High-Velocity Coefficient in Two-Phase Gas/Liquid Flow
Production and Injection Profiling Through Permanent-Downhole-Pressure-Gauge Recording During
a Coiled-Tubing-Conveyed Workover Operation
Flow Profiling by Distributed Temperature Sensor (DTS) System—Expectation and Reality
Maximizing Production Capacity Using Intelligent-Well Systems in a Deepwater, West-Africa Field
A Combined Well Completion and Flow Dynamic Modeling for a Dual-Lateral Well Load-up
Investigation
Automatic Concurrent Water Collection (CWC) System for Unloading Gas Wells
A New Method of Plunger Lift Dynamic Analysis and Optimal Design for Gas Well Deliquification
The Use of a Fully Coupled Geomechanics-Reservoir Simulator To Evaluate the Feasibility of a
Cavity Completion
New Solution To Improve Perforation Penetration and Breakdown: San Jorge Field, Argentina Case
Histories
A Novel Technology for Through Tubing Perforation in Highly Deviated Wells Where Electric Line Is
Limited
Deepwater Extended-Reach Sand-Control Completions and Interventions
Sanding Study for Deepwater Indonesia Development Wells: A Case History of Prediction and
Production
High-Angle Well Deliverability Modeling for Openhole Gravel-Pack Completion Under Ultrahigh Gas
Rate
Critical Conditions for Effective Sand-Sized Solids Transport in Horizontal and High-Angle Wells
A Novel Technique for Determining Screen Failure in Offshore Wells: A GOM Case History
Screenless Completions as a Viable Through-Tubing Sand Control Completion
Evaluation of Sand-Control Completions in the Duri Steamflood, Sumatra, Indonesia
Diversion and Cleanup Studies of Viscoelastic Surfactant-Based Self-Diverting Acid
Use of Novel Acid System Improves Zonal Coverage of Stimulation Treatments in Tengiz Field
A New Efficiency Criterion for Acid Fracturing in Carbonate Reservoirs
Chemical Stimulation of Gas/Condensate Reservoirs
New Viscoelastic Surfactant Fracturing Fluids Now Compatible With CO2 Drastically Improve Gas
Production in Rockies
Wettability Alteration in Gas-Condensate Reservoirs to Mitigate Well Deliverability Loss by Water
Blocking
Integrating Pressure Transient Test Data With Seismic Attribute Analysis to Characterize an
Offshore Fluvial Reservoir
Challenges Encountered During a Comprehensive Test Analysis for a Horizontal Well in a Thin,
Carbonate Reservoir of the Greater Burgan Field, Kuwait
Use of Transient Testing Data To Calculate Absolute Permeability and Average Fluid Saturations
Deepwater Exploration Well Pre-Drill DST Sanding Potential Prediction Using Probabilistic and
Deterministic Approaches
Author Abstract
Abstract As part of the long tradition of
Andrew Shere, SPE, and Yvonne Roberts, SPE, Weatherford/EPS, and Synnoeve Bakkevig, SPE, ConocoPhillips innovative
Abstract Through ConocoPhillips
Wen Shi, SPE, Jeff Corwith, SPE, Andre Bouchard, Russ Bone, SPE, and Eric Reinbold, SPE, many phases of expansion the
Abstract The ConocoPhillips Alpine facility on the
Y. Tang, SPE, Chevron Energy Technology Co., and T. Danielson, SPE, ConocoPhillips Upstream Technology Co.
Abstract Offshore gas gathering networks require l
M.J. Watson, N.J. Hawkes, and P.F. Pickering, FEESA Limited, and L.D. Brown, ConocoPhillips Incorporated
Abstract As SPE, and Probjot Singh, SPE, dollar
Chiedozie Ekweribe, SPE, and Faruk Civan, SPE, University of Oklahoma, Hyun Su Lee,the oil industry invests billions ofConoc
Abstract This Switch Consulting; behavior of hea
M.D. Fetkovich, SPE, and G.E. Petrosky Jr., SPE, ConocoPhillips; C.B. Hughesman, SPE, paper examines theand�R.P. Saw
Abstract There are now a variety of ways to achiev
Steven Fipke, Halliburton, Sperry Drilling Services; and Adriano Celli, Petrozuata
Abstract ConocoPhillips China Inc. (COPC) opera
Zhizhuang Jiang, SPE, ConocoPhillips China Inc., and Bassam Zreik, SPE, Schlumberger
Abstract Many examples of reaction-diffusion proc
Pradeep Ananth Govind and Sanjay Srinivasan, SPE, The University of Texas at Austin
Abstract In recent Company, Sanjay Srinivasan, S
Pradeep Ananth Govind, SPE, ConocoPhillips Canada Ltd., Swapan Das, SPE, ConocoPhillipsyears several Steam Assisted G
Swapan Das, ConocoPhillips Abstract As the demand for oil grows the petroleu
Abstract ConocoPhillips Nieuwland, and Juanita C
Kunto Wibisono, Robert C. Burton, and Richard M. Hodge, ConocoPhillips, and Rio Wijaya, BastiaanIndonesia Inc. Ltd. is prod
Liaqat Ali, SPE, Sandip Bordoloi, and Serene H. Wardinsky, ConocoPhillips Abstract Evaluation of gas potential in low permeab
Abstract Secondary fractures and faults associate
Pijush Paul, SPE, and Mark Zoback, SPE, Stanford University, and Peter Hennings, ConocoPhillips
Beste, G. Hu, M. Wu, J. Pitcher, companies Altho
M. Bittar, SPE, Halliburton Energy Services; J. Klein, ConocoPhillips; and R. Abstract Drilling services and oil C. Golla, G.have
Abstract Development of formation evaluation tech
Trond Gravem, Alf Berle, Sven S. Gundersen, INTEQ, and Jarle Pedersen, Kjell Oddvar Rorvik, and Atle Hansen, ConocoPhill
Inteq, and Jenson describes the experience and
Ulrich Hahne, Jos Pragt, Martin Venier, and Matthias Meister, Baker HughesAbstract This paperTan and Dai Chunsen, Conoco
L. Zhou, SPE, Baker Hughes; J. Mardambek, SPE, Rice University Abstract Modern formation pressure testing while d
Abstract Bul Pellerin and Ga�l Lecante, Beicip-F
Nicolas Desgoutte, Beicip-Franlab; Abdulmalik Al Abdulmalik, Qatar Petroleum; Matthieu Hanine field is located offshore Qatar
Abstract The predicted flow performance of Steam
J.A. McLennan and C.V. Deutsch, U. of Alberta; D. Garner and T.J. Wheeler, ConocoPhillips Canada Ltd.; and J.-F. Richy and
M.D. Fetkovich, M.G. Gerard, L.Y. Chin, and D. Shuxing, ConocoPhillips Abstract The overall structure of the PL19-3 field
Abstract A revised Field Development Cuauro, Sc
E. Kasap, Schlumberger; G.J. Sanza, and M.I. Ali, Petronas Carigali; T. Friedel, A. Waheed, A.Y. Sukmana, and A.Plan (FDP)
Abstract Ayda Abdulwahab, BAPCO
Ali E. AL-Muftah, BAPCO; William Vargas, PETE Schlumberger, Huston; CRK Murty,For a matured oil field like Bahrain Field w
R. Schulz and L. Harms, ConocoPhillips Abstract Production results from capital or operati
Abstract The China National Offshore Oil Corporat
Zhizhuang Jiang and Zhang Tao, ConocoPhillips, China Inc., and Khong Chee Kin and Robert North, Schlumberger China Inc.
Abstract A reservoir Bhd.; andE. Kasap*, S. Yuso
T. Friedel, SPE, Schlumberger; G.J. Sanza, M.I. Ali, and A. Embong, SPE, Petronas Carigali Sdn simulation model calibrated w
Abstract The initial steam chamber
Anh N. Duong, SPE, ConocoPhillips Canada, Timothy A. Tomberlin, ConocoPhillips, Martin Cyrot, Total E&P that developed
Abstract The solution of the linear system of equa
Tareq M. Al-Shaalan, SPE, Saudi Arabian Oil Company; Hector Klie, SPE, Center for Subsurface Modeling, The University of T
Abstract In recent years there has been a resurge
Hector Klie, ConocoPhillips; Jorge Monteagudo, Reservoir Engr. Research Inst. and Hussein Hoteit and Adolfo Rodriguez, Con
Abstract Traditional reservoir simulators Company
Feng Pan, SPE, and Kamy Sepehrnoori, SPE, The University of Texas at Austin, and L.Y. Chin, SPE, ConocoPhillips cannot ca
and L.Y. Chin, SPE, ConocoPhillips Company
Feng Pan, SPE, and Kamy Sepehrnoori, SPE, University of Texas at Austin,Abstract This paper presents a coupled geomecha
Summary A ConocoPhillips Company; and C.J.N
M.S. Nadar, SPE, Edinburgh Petroleum Services; T.S. Schneider and K.L. Jackson, SPE,total-system production-optimization m
Summary A technique for the
M.J. Mlacnik, SPE, and L.J. Durlofsky, SPE, Stanford U., and Z.E. Heinemann, SPE, Mining U. of Leoben sequential generatio
Ochi I. Achinivu, Zhuoyi Li, D. Zhu, and A.D. Hill, Texas A&M University Abstract Accurate and reliable downhole data acq
T.N. Mahmoud, SPE, and D.N. Rao, SPE, Louisiana State University Abstract The gas-assisted gravity drainage (GAGD
T.N. Mahmoud, SPE, and D.N. Rao, SPE, Louisiana State University Abstract The Gas Assisted Gravity Drainage (GAG
Abstract Bergen, and J. Stevens and J. Howard, C
M.A. Fern�, G. Ersland, �. Haugen, E. Johannesen, and A. Graue, University of The fracture/matrix transfer and fluid flow
Abstract Consulting Services; and T. the SPE,
J.A. Walker, SPE, ConocoPhillips Alaska Inc.; D.O. Ogbe, SPE, Schlumberger Data &Alaska’s North Slope andZhu, United
Hongjie Xiong, Burlington Resources, and Stephen A. Holditch, Texas A&M U. Abstract There are substantial volumes of unconve
Ochi I. Achnivu, D. Zhu, Texas A&M University, and Kenji Furui, ConocoPhillipsAbstract Accurate and reliable downhole data acqu
John L. Stalder, ConocoPhillips Canada Limited Abstract Two characteristics of XSAGD that accele
K. Morad, SPE, Fekete Associates Inc., and C.R. Clarkson, SPE, ConocoPhillips Abstract Material balance analysis�is a fundam
Abstract It is well known that absolute permeability
C.R. Clarkson, ConocoPhillips, Z. Pan, CSIRO Petroleum Resources, I. Palmer, Higgs-Palmer Technologies, S. Harpalani, Sou
R.R. Gierhart, SPE, BP America; and J.P. data an
C.R. Clarkson, SPE, ConocoPhillips; C.L. Jordan, SPE, BOE Solutions Inc.; Summary Recent advances in production Seidle, S
R.D. Roadifer, ConocoPhillips Alaska, Inc. and T.R. Moore, CDX Gas LLC Abstract Four distinct sequential phases comprise
C.R. Clarkson, SPE, ConocoPhillips Abstract The Horseshoe Canyon (HSC) CBM play
Abstract The Petroleum Consultants
R. R. Gierhart, SPE, BP; C.R. Clarkson, SPE, ConocoPhillips; and J.P. Seidle, SPE, MHASan Juan basin Fruitland coalbed me
Adam M. Lewis and Richard G. Hughes, Louisiana State University Abstract Unconventional shale gas reservoirs have
David D.Cramer, ConocoPhillips Abstract The term “unconventional reservoir ha
Summary The McMurray formation consists of he
Weishan Ren, SPE, ConocoPhillips Canada; Clayton V. Deutsch, SPE, University of Alberta; David Garner, SPE, Chevron Can
Abstract Formation powered jet pumps (FPJP)
J.W. Peirce, SPE, J.A. Burd, G.L. Schwartz, ConocoPhillips Alaska, Inc., and T.S. Pugh, SPE, Weatherford International we
T.C. Handfield, T. Nations, S.G. Noonan; ConocoPhillips Abstract Gas lift completions for SAGD1 producers
Abstract The Bayu-Undan gas recycling project is l
L. B. Ledlow, W. W. Gilbert, N. P. Omsberg, G. J. Mencer and D. P. Jamieson, ConocoPhillips
Abstract The SPE, field located on the North Slop
Tim S. Schneider, David O. Uldrich, and Richard Hodge, ConocoPhillips Co.; Bob Barree, AlpineBarree�& Assocs.; and Mich
Abstract The Joint Chalk Norway; Rene Frederikse
Bart Vos and Hans de Pater, Pinnacle Technologies; Chris Cook, Norsk Hydro; Tommy Skjerven, BP Research (JCR) initiative
Abstract Massive hydraulic fracturing China Ltd
Xing Zhenhui, Saint-Gobain (Guanghan) Proppant; Andrew Pfaff, Thomas Weller, David Wendt, EOG Resources has been suc
Summary The Colville River
Michael D. Erwin, SPE, ConocoPhillips Alaska, and David O. Ogbe,SPE, University of Alaska Fairbanks field represents the fi
Green, The design and subsequent results of a h
L. Casas and J.L. Miskimins, Colorado School of Mines, and A. Black and S.Abstract TerraTek
Varun Mishra, D. Zhu, and A.D. Hill, Texas A&M U., and K. Furui, ConocoPhillips Abstract In several places around the world notab
Abstract ConocoPhillips and Kenyon the Magnolia
Luke F. Eaton and W. Randall Reinhardt, ConocoPhillips Co.; J. Scott Bennett, Devon Energy Corp.; is developingBlake and Hu
Abstract ConocoPhillips is developing the Magnolia
George Colwart, Robert C. Burton, Luke F. Eaton, and Richard M. Hodge, ConocoPhillips Co., and Kenyon Blake, Schlumberg
J. Skufca and J. Li, BJ Services Company Reach sand With of large diameter d
Abstract Cleaning Wells fill outConcentric Coiled Tu
N. Morita, Waseda U., and G.-F. Fuh and B. Burton, ConocoPhillips � Abstract Sand flow models have been succe
Abstract Using two field
G.-F. Fuh, I. Ramshaw, K. Freedman, and N. Abdelmalek, ConocoPhillips, and N. Morita, Waseda U.case examples this pape
Summary Using now with Texas analytical calcul
K. Furui* , D. Zhu**, and A.D. Hill**, University of Texas at Austin * now with ConocoPhillips ** a combination ofA&M University
Abstract The SPE, an acid fracture treatment is t
G. Zaeff and C. Sievert, SPE, ConocoPhillips, and O. Bustos, SPE, A. Galt, SPE, D. Stief,goal ofL. Temple, SPE, and V. Rodrig
Abstract During at Austin; from gas Baran Jr., re
Vishal Bang, SPE, Gary A. Pope, SPE, and Mukul M. Sharma, SPE, The University of Texasproduction Jimmie R.condensate3M
Anh N. Duong, SPE, ConocoPhillips Canada Abstract The effectiveness of heat injection into a t
B. Todd Hoffman, SPE, drc consulting, and Wayne Narr, SPE, and Liyong
Li, SPE, Chevron ETC Abstract In naturally fractured reservoirs determin
Emmanuel Toumelin, SPE, and Carlos Torres-Verd�n, SPE, U. of
Texas at Austin, and Boqin Sun and Keh-Jim Dunn, Chevron Energy
Technology Co. Summary Two-dimensional (2D) NMR techniques
M.J. Sullivan, D.L. Belanger, M.T. Skalinski, S.D. Jenkins, and P. Dunn,
Chevron Abstract Estimation of effective permeability at the
Michael J. Sullivan, SPE, Chevron Distinguished Author Series articles are general d
T. Zhang, Stanford U., and S. Bombarde, S. Strebelle, and E. Oatney,
Chevron Corp. ETC Summary Training images are numerical represen
V. Bang, SPE, and V. Kumar, SPE, U. of Texas at Austin; P.S.
Ayyalasomayajula, SPE, Chevron; and G.A. Pope, SPE, and M.M. Sharma,
SPE, U. of Texas at Austin Abstract Predicting production from gas-condensa
Soraya S. Betancourt, Francois X. Dubost, and Oliver C. Mullins,
Schlumberger Oilfield Services; Myrt E. Cribbs and�Jefferson L. Creek,
Chevron Energy Technology Corporation; and Syriac G. Mathews,
Schlumberger Oilfield Services Abstract Compartmentalization is perhaps the sing
J.F. App, SPE, and J.E. Burger, SPE, Chevron Energy Technology
Company Summary Measurement of gas and condensate re
M. Ikeda, G.-Q. Tang, C.M. Ross, and A.R. Kovscek, Stanford University Abstract Spontaneous imbibition and coreflood ex
C.M. Ross, SPE, M. Ikeda, SPE, Schlumberger, G.-Q. Tang, SPE,
Chevron, and A.R. Kovscek, SPE, Stanford University Abstract Pore microstructure and mineral composi
W. Scott Meddaugh, SPE, Dennis Dull, Raymond A. Garber, and Stewart
Griest, Chevron Energy Technology Co., and David Barge, SPE, Saudia
Arabian Texaco Abstract The First Eocene reservoir at Wafra Field
Shah Kabir, Chevron Energy Technology Company Abstract Exploitation of gas/condensate reservoirs
W. Scott Meddaugh, SPE, Chevron Energy Technology Company; David
Barge, SPE, Saudi Arabian Chevron; and W.W.�(Bill) Todd, SPE, and
Stewart Griest, Chevron Energy Technology Company Abstract The Jurassic-age Humma Marrat carbona
P.E. Carreras, SPE, Chevron Energy Technology Co., and S.E. Turner,
SPE, and G.T. Wilkinson, SPE, Chevron North America Exploration and
Production Co Abstract Tahiti field in deepwater Gulf of Mexico i
P.E. Carreras, SPE, and S.G. Johnson, SPE, Chevron Energy Technology
Co.; and S.E. Turner, SPE, Chevron North America E&P Co., Chevron
Corp. Abstract Tahiti prospect in deepwater Gulf of Mex
C.S. Kabir, SPE, Chevron Energy Technology Company; M. Agamini, SPE,
Chevron Nigeria Limited; and R.A. Holguin, SPE, Chevron North America Summary Maximizing oil recovery in thin and ultra
B. Gűyagűler, SPE, Chevron, and K. Ghorayeb, SPE, Schlumberger Abstract Field management (FM) is the simulation
Obor Eruvbetine, Olufemi Odusote, Inegbenose Aitokhuehi, Moses Imogu,
and Oyie Ekeng, Chevron Nigeria Ltd. Abstract Asset development teams have the respo
Hamad Al-Ajmi, SPE, Issa Al-Jadi, SPE, Feras Al-Ruhaimani, SPE, Kuwait
Oil Company; Wahyu Budiarto, SPE, Chevron Abstract This paper presents the process of candid
N. Nijhawan and J.E. Myers, Chevron Corp. Abstract When water is scarce its value increase
Akshay Sahni, Chevron and Steven T. Kovacevich, Chevron Corp. Abstract As the hydrocarbon production in the Gul
You Hongqing, Wei Ping, Tian Xiang, Xu Xiang Dong, Lian JiHong, Thanh
Tran, Yoseph J. Partono : CACT, Jeffrey Kok, Liu Yang, Sarfraz Balka:
Schlumberger Abstract The Huizhou 6S and 3S oil fields in the Pe
M.A. Crotti, Inlab S.A.; Gustavo Fernandez, Chevron Argentina; and Martin
Terrado, Chevron Energy Technology Co. Abstract The El Trapial field is a 1.2 B bbl OOIP as
D.F. Frizzell, M.J. Sibley, B. Cotner, S.P. McCartney, G.R. Schmidt, SPE,
and R. Burkes, AICHE; J.C. Phelps, SEG, Chevron; and M. Tosdevin, and
J. Mazloom, SPE, Sasol Petroleum International Abstract A primary objective of any project evaluat
W. Scott Meddaugh, SPE, and Stewart Griest, Chevron Energy
Technology Company, Houston, TX, and David Barge, SPE, Saudi Arabian
Chevron, Houston, TX Abstract The Jurassic-age Humma Marrat carbona
A. Saeedi, SPE, Chevron Corp., and K.V. Camarda and J.T. Liang, SPE,
The U. of Kansas Abstract Using actual field cases a neural-networ
N. Liu, Chevron ETC, and Y. Jalali, SPE, Schlumberger Abstract We present a methodology of converting
Pallav Sarma and Wen H. Chen, Chevron ETC; and Louis J. Durlofsky and
Khalid Aziz, Stanford University Summary The general petroleum-production optim
Pallav Sarma and Wen H. Chen, Chevron Energy Technology Company Abstract A key reservoir management decision tak
I.C. Okoro and S.E. Okojie, Chevron Nigeria Ltd., and J.O. Umurhohwo,
SPE Abstract A critical component of waterflood manag
A.R. Hasan, U. of Minnesota-Duluth; and C.S. Kabir, Chevron Energy
Technology Co. Summary Annular flow is associated with producti
James F. Keating and Umut Ozdogan, Chevron North America E&P Co. Abstract This study is an attempt to justify the incre
Pallav Sarma, Chevron ETC; Louis J. Durlofsky and Khalid Aziz, Stanford
U.; and Wen H. Chen, Chevron ETC Abstract Efficient history matching of geologically c
Guohua Gao, SPE, Chevron Corp.; Gaoming Li, SPE, U. of Tulsa; and
Albert C. Reynolds, SPE, U. of Tulsa Summary For large- scale history- matching prob
P. Likanapaisal, Stanford University; L. Li, Chevron Energy Technology
Company; and H.A. Tchelepi, Stanford University Abstract A probabilistic framework for dynamic da
Daniel Weber, SPE, Thomas F. Edgar, Larry W. Lake, SPE, Leon Lasdon,
Sami Kawas, SPE, Morteza Sayarpour, SPE, The University of Texas at
Austin Abstract Oil production strategies traditionally attem
M. Sayarpour, SPE, University of Texas at Austin; E. Zuluaga, SPE, and
C.S. Kabir, SPE, Chevron ETC; and Larry W. Lake, SPE, University of
Texas at Austin Abstract The capacitance-resistive model (CRM) o
M. Sayarpour, SPE, U. of Texas-Austin; C. S. Kabir, SPE, Chevron ETC; L.
W. Lake, SPE, U. of Texas-Austin Abstract Application of fast simple and yet powerfu
N. Fathi Najafabadi, SPE, University of Texas at Austin; C. Han, SPE,
Chevron; and M. Delshad and K. Sepehrnoori, SPE, University of Texas at
Austin Abstract Field-scale applications of chemical flood
Xundan Shi and Yih-Bor Chang, Chevron; Mathieu Muller and Eguono Obi,
Total USA Inc.; and Kok-Thye Lim, Chevron Abstract We describe the construction of a genera
H. Cao and P.I. Crumpton, Schlumberger, and M.L. Schrader, Chevron
Energy Technology Company Abstract This paper describes a general formulatio
C. Han, SPE, M. Delshad, SPE, G.A. Pope, SPE, and K. Sepehrnoori,
SPE, Center for Petroleum and Geosystems Engineering, University of
Texas at Austin Summary Equation-of-state (EOS) compositional
Carbon
Haibin Chang, Peking University; Yan Chen, SPE, Chevron; and Dongxiao
Zhang, SPE, U. of Southern California Abstract In reservoir history matching or data assi
John R. Fanchi, Chevron ETC Abstract Time-lapse (4D) seismic can be effective
Umut Ozdogan, Chevron Energy Technology Co.; James F. Keating,
Chevron North America Exploration and Production Co.; Mark Knobles,
Chevron North America Exploration and Production Co.; Adwait Chawathe,
Chevron North America Exploration and Production Co.; and Doruk Seren,
Chevron Energy Technology Co. Abstract This paper presents an integrated produc
B. Izgec, SPE, Chevron ETC/Texas A&M University; C.S. Kabir, SPE,
Chevron ETC; D. Zhu, SPE, Texas A&M University; and A.R. Hasan, SPE,
University of Minnesota-Duluth Summary This paper presents a transient wellbore
I. Aitokhuehi, SPE, Chevron Nigeria Limited Abstract The data most collected within the oil ind
Mun-Hong Hui, Bradley Mallison, and Kok-Thye Lim, SPE, Chevron Energy
Technology Company Abstract Most of the oil reserves in the giant carbo
Yuguang Chen, SPE, Chevron Energy Technology Company, and Louis J.
Durlofsky, SPE, Stanford University Summary Upscaling is often needed in reservoir s
I. Aavatsmark, G.T. Eigestad, and B.-O. Heimsund, CIPR; B.T. Mallison,
Chevron; J.M. Nordbotten, U. of Bergen; and E. �ian, CIPR Abstract MPFA methods were introduced to solve
J. Sitorus, SPE, A. Sofyan, SPE, and M.Y. Abdulfatah, SPE, Chevron
Pacific Indonesia Abstract A fractional flow curve (fw versus Sw) is u
K. Jessen, University of Southern California, M.G. Gerritsen, Stanford
University, and B.T. Mallison, Chevron Energy Technology Company Summary This paper investigates the accuracy of
C.S. Kabir, SPE, Chevron Energy Technology Co. Summary This paper probes the usefulness of est
Eddie Ma, KOC; Lee Williams and Anil Ambastha, Chevron; and Meqdad
Al-Naqi, KOC Abstract The Wara reservoir is one of the four ma
H. Zhou, SPE, Stanford University; S.H. Lee, SPE, Chevron Energy
Technology Company; and H.A. Tchelepi, SPE, Stanford University Abstract Recent advances in multiscale methods
Guohua Gao, SPE, Chevron Corp.; and Younes Jalali, SPE, Schlumberger Summary This paper presents a mathematical mo
U. Demiryurek, F. Banaei-Kashani, and C. Shahabi, University of Southern
California, and Frank Wilkinson, Chevron Abstract Determining injector-producer relationshi
L.M. Wickens, SPE, RPS Energy, and G. De Jonge, SPE, Chevron
Upstream Europe Abstract To assist in the probabilistic forecasting
C. Zhang, A. Orangi, and A. Bakshi, U. of Southern California; W. Da Sie,
Chevron Corp.; and V.K. Prasanna, U. of Southern California Abstract This paper describes the design and imp
Jalal Mazloom and Mike Tosdevin, SPE, Sasol Petroleum International,
and Dominique Frizzell, Bill Foley, and Mike Sibley, SPE, Chevron Abstract Sometimes a simple and quick material b
M. Elahmady, Chevron, and R.A. Wattenbarger, Texas A&M U. Abstract Field data and simulated models have rev
Umut Ozdogan, SPE, Chevron Energy Technology Co., and Roland N.
Horne, SPE, Stanford U. Summary Well-placement decisions made during
Yan Pan, Medhat M. Kamal and Jitendra Kikani, Chevron Energy
Technology Company Abstract Advanced drilling technology has been wi
P. Sarma and W.H. Chen, Chevron Energy Technology Company, CA,
USA Abstract In practical reservoir management altho
B. Todd Hoffman, SPE, Montana Tech; Jef K. Caers, SPE, Stanford U.;
Xian-Huan Wen, SPE, Chevron Corp.; and Sebastien Strebelle, SPE,
Chevron Summary This paper presents an innovative meth
Liyong Li and Seong H. Lee, Chevron Energy Technology Co. Abstract This paper describes a hybrid finite volum
B. Gong, SPE, M. Karimi-Fard, SPE, and L.J. Durlofsky, SPE, Stanford
University Summary The geological complexity of fractured r
Mun-Hong Hui,�SPE, and Bin Gong, SPE, Chevron Energy Technology
Company, and Mohammad Karimi-Fard, SPE, and Louis J. Durlofsky,
SPE, Stanford University Abstract Detailed geological characterizations of na
H.S. Farahani, M. Yu, S. Miska, and N. Takach, SPE, U. of Tulsa, and G.
Chen, SPE, Chevron Energy Technology Co. Abstract The temperature difference between the
Asha Ramgulam, Turgay Ertekin, and Peter B. Flemings, Pennsylvania
State U. Abstract Artificial neural networks are becoming in
Daoyuan Zhai, Jerry M. Mendel, Feilong Liu, University of Southern
California Abstract This paper is based on a relatively simple
Guohua Gao, SPE, Chevron Corp.; Mohammad Zafari, SPE,
Schlumberger; and Albert C. Reynolds, SPE, U. of Tulsa Summary The well known PUNQ-S3 reservoir mo
C.S. Kabir, SPE, Chevron ETC, and B. Izgec, SPE, Texas A&M U. Abstract This paper presents a simple diagnostic
C.S. Kabir, SPE, Chevron ETC; S.B. Gorell, SPE, Landmark Graphics;
M.E. Portillo, SPE, University of Texas/Chevron; and A.S. Cullick, SPE,
Landmark Graphics Summary Well-developed methodology exists for
C.D. Wehunt, SPE, Chevron Energy Technology Co. Summary����������ï¿
Olaoluwa Adepoju, SPE, Olufemi Odusote, SPE, and Djuro Novakovic,
SPE, Chevron Nigeria Limited Abstract A reliable production forecast is a critical
B. G�yag�ler, Chevron, and A.T. Papadopoulos, and J.A. Philpot,
Schlumberger Abstract Control systems with feedback controller
Masroor M. Chaudhri, SPE, Chevron Energy Technology Company,
Hemant A. Phale, SPE, University of Oklahoma, Ning Liu, SPE, Chevron
Energy Technology Company, Dean S. Oliver, SPE, University of
Oklahoma Abstract For oil reservoirs under water and/or gas
Xian-Huan Wen, SPE, and Wen H. Chen, SPE, Chevron Corp. Summary The ensemble Kalman Filter technique
Xian-Huan Wen and Wen H. Chen, Chevron Energy Technology Company Summary The concept of closed-loop" reservoir m
P. Sarma and W.H. Chen, Chevron Energy Technology Company, CA,
USA Abstract Efficient history matching (model updatin
William J. Milliken, Marjorie Levy, and Sebastien Strebelle, Chevron
Energy Technology Company; and Ye Zhang University of Michigan Abstract The application of reservoir simulation as
W.S. Meddaugh, SPE, Chevron Energy Technology Co. Abstract Scoping studies using data from three m
C. Amudo, SPE, Chevron Australia Pty Ltd; T. Graf, SPE, and R.
Dandekar, SPE, Schlumberger; and J.M. Randle, SPE, Chevron Vietnam Abstract With the dearth of easy oil in the industry
H.A. Tchelepi, SPE, Stanford U.; P. Jenny, ETH Z�rich; S.H. Lee, SPE,
and C. Wolfsteiner, SPE, Chevron ETC Summary A multiscale finite-volume (MSFV) fram
J. Kozdon, SPE, Stanford University; B. Mallison, SPE, Chevron ETC; M.
Gerritsen, SPE, Stanford University; and W. Chen, SPE, Chevron ETC Abstract Multidimensional transport for reservoir s
Cengiz Satik, Mridul Kumar, Sam DeFrancisco, Viet Hoang, and Mike
Basham, Chevron Energy Technology Company Summary A comprehensive numerical modeling s
S.F. Matringe, SPE, Stanford, R. Juanes, SPE, Massachusetts Institute of
Technology, and H.A. Tchelepi, SPE, Stanford Summary The accuracy of streamline reservoir sim
H. Cheng, SPE, D. Oyerinde, SPE, and A. Datta-Gupta, SPE, Texas A&M
U., and W. Milliken, SPE, Chevron Energy Technology Co. Abstract Reconciling high-resolution geologic mo
Adedayo Oyerinde, SPE, Akhil Datta-Gupta, SPE, Texas A&M University,
and William Milliken, SPE, Chevron Energy Technology Company Abstract Streamline-based assisted and automatic
Ajay K. Samantray, Shell; Qasem M. Dashti, SPE, and Eddie D.C. Ma,
Kuwait Oil Co.; and Pradeep S. Kumar, SPE, Chevron Intl. E&P Summary Nine multimillion-cell geostatistical earth
M.K. Choudhary, SPE, and S. Yoon, SPE, Chevron Energy Technology
Co., and B.E. Ludvigsen, Scandpower PT Abstract Subsurface uncertainties have a major in
N. Rivera, SPE, N.S. Meza, J.S. Kim, SPE, P.A. Clark, SPE, R. Garber,
and A. Fajardo, Chevron, and V. Pe�a, Ecopetrol Abstract Structural stratigraphic and petrophysic
Xian-Huan Wen, SPE, Chevron Energy Technology Co.; and Yuguang
Chen, SPE, and Louis J. Durlofsky, SPE, Stanford U.� Summary Upscaling is often applied to coarsen de
S.H. Lee, SPE, Chevron Energy Technology Company, and X. Wang,
SPE, H. Zhou, SPE, and H.A. Tchelepi, SPE, Stanford University Abstract We propose an upscaling method that is
B. Izgec, SPE, Chevron ETC/Texas A&M University and C.S. Kabir, SPE,
Chevron ETC Abstract This work presents a complete reformula
C.S. Kabir, SPE, Chevron Energy Technology Co., and A.R. Hasan, SPE,
U. of Minnesota-Duluth Summary Predicting long-term reservoir performa
Yula Tang and Martin Wolff, Chevron Energy Technology Company, and
Patrick Condon and Katharine Ogden, Chevron International E&P
Company Abstract The Banzala Field (Block 0 Angola) has p
A.R. Hasan, SPE, University of Minnesota–Duluth; C.S. Kabir, SPE,
Chevron ETC; and X. Wang, SPE, Baker Hughes Abstract This paper presents an analytic model for
A.R. Hasan, SPE, University of Minnesota–Duluth; C.S. Kabir, SPE,
Chevron ETC; and M. Sayarpour, SPE, University of Texas at Austin Abstract This study presents a simplified two-phas
X. Yi, H.E. Goodman, R.S. Williams, W.K. Hilarides, Chevron Corp. Abstract Kotabatak field Sumatra Indonesia is a h
K. Yoshioka, Chevron ETC; D. Zhu, and A.D. Hill, Texas A&M University;
P. Dawkrajai, Thailand Defense Energy Department; and L. W. Lake,
University of Texas at Austin Summary With the recent development of temper
X. Yi, Chevron Corporation Abstract Fault reactivation induced by excessive re
Liyong Li, SPE, Chevron, and Hamdi A. Tchelepi, SPE, Stanford U. Summary An inversion method for the integration
O.Izgec, D.Zhu, A.D.Hill, SPE, Texas A&M University Abstract Previously we have studied the acidizatio
Elizabeth J. Spiteri, SPE, Chevron Energy Technology Company; Ruben
Juanes, SPE, Massachusetts Institute of Technology; Martin J. Blunt, SPE,
Imperial College London; and Franklin M. Orr, Jr., SPE, Stanford University Summary The complex physics of multiphase flow
Elizabeth Zuluaga* and Larry W. Lake, University of Texas at Austin, SPE *
Now with Chevron Energy Technology Company Summary Dry gas injected into wells will vaporize
Whitaker, A.E., Kabir, C.S., and Narr, W., Chevron ETC Abstract The extent to which fractures affect fluid p
Michael Brul�, Technomation; Yanni Charalambous, Oxy; Mark L.
Crawford, ExxonMobil Global Services Company; and Charles Crawley,
Chevron Abstract For the past several years the problem o
Frank Close, Bob McCavitt, and Brian Smith, Chevron North America E&P
Company Abstract Chevron's role as a major player in the gl
Richard Kopps, Rama Venkatesan, Jeff Creek, and Alberto Montesi,
Chevron Energy Technology Company Abstract The Flow Assurance strategy is crucial in
J.A. Ayoub, SPE, and R.D. Hutchins, SPE, Schlumberger; F. van der Bas,
SPE, Shell; S. Cobianco, SPE, and C.N. Emiliani, SPE, Eni; M. Glover,
SPE, BP America Inc.; M. K�hler, SPE, Gaz de France; S. Marino,
SPE, Schlumberger; G. Nitters, SPE, Shell; D. Norman, SPE, Chevron
Corp.; and G. Turk, SPE, BP America Inc. Abstract This paper summarizes part of the resul
Syed Ali, SPE, Chevron Energy Technology Co., Tommy Grigsby, SPE,
and Sanjay Vitthal,* SPE, Halliburton Energy Services Inc. *Currently with
Shell Corp. Summary Technological advancement in horizont
Suk Kyoon Choi, SPE, The University of Texas at Austin, and Liang-Biao
Ouyang, SPE, and Wann-Sheng (Bill) Huang, SPE, Chevron Energy
Technology Company Abstract Inflow performance is one of the significan
Steven K. Cheung, Chevron Energy Technology Co. Abstract Many wells and reservoirs are premature
Amna Ali, SPE, Ian Taggart, SPE, Benjamin Mee, Megan Smith and Andre
Gerhardt, Woodside Energy Ltd. and Laurent Bourdon, Shell Development
(Australia) Abstract The Enfield field has a 160 m oil column
B. Izgec, SPE, Chevron ETC/Texas A&M U.; M.E. Cribbs, SPE, Chevron
North America & Exploration; S.V. Pace, SPE, Chevron ETC; D. Zhu, SPE,
Texas A&M U.; and C.S. Kabir, SPE, Chevron ETC Summary This paper probes the gauge-placemen
Liang-Biao Ouyang, SPE, Chevron Energy Technology Company Abstract Production logging (PLT) has been routin
C.S. Kabir, SPE, and B. Izgec, SPE, Chevron ETC; A.R. Hasan, SPE, U.
Minnesota-Duluth; and X. Wang, SPE, and J. Lee, SPE, Baker Hughes Abstract Distributed temperature sending or DTS
Liang-Biao Ouyang, SPE, Chevron Energy Technology Company; Polpipat
Suthichoti, SPE, Chevron Thailand Exploration & Production Company Abstract Production logging (PLT) has been routin
Liang-Biao Ouyang, SPE, Chevron Energy Technology Company; Polpipat
Suthichoti, SPE, Chevron Thailand Exploration &Production Company Abstract Production logging (PLT) has been routin
B. G�yag�ler and T. Byer, Chevron Summary Determination of the operating condition
Himansu Rai, SPE, and Roland N. Horne, SPE, Stanford University Abstract Permanent downhole gauge data provide
D.K. Nath, Halliburton Energy Services; Riki Sugianto, PT Chevron Pacific
Indonesia; and Doug Finley, Halliburton Energy Services Summary The world’s largest steamflood ope
Karen Whittlesey, SPE, and James Logan, SPE, Chevron, and Huw
Rossiter, SPE, Halliburton Abstract In Chevron's Gulf of Thailand (GOT) ope
A. Badruzzaman, SPE, Chevron Energy Technology Company; T.
Badruzzaman, Pacific Consultants & Engineers; and M.F. Morea and D.J.
Julander, Chevron North America E&P Company Abstract We discuss our experience to date with th
R. Martin Terrado, Suryo Yudono, and Ganesh Thakur, Chevron Energy
Technology Company Summary This paper illustrates how practical app
Peter Schipperijn, SPE, Chevron Energy Technology Company; Raymond
Thavarajah, SPE, and Ana Simonato, SPE, Chevron North America
Exploration and Production Company; and Mohsen Mehdizadeh, SPE,
Science Application International Corporation (SAIC) Abstract The increased need to maximize product
W. Lin, SPE, G.-Q. Tang, SPE, and A.R. Kovscek, SPE, Stanford
University Abstract Our study has two features. First laborato
Nikola Maricic, SPE, Chevron Corporation; Shahab D. Mohaghegh, SPE,
and Emre Artun, SPE, West Virginia University Summary Recent years have witnessed a renewe
Francis Nwaochei, SPE; Adebayo Olufemi, SPE; Vincent Eme, SPE; and
John Ibrahim, SPE, Chevron Nigeria Limited; Eseoghene Nakpodia, SPE,
and Wole Areo, SPE, Flostar Oil & Gas Nigeria Limited Abstract Application of improved Oil Recovery in m
C.S. Kabir, SPE, Chevron Energy Technology Co.; M.-M. Chang, SPE,
Chevron Intl. E&P; and O. Taghizadeh, SPE, U. of Texas at Austin Summary This paper explores multiple completion
M. Kabir, KOC; S. Ingham, Schlumberger; D. Sibley, K. Osman, A.K.
Ambastha, and M. Anderson, Chevron; and B. Rahman, KOC Abstract Mauddud reservoir in the Greater Burgan
Yula Tang, Chevron Energy Technology Co.; Turhan Yildiz and Erdal
Ozkan, Colorado School of Mines; and Mohan Kelkar, U. of Tulsa Abstract Slotted-liner is a relatively simple and cos
Lloyd Simms III and Brad Clarkson, Halliburton, and Gilbert Navaira,
Chevron Abstract With Gulf of Mexico (GOM) hydrocarbon d
Andrey V. Dedurin, TNK-BP; Vadim A. Majar, Gazpromneft; Andrey A.
Voronkov, SPE, SIAM; Alexey G. Zagurenko, SPE, Rosneft; and Alexander
Y. Zakharov, SPE, Terry Palisch, SPE, and M.C. Vincent, SPE, Carbo
Ceramics Summary Non-Darcy and multiphase flow effects
M. Mahajan, SPE, and N. Rauf, SPE, BJ Services; T. Gilmore, SPE,
Chevron; and A. Maylana, SPE, Pertamina Abstract Water production in mature fields is a com
J.A. Ayoub, SPE, and R.D. Hutchins, SPE, Schlumberger; F. Van der Bas,
SPE, Shell; S. Cobianco, SPE, and C.N. Emiliani, SPE, Eni; M. Glover,
SPE, BP America Inc.; S. Marino, SPE, Schlumberger; G. Nitters, SPE,
Shell; D. Norman, SPE, Chevron, and G. Turk, SPE, BP America Inc. Abstract It is well documented in the literature that
David Abbott, Chris Neale, and James Lakings, Microseismic Inc., and
Lynn Wilson, Jay C. Close, and Evan Richardson, Chevron Abstract A surface microseismic array was utilized
Liang-Biao Ouyang, SPE, Chevron Energy Technology Company Abstract Well completion plays a critical role in the
R.A. McCarty, SPE, Chevron IE&P, and W.D. Norman, SPE, Chevron ETC Abstract This paper documents the utilization of fr
Jairam Kamath, Chevron Distinguished Author Series articles are general d
Myeong Noh* and Abbas Firoozabadi, SPE, Reservoir Engineering
Research Institute (RERI) * now with Chevron Corporation Summary Gas-well productivity is affected by two
Liang-Biao Ouyang, SPE, Chevron E&P Technology Co., and Ramzy
Sawiris, SPE, Chevron Overseas Petroleum Co. Tubing
Summary Production and injection profiling throug
Liang-Biao Ouyang, SPE, and Dave Belanger, SPE, Chevron Corp. Summary Permanent downhole monitoring can pr
D.J. Goggin, M.A. Ovuede, N. Liu, U. Ozdogan, P.B. Coleman, and D.P.
Meinert, Chevron Intl. E&P Co.; I. Nygard, Statoil; and J. Gontijo, Petroleo
Brasileiro Nigeria Ltd. Abstract Large deepwater fields with a limited num
Yula Tang and W.S. (Bill) Huang, Chevron Energy Technology Company Abstract A dual-lateral well was completed in a Ch
B. Khoshnevis, R. Rastegar Moghadam, SPE, and I. Ershaghi, SPE, U. of
Southern California, and K. Larbi, SPE, and V. Villagran, SPE, Chevron Abstract Several methods for unloading water from
Yula Tang, SPE, Chevron Energy Technology Company, Zheng Liang,
Southwest Petroleum Institute Abstract This work presents a new dynamic model
E. Zuluaga and J.H. Schmidt, Chevron ETC, and R.H. Dean, Simwulf
Systems Abstract Cavity completions have been widely use
Ashraf Aly Abou Elnaga, Chevron San Jorge S.R.L., and Edgar Almanza,
Marcelo Batocchio, Kent Folse, and Martin�Schoener-Scott, Halliburton
Energy Services Inc. Abstract Chevron San Jorge S.R.L. operates in the
Emmanuel Ifediora, Charles Ibrahim, and Davis Ekeke, SPE, Addax
Petroleum Development (Nigeria) Ltd.; Francis Nwaochei and Emeka
Ogugua, SPE, Chevron Nigeria Ltd.; Emeka C. Ene, Sylvester Orumwese,
and Kingsley Idedevbo, SPE, Oildata Wireline Services Abstract Electric line remedial work such as throug
Robert D. Pourciau, Chevron Corporation Summary Extended-reach naturally perforated w
Ian D. Palmer and Nigel G. Higgs, Higgs-Palmer Technologies; Robert M.
Mathers & Scott R. Herman, Chevron Abstract A detailed sand prediction has been made
Yula Tang, W.S. (Bill) Huang, Chevron Energy Technology Company Abstract Open-hole Gravel packing is increasingly
Mingqin Duan, Stefan Miska, Mengjiao Yu, Nicholas Takach, and
Ramadan Ahmed,SPE, University of Tulsa; and Claudia Zettner, SPE,
ExxonMobil Summary Effective removal of small sand-sized s
G. Navaira, SPE, Chevron; M. Hupp, T. Palisch, SPE, CARBO Ceramics
Inc; J. Renkes, SPE, PropTester, Inc Abstract Offshore completions in the Gulf of Mexic
M.R. Wise and R.J. Armentor, Chevron, R.A. Holicek, B.R. Gadiyar, M.D.
Bowman, R.A. Jansen, and S.N. Krenzke, Schlumberger Abstract Screenless sand control completions pro
David Underdown, SPE, Chevron; Henky Chan, SPE, Chevron Pacific
Indonesia Summary The Duri field in Sumatra Indonesia sh
Bernhard Lungwitz, SPE, Chris Fredd, SPE, Mark Brady, SPE, and
Matthew Miller, SPE, Schlumberger; Syed Ali, SPE and Kelly Hughes,
SPE, ChevronTexaco Summary A self-diverting-acid based on viscoelas
M.A.P. Albuquerque, SPE, Schlumberger; A.G. Ledergerber, SPE,
Chevron; and C. Smith, SPE, and A. Saxon, SPE, Schlumberger Abstract Between December 2003 and February
M.S. Newman, Chevron Australia Pty. Ltd., and�M.M. Rahman, SPE,
The University of Adelaide Abstract The success of a stimulation technique is
V. Kumar, SPE, V. Bang, SPE, G.A. Pope, SPE, and M.M. Sharma, SPE,
U. of Texas at Austin, and P.S. Ayyalasomayajula, SPE, and J. Kamath,
SPE, Chevron Abstract Significant productivity loss occurs in gas
K. Hughes and N. Santos, SPE, Chevron, and R.E. Arias and S.V.
Nadezhdin, SPE, Schlumberger Well Services Abstract Historically carbon dioxide (CO2)–foam
Myeong Noh* and Abbas Firoozabadi, RERI *currently with Chevron
Corporation Summary Liquid blocking in some gas-condensate
Akshay Sahni, SPE, Ken Kelsch, SPE, Hathaiporn Samorn, and Chalatpon
Boonmeelapprasert, SPE, Chevron Abstract Interpreting pressure transient tests in co
A.K. Ambastha, SPE, and M. Anderson, SPE, Chevron Corp.; H. Gandhi,
SPE, Kuwait Oil Co.; and P.-D. Maizeret, SPE, Schlumberger Abstract Mauddud reservoir in the Greater Burgan
Medhat M. Kamal and Yan Pan, Chevron Energy Technology Company Abstract A new well testing analysis method is pres
Xianjie Yi, James E. Sabolcik, and Harvey E. Goodman, Chevron Energy
Technology Company, and Brent W. Walton, Chevron International
Exploration & Production Company Abstract Sand control decisions are often made ba
he long tradition of innovative production growth and enhancement projects in the Greater Ekofisk Area in 2004 ConocoPhillips Norway AS (
any phases of expansion the Kuparuk hydrocarbon miscible water-alternating-gas (MWAG) project has grown from 10 patterns on 2 drillsites
oPhillips Alpine facility on the Alaskan North Slope has experienced slugging problems severe enough to trip the high-high inlet separator le
s gathering networks require large capital investments in wells subsea equipment pipelines and compression systems. Generally the optim
dustry invests billions of dollars in oil and gas production from deep waters the concern for flow assurance of reservoir fluids to the surface a
examines the behavior of heavy oil reservoirs developed with horizontal and multilateral wells.�Advanced decline curve analyses were us
ow a variety of ways to achieve higher recovery factors from heavy oil reservoirs but most of them involve the injection of thermal energy or c
ips China Inc. (COPC) operates the Penglai 19-3 oil field located offshore in Bohai Bay the People’s Republic of China. COPC holds a
ples of reaction-diffusion processes are encountered in enhanced heavy oil recovery applications. A typical instance of such a process is whe
ars several Steam Assisted Gravity Drainage (SAGD) projects have proven effective for the recovery of heavy oil and bitumen and Expandin
and for oil grows the petroleum industry is expanding the technology envelope to access and exploit many unconventional resources.� Th
ps Indonesia Inc. Ltd. is producing oil and gas in various locations in Indonesia both on and offshore. This paper covers work performed in t
f gas potential in low permeability reservoirs ( 10 seams to complete which may exhib
plaining well performance in these areas has required the examination of a mechanism whereby coal permeability increases over time. Field
an adjusted system compressibility function similar to that proposed by Bumb and McKee (1988) to account for adsorbed gas. These modif
nal rock matrix quality these reservoirs generally require both natural and induced fracture networks to enable economic recovery of the hyd
ulation but is neither practical nor necessary for resource assessment across large areas. A methodology for resource assessment is deve
rate from the C sand. Gas lift can be used in formation powered jet pump wells to further enhance drawdown on a well while jet pumping. M
the overall lift efficiency. In 2006 ConocoPhillips conducted a study to design a gas lift system for the Surmont SAGD development that wou
003 it became apparent that the original well design would not achieve the 1.1 Bcf/D production target because of well construction problem
based on the reservoir characterization. Well performance had proven to be economic in this Jurassic marine sandstone without hydraulic
s was analyzed. This paper presents the results of a study focused on increasing the understanding of productivity drivers using a database
nd clean out wellbores. Snubbing operations can be costly in terms of investment and time. Annular fracs have been applied in the industry a
ned by reservoir properties geologic setting rock mechanics development plan and completion design. In this paper we will review the uniq
ere monitored by fixed probes placed normal to the expected plane of propagation. Fracture tip arrivals were captured by the fixed pressure p
mall acid volume is required to economically obtain the desired broad reservoir access. We have developed a model to predict the placemen
re sand-control to prevent sand production at the expected drawdowns planned during the life of the wells. To help ensure high rate long life
n conditions are satisfied the sand rate is reasonably stable. This paper clarifies nine forms of post-failure stabilization. Subsequently field m
mples in the low to intermediate strength range for defining the stress-strain relationship (or material laws) rock failure and yield criteria and
cased perforated well may have lower productivity (as characterized by a positive skin factor) relative to the equivalent openhole completion
temperature. Yet another concern in acid fracturing in long carbonate intervals is attaining the necessary diversion to ensure that multiple s
ocking on gas relative permeability. A chemical treatment was developed to reduce the damage caused by condensate and water blocking. T
orizontal wellbores heat return rates and losses to the vertical section above the target formation. This paper proposes a new technique to
s acquired in complex rock/fluid models. The general pore-scale framework considered in this paper is based on NMR random walks for mul
tes of oil recovery and optimized reservoir management requires good estimates of the reservoir permeability.� In the Tengiz field a gian
raining images MPS enables the modeling of complex curvilinear structures (e.g. sinuous channels) in a much more geologically realistic w
e dominant over the interfacial forces. New steady-state relative permeability data have been measured over a wide range of capillary numbe
xico uncovering a large concentration variation of asphaltenes. These asphaltene nanoparticles are shown to be colloidally suspended in the
es the complicated thermodynamic and transport properties of a near-critical fluid. Two-phase-flow tests were performed across a range of p
recovery potential at negligible pressure gradient. Numerous imbibition tests show that oil recovery from diatomite is accelerated and enhan
ralogy pore structure and physical properties of material collected before and after the experiments. One set of reservoir samples consist o
n the backdrop of potential loss of well deliverability owing to condensate banking in the well vicinity or from pure depletion standpoint when
of the Marrat E is dominated by a forty-foot thick largely dolomitized interval with 15-20% porosity and 20-100 mD permeability. The upper z
assical experimental design method was applied and reasonable P10 P50 and P90 reservoir simulation models were designed. Next we lo
elow the gas/oil contact (GOC). Once the well waters out the well is recompleted in the gas zone. Completion occurs either at the crest for a
ages.��� We present a comprehensive portable flexible and extensible FM framework completely decoupled from surface and su
dry climates where easily accessible sources of freshwater are limited large volumes of freshwater are being used for non-potable uses s
subsurface disposal alternatives of produced water management using examples from Chevron Thailand’s greater B8/32 operating are
ral locations of clean sandstone reservoirs. As a result a comprehensive portfolio of prospects has been built for a robust development prog
as that contains high CO2 concentrations greater than 75%. This is observed in both dissolved gas and in gas caps in various blocks of the f
porosity and 10-100 mD permeability. Productive intervals in the Marrat A and C zones average 15-20% porosity and 0.5-2 mD permeability
ymers and gels have been used extensively in field applications to suppress excess water production and improve oil productivity.� Field e
cribed frequency (e.g. quarterly) until the total well ‘budget’ for the field is exhausted and eventual termination of wells as they reach p
ations to address this issue. However these methods either are impractical for the production optimization problem or require complicated m
hus gradient-based methods have not found much applicability to this problem and most existing algorithms applied to this problem are sto
rates on reservoir pressures under various injection and production scenarios is of immense benefit. The method presented in this paper
pact on pressure-drop computation in wellbores producing steam-water gas-condensate and gas-oil mixtures. Computational results show t
e spatial locations though time. This error analysis can easily identify locations or times with high errors. During manual history matching with
he permeability field. Both of these procedures are technically appropriate only for random fields (e.g. permeability) characterized by two-poi
ertise in simulation development. Here we apply the simultaneous perturbation stochastic approximation (SPSA) method to history match m
e reservoir description. Methods based on�Monte Carlo Simulation (MCS) are widely used. This is driven by the generality and simplicity o
e pressure if available to calibrate the model against a specific reservoir. Thereafter the model is used for predictions. We focused on three
o demonstrate CRMs capabilities in different settings: a tank representation of a field its ability to determine connectivity between the produc
the surfactant in Type III near the optimum salinity. Salinity gradient design is a robust design since it can compensate for heterogeneity and
ass equilibrium equations for component mole fractions saturation temperature and pressure using the Newton-Raphson method. External
and speed. Here we describe an efficient natural-variable-based general formulation approach which handles general partitioning of phase-
wave and S-wave velocities and impedances dynamic and static Young’s moduli and dynamic and static Poisson’s ratios. Example
model (IPM) is to predict the reservoir performance while honoring mechanical design constraints of the surface network. The integrated pro
and downhole data were available. The accuracy of the heat-transfer calculations improved with a variable-earth-temperature model and a n
of the relative permeability curve can be obtained from a well under voidage rate control in a solution gas drive system. For a well under pres
d study. Our approach allows us to do away with the simplifying assumptions of the dual-porosity (DP) conceptualization traditionally employe
tions. The ensemble-level upscaling approach aims to achieve agreement between the fine- and coarse-scale flow models at the ensemble
. These conditions indicate that MPFA formulations which lead to smaller flux stencils are desirable for grids with high aspect ratio or severe
model that allows the estimation of oil rate production forecasts and reserves for existing or proposed new wells.� In addition relative per
the mathematical model of these multiphase multicomponent systems. The comparisons demonstrate that SPU schemes may fail to pred
echanical and non-Darcy skin and average pressure. Second with these known parameters use an analytic tool to describe the deliverabilit
l-field Wara simulation model.� The 23-million cells geological model was scaled-up to 4 million cells for flow simulation.� Four pseudo
alculation is proposed and an analytical solution is derived on the basis of some realistic assumptions. The analytical solution can be used to
is an intuitive while fundamental approach to address this problem. Sensitivity analysis is based on a theory with which the functioning of a c
cash flows. These forecasts take full account of facilities constraints and uncertainties in reservoir and operational parameters through link
esis tool. The actual optimization is performed using a commercially available solver. For an oilfield with about 75 wells the tool requires on
reservoirs are needed to be developed in order to provide enough gas for a particular project. A significant drawback of this modelling appro
with an aquifer in transient phase (unsteady-state) and producing under a certain production schedule can plot as a straight-line on a p/z plo
ns in terms of reduced uncertainty and increased probable net present value (NPV). Unlike previous approaches well-placement optimizatio
l resources it now appears possible to apply systematic approaches for efficiently optimizing reservoir performance. In previous work we inc
he conceptual geologic model is maintained and that any history-matching-related artifacts are avoided. Creating reservoir models that matc
appearing in the flow model. In this work a systematic upscaling procedure is presented to construct a dual-porosity dual-permeability mo
s. In this work we extend these formulations to generate full dual-porosity dual-permeability MSR models and additionally introduce the use
dstones. A 3-D thermo-poroelastic model that accounts for the effect of convective heat transfer is developed in this study. Transient couple
proved history match when input into a reservoir simulation model. An ANN was developed to improve the history match with a ‘small’
eters which are then used to generate N numeric Injector-Producer-Relationship (IPR) values for the N producer-injector pairs. The IPR valu
that this is incorrect. With a correct implementation of the RML method within a Bayesian framework we show that RML does an adequate j
pe signifies the pseudosteady-state (PSS) flow period whereas the negative slope implies infinite-acting (IA) flow. Constant-rate production
eliable and sustainable performance. Table 1 presents a list of operating constraints and this paper includes examples regarding the applic
ere are many factors surface and subsurface that affect the reliability and accuracy of production forecasts. All these factors are not single-
r algorithms for managing a variety of field processes. In this study three field processes are considered. First average pressure within a res
-to-date. In this paper we apply the EnKF for continuously updating an ensemble of permeability models to match real-time multiphase prod
onal system using data from two reservoir analogs: the shallow seismic dataset from the Mahakam Fan and outcrop data from the Brushy C
iate workflows are used.� The reservoirs studied include a Permian-age carbonate reservoir in New Mexico an Upper Miocene deepw
experimental design workflows and the different methods of generating response surface models for reservoir simulation studies there is a
aturation). To compute the fine-scale flow field two sets of basis functions - dual and primal - are constructed. The dual basis functions whic
rated data such as breakthrough times. To increase robustness of simulators especially for adverse mobility ratio flows that arise in gas inje
ifornia. All models included an initial primary depletion zone of 6 ft within 60 ft of net pay. Up to twenty-five 2.5-acre patterns were included in
esentation of the fluxes across control volume faces. These fluxes are then interpolated to define the velocity field within each control volume
ited to two-phase water-oil flow under incompressible or slightly compressible conditions. We propose an approach to history matching thr
ly expanded the scope and applicability of streamline-based history matching in particular for three phase flow. In our previous work we cal
able history matched models which have multiple combinations of model parameters is required to obtain a probabilistic view of the reservo
f this study 3 new horizontal wells were being planned and new gas sales agreements were being considered.� We developed a dynam
ned. In this work we extend this approach to 3D systems and introduce and evaluate procedures to decrease the computational demands of
2006). Upscaling of multi-phase flow entails a detailed flow information in the underlying fine scale. We apply adaptive prolongation and restr
bank at the water/oil interface is evaluated at every timestep thereby allowing continuous update of the ‘external pressure’ in Hall’
exacerbates the prediction problem. This study explores the possibility of using simplified approaches to compute bottomhole pressure (BHP
water-cut have also adversely affected production. The objective of this simulation study of wellbore transient flow is to understand past prod
ation methods for various required thermal parameters such as the Joule-Thompson coefficient and fluid expansivity. The approach taken i
ods. Frictional and kinetic heads are estimated using the simple homogeneous modeling approach. We present a comparative study involvin
feasibility of open horizontal well completions hydraulic fracturing design and sanding onset prediction also warranted rock mechanics anal
s. Since in a producing horizontal well fluid inflowing temperature is not affected by elevational geothermal temperature changes the primary
he model input parameters and the predicted results. A probability distribution of the fault reactivation maximum reservoir pressure provides
re available. The first two statistical moments of the dependent variable (pressure) are conditioned on all available information directly. An ite
ormholes were observed to break through to the end of the cores an order of magnitude more rapidly than occurs in more homogeneous core
ydrocarbon phase in a two-phase system. We propose a new model of trapping and waterflood relative permeability which is applicable for
gas production vaporization concentrates solids in the brine that will precipitate into the formation when sufficiently concentrated. This pape
d their locations to facilitate building next generation earth and flow-simulation models. The geological assessment involved mapping fault or
Several contexts of oilfield integration and their role in Digital Oilfield of the Future (DOFF) initiatives are identified. We discuss the results of
n the Gulf's deepwater1 and ultra deepwater2. Following on from the successes of an aggressive deepwater exploration campaign in the Gul
perability deliverability and system performance. This paper focuses on two key aspects of the flow assurance plan for subsea gas develop
gth and the effective production fracture length. Ineffective fracture clean-up is often cited as a likely culprit. The main results presented in
so has been an enabler for heavy-oil developments [American Petroleum Inst. (API) gravity 0.934] in Brazil and the North Sea t
ble for specific circumstances since Darcy proposed the simple and useful Darcy’s law in 1856. As a consequence various correlations f
producer reservoir-wide and facility-related will be communicated. New near-wellbore and reservoir in-depth treatments will be particularly
e obtains this information by monitoring at the wellbore. Such approaches require significant time and water-cut development to determine ho
pwater asset to demonstrate the simulator’s capabilities. In this example we matched the bottomhole pressure (BHP) and pressure/tem
ront movements detect crossflow and fluid migration assist in reservoir simulation studies etc. After a PLT is run subsequent workover is
rtainty normally creeps into assigned well rates. This study provides a methodology wherein both the total and individual layer rates can be c
assist in reservoir simulation studies etc. Subsequent workover operation following a PLT run is frequently performed aiming at reducing w
ont movements detect crossflow and fluid migration assist in reservoir simulation studies etc. After a PLT is run subsequent workover is r
r reliable and accurate identification of transient break points (to separate transients into relevant subsections) and investigating the impact
urements was a risk that should be mitigated providing a major opportunity to add value. Historical experience has shown that the diamete
e test algorithms were then developed with significantly more accurate estimation of the oil saturation from a centralized-detector C/O tool in
ectives are presented in a methodical way on the following bases: field block pattern and wells. A novel diagnostic plot is presented to ass
eption" process through the automated identification and prioritization of exception wells. The primary benefit of incorporating the surveillanc
xtures. The coal pack was initially dry and free of gas then saturated by each test gas at a series of increasing pore pressures and a constan
d several multilateral drilling patterns for CBM reservoirs are studied. The reservoir parameters that have been studied include gas content p
ment pipelines manifold configuration and associated piping etc. In many cases gas lift sourcing might require completely fresh construction
d completion issues in a stacked-reservoir situation. The ultimate objective of this study was to ascertain economic completion strategy so th
rough the well architecture.� To this end a tri-lateral MRC well with a mother bore and two laterals has been recently drilled in this reservo
ess. This paper presents a comprehensive semi-analytical model for estimating the productivity of horizontal wells completed with slotted lin
nvironments is a priority. With conventional frac pack fluids these greater depths and higher bottomhole pressures often would result in the
Lolon et al. 2004; Vincent 2004; Olson et al. 2004). Although the importance in gas wells is evident the authors pose the question of whethe
estigation of fracture clean-up mechanisms. This investigation was undertaken under a Joint Industry Project (JIP) active since the year 2002
roseismic monitors without borehole equipment in downhole configurations represents a relatively new and untested technology for hydraulic
eral readership of recent advances in various areas of petroleum engineering. Introduction Predicting and assuring well deliverability often
er than that in single phase only a handful of studies have been made on the subject. In this work we have measured the high-velocity coef
s which is the primary motivation and focus of this project. In the present paper a thermal model recently developed for single-phase- and
hich consist of interval control valves (ICVs) and many sensors will be used to monitor analyze and control (MAC) injection and production
up involving unstable operation conditions and changing reservoir deliverability. The conventional steady-state based liquid load-up predictio
hysical and software simulators have been developed to demonstrate the feasibility of the new approach and to configure the approach for v
falling back and liquid transfer from the tubing into the annulus during shutting-in period is specially considered for liquid accumulation and s
g skin 2) increase in effective wellbore radius 3) creation of an enhanced permeability (dilatant) zone near the wellbore and 4) decrease in p
ompleted with electro-submersible pumps (ESPs). To effectively meet the operator’s needs for a method that would help optimize well p
d tubing since most through tubing perforation are done in real time. Apart from space constraint at the wellsite and cumbersome logistics th
extended-reach completion and intervention operations along with the lessons learned while implementing these case-history jobs. Introduc
y an analysis is presented on the economics and trade-offs of vertically-oriented perforating (with possibly managed sand production) versus
e of this investigation is to build an accurate model to validate and quantify the non-Darcy mechanical skins for the high-angle OHGP gas w
ti-zone completions it is often difficult and expensive to determine which well or specific completion interval has failed most times requiring
ution that involve many field-proven technologies such as reservoir characterization perforating coiled-tubing intervention matrix acidizing r
One of the biggest problems associated with the production of the crude oil in this environment is the production of massive amounts of solids
ts as a temporary barrier and diverts the fluid into the remaining lower-permeability treating zones. After treatment the SDVA barrier breaks
methods of placement. Pre- and post-job production logs acquired in five wells provided analysis of changes in the production profiles. In one
been proposed and implemented to stimulate such wells. However all of these methods offer short-lived stimulation and are sometimes not
oduction rates called for different options. One of those options was the recently developed CO2 viscoelastic surfactant (VES) fluid system. It
heterogeneities and boundaries and is the central theme of this paper.� Additionally seismic data can guide the design of pressure trans
ensive test program including flowing and static pressure surveys modified isochronal test two buildup tests and FloScan Imager (FSI) log
and the “total mobility of all phases. The new method uses the surface flow rates and fluid properties of the flowing phases and the sam
his project.� This software was provided and developed by EPS Ltd a Weatherford company in collaboration with COPNo. Specification
inlet separator.� Slugging mechanism and instability analysis were performed. The instability is due to combination of its low flow rate ov
ll wells exhibit a characteristic extended transient linear flow regime followed by an exponential decline.�Similar results were obtained wh
eliability flexibility and robustness to produce wells with high flow rates and lift heavy oil in an offshore environment. The first ESP installatio
nsport mechanisms. We evaluate a simulation model for the displacement of carbon dioxide in a simultaneous injection of carbon dioxide an
of the steam chamber. Thus the solvent will have enough time to dissolve/disperse in the bitumen in the mobile zone before steam condensa
ding and cyclic steam stimulation (CSS) are being used extensively for the recovery of moderately viscous heavy oil from sand stone reservo
horizontals (2 300 - 3 400 ft) with openhole completions utilizing stand-alone screens through the producing interval. The reservoir section is
oad lenses. Core data is sparsely available. Most importantly there are no structural features that may construe trapping mechanisms. In vie
of dynamic rupture propagation from earthquake seismology to predict the nature of fractured/damage zones associated with reservoir scale
usses a newly developed propagation resistivity tool that is designed to be azimuthally sensitive for use in geosteering and formation evaluati
This paper shows a well where the information was extracted and included in the decision making process to an extent that sets a new indus
are often neglected. Incorporating formation pressure testing into the drilling process on the other hand creates challenges to perform mea
from PGS Total and Beicip-Franlab has applied advanced reservoir characterization techniques to constrain petrophysical property distribu
to establish representative relationships/correlations at the grid block scale used in SAGD flow simulation. �The mini-models are construc
en considered drilling reach and anti-collision limitations and finally had the appropriate facilities and regional evacuation constraints impose
5/8-in casing with zones separated by packers and produced commingled through sliding sleeve doors (SSDs). In the past few years more a
can be predicted. This paper proposes a new analytical model to predict the temperature fronts and heating efficiency between and along th
mated from Ausing four different solution methods: (1) constrained pressure residuals (CPR) (2) lower block Gauss-Seidel (3) upper block G
maximum robustness and parallel efficiency of these solvers in a wide range of problems that the oil industry is currently pursuing on. A new
d to represent deformation behaviors of rocks in the geomechanics model. Porosity is selected as the coupling parameter between two coupl
able to most gas lifted fields and will be particularly beneficial when applied to those with complex production systems and those where com
step. The overall procedure is successfully applied to a complex channelized reservoir model involving changing well conditions. The griddin
ons there is a need for a systematic data analysis process to improve our understanding of reservoir and production conditions using the acq
ty to fractured reservoirs the effect of oil viscosity and a comparison of its performance with WAG and CGI processes. A Hele-Shaw type m
ms operative in the GAGD process. The model was also designed to adopt different vertical well configurations. The model experiments hav
purpose commercial core analysis simulator was used to simulate the flood experiments and to perform a parameter sensitivity study. The re
Alaska’s North Slope started producing oil at about the same time as the United Kingdom North Sea in the mid to late 1970’s. Alask
entional natural gas exploration and exploitation. As those technologies in geology geophysics drilling completion and production have ma
ns there is a need for a systematic data analysis process to improve our understanding of reservoir and production conditions using the acq
¿½reservoirs by Clarkson et al. (2007a) and Gerami et al. (2007) and to 2-phase (gas and water) CBM wells by Clarkson et al. (2007b).�
of stress and sorption. Most models however utilize an empirical method for estimating sorption-induced strain. Recently a theoretical mod
owing material balance (FMB) and production type curves may be adapted to account for CBM storage mechanisms (i.e. adsorption) but to
mally takes place after reconnaissance but before final appraisal. A step-wise phased CBM prospect assessment process allows us to: ga
seams to complete which may exhibit strong contrasts in initial pressure gas content thickness and permeability.� Further the lateral co
ermeability increases over time. Field data and pressure transient analysis (PTA) for Fairway wells have revealed that coal permeability does
count for adsorbed gas. These modified material balance solutions allow for type curves" (rate or pressure solutions) to be used in a convent
enable economic recovery of the hydrocarbon. Rock types in this class include shale and coalbed methane (CBM.) The term shale is a catch
ogy for resource assessment is developed from a geostatistical study on the Surmont lease. The uncertainty in more than 30 correlated varia
wdown on a well while jet pumping. Many formation powered jet pumps are being used in Kuparuk wells with gas lift to increase the drawdow
urmont SAGD development that would allow better control of lift gas into the production string and in late 2007 the wells completed with gas
ecause of well construction problems. Three wells on the remotely located wellhead platform were abandoned because of wellbore instabilit
marine sandstone without hydraulic fracturing until drilling the CD2-37 well in 2003. The poor reservoir quality found in the southwestern edg
productivity drivers using a database on well productivity related to different completions stimulations and production options. The database
s have been applied in the industry as an alternative completion strategy. However previously documented annular jobs have been small siz
. In this paper we will review the unique advantages and disadvantages of horizontal openhole completions in the Colville River field. Three
were captured by the fixed pressure probes and showed a distinct fluid lag region (i.e. a lower fluid pressure region close to the fracture tip).
ped a model to predict the placement of injected acid in a long horizontal well and to predict the subsequent effect of the acid in creating wo
ls. To help ensure high rate long life completions the producing zones are frac-packed. The average perforated interval during the initial co
re stabilization. Subsequently field methods to deal with sand problems with uncertain sand rate predictions are proposed. Introduction Per
s) rock failure and yield criteria and other non-linear rock parameters required for numerical modeling analysis; (3) perform a series of form
o the equivalent openhole completion because of two factors: the convergence of the flow to the perforations and the blockage of the flow by
ary diversion to ensure that multiple sets of perforations are adequately stimulated. Because of their high solubility and highly fractured/vugu
by condensate and water blocking. The treatment is composed of a fluorinated material delivered in a unique and optimized glycol-alcohol s
s paper proposes a new technique to estimate cooling time and formation thermal diffusivity by using thermal transient analysis (TTA) along t
ased on NMR random walks for multiphase fluid diffusion and relaxations combined with Kovscek’s pore-scale model for two-phase flu
eability.� In the Tengiz field a giant carbonate reservoir in western Kazakhstan a method has recently been developed to calculate appar
a much more geologically realistic way than traditional two-point statistics (variogram-based) techniques. However in the original MPS imple
over a wide range of capillary numbers including very high values corresponding to the near-well region.� These measurements have bee
wn to be colloidally suspended in the crude oil in agreement with recent laboratory results and settle preferentially lower in the oil column in a
were performed across a range of pressures and flow rates to simulate reservoir conditions from initial production through depletion. A sing
m diatomite is accelerated and enhanced at elevated temperature mainly due to a systematic shift toward greater water. Comparison of resul
ne set of reservoir samples consist of relatively clean calcite-rich opal-A and opal-CT diatomites. Samples from the other reservoir are clay-r
rom pure depletion standpoint when the well penetrates a small-fault block. Distinguishing the reason for premature rate decline has a profo
0-100 mD permeability. The upper zones contribute 10-20% of the production from thin intervals with 12-15% porosity and 2-5 mD permeab
n models were designed. Next we looked upon the development plan by performing a second round of design of experiment runs with unco
pletion occurs either at the crest for a small gas-cap reservoir or at the GOC inducing reverse cone for reservoirs with thick-gas columns. A
letely decoupled from surface and subsurface simulators. The framework has a clearly defined interface for simulators and external FM algo
being used for non-potable uses such as by the agricultural and industrial sectors. This paper discusses the growing need for produced w
nd’s greater B8/32 operating area. Introduction The foundation of a robust produced water management strategy lies in the ability to acc
n built for a robust development program. Horizontal wells were utilized to improve oil recovery in shaly sands and to reduce water coning in
in gas caps in various blocks of the field. Well documented production data have indicated variations in CO2 concentration in different areas
% porosity and 0.5-2 mD permeability. The current estimated original oil in place is about 500 million bbls. A volumetric uncertainty look-back
nd improve oil productivity.� Field experience has demonstrated that candidate-well selection is critical to the success of gel-polymer treatm
l termination of wells as they reach prescribed abandonment criteria.� This method in general results in an irregular well placement patte
on problem or require complicated modifications to the forward-model equations (the simulator). Therefore the usual approach is to formula
ithms applied to this problem are stochastic in nature such as genetic algorithms simulated annealing and stochastic perturbation methods
The method presented in this paper was developed and used by a team of Engineers managing the Meren field waterflood project to diagno
xtures. Computational results show that this dimensionless liquid-film thickness is most likely less than 0.06 in annular flow. For such values
During manual history matching with ESA the efforts are placed on removing the highest errors. In this automatic history matching experime
ermeability) characterized by two-point geostatistics (multi-Gaussian random fields). Realistic systems are much better described by multipoi
n (SPSA) method to history match multiphase flow production data. SPSA which has recently attracted considerable international attention in
iven by the generality and simplicity of MCS. As a black-box approach only pre/post-processing of conventional flow simulations is needed.
for predictions. We focused on three different control volumes for CRMs: the volume of the entire field the drainage volume of each produc
mine connectivity between the producers and injectors and understanding flood efficiencies for the entire or a portion of a field. Significant in
n compensate for heterogeneity and reservoir uncertainties and guarantees the surfactant in Type III for a longer time compared to other de
e Newton-Raphson method. External heat sources and sinks are included in source terms to model the energy interaction with over-burden a
andles general partitioning of phase-component consumes no extra memory and only has a small amount of CPU overhead. This general
static Poisson’s ratios. Examples illustrate how to use the petroelastic model to facilitate the integratation of 4D seismic and reservoir flo
e surface network. The integrated production model construction process consists of five steps which are framing modeling static quality ch
ble-earth-temperature model and a newly developed numerical-differentiation scheme. This approach improved the calculated wellbore fluid
s drive system. For a well under pressure control in a solution gas drive reservoir however we show that the decline is exponential and obta
onceptualization traditionally employed to model naturally fractured reservoirs (NFRs). Using a fracture characterization procedure that is ba
-scale flow models at the ensemble level rather than realization-by-realization agreement as is the intent of existing upscaling techniques. F
grids with high aspect ratio or severe skewness and for media with strong anisotropy or strong heterogeneity. The ideas were recently pursue
ew wells.� In addition relative permeability curves can be generated based on the resultant fractional flow curve.� A comparison with r
e that SPU schemes may fail to predict the formation of the mobile liquid bank at the leading edge of the displacement unless an impractical
alytic tool to describe the deliverability potential for a well or a group of wells including reservoir uncertainty and/or operational constraints. T
for flow simulation.� Four pseudo layers were added to the simulation model to allow fluid migration via faults from the lower reservoirs.ï¿
he analytical solution can be used to generate the temperature profile in a horizontal injection well for any assumed distribution of injection pr
eory with which the functioning of a closed system is derived by analyzing the derivatives of the output with respect to each input combination
operational parameters through links to decision risk analysis software. This paper describes the novel approach used and model applicatio
h about 75 wells the tool requires only a few seconds to read the model information and produce the forecast. The time required to generate
ant drawback of this modelling approach is the simplification introduced when a single tank model (Material balance method) is being used i
can plot as a straight-line on a p/z plot masking the existence of an active aquifer and causing a significant overestimation in gas reserves. T
proaches well-placement optimization is coupled with recursive probabilistic history-matching steps through the use of the pseudohistory con
erformance. In previous work we incorporated adjoint-based optimal control procedures into a general-purpose simulator that allows the eff
Creating reservoir models that match all types of data are likely to have more prediction power than methods in which some data are not ho
a dual-porosity dual-permeability model from detailed discrete fracture characterizations. The technique referred to as a multiple subregion
els and additionally introduce the use of global single-phase flow information in the computation of the upscaled interblock transmissibilities r
eloped in this study. Transient coupled pore pressure and temperature equations for non-isothermal conditions are developed based on cons
he history match with a ‘small’ number of simulation runs for a reservoir that produced oil gas and water for a period of ten years. Du
producer-injector pairs. The IPR values allow one to assess how well an injector influences the producer. This same model and an EKF wer
e show that RML does an adequate job of sampling the a posteriori distribution for the PUNQ problem. In particular the true predicted oil pro
g (IA) flow. Constant-rate production exhibits infinite slope whereas constant-pressure production produces zero slope. Mathematical justifi
ludes examples regarding the application of some of the constraints.� This table also includes consideration for the type of surveillance th
asts. All these factors are not single-valued and would generally have a band of uncertainty around them. The challenge therefore is how to
d. First average pressure within a reservoir region is maintained by adjusting the voidage replacement ratio between a group of injectors and
s to match real-time multiphase production data. We improve the previous EnKF by adding a confirming option (i.e. the flow equations are r
and outcrop data from the Brushy Canyon Formation of West Texas. Shallow seismic data from the Mahakam Fan area shows a high-reso
w Mexico an Upper Miocene deepwater clastic reservoir in California and an Eocene-age shallow water clastic reservoir in Venezuela.�T
servoir simulation studies there is also a growing need to share practical examples of the lessons learned in constructing experimental desi
ucted. The dual basis functions which are associated with the dual coarse grid are used to calculate the coarse scale transmissibilities. The
obility ratio flows that arise in gas injection and other EOR processes it is therefore of much interest to design truly multi-D schemes for trans
ve 2.5-acre patterns were included in the study. Results show that finely gridded models accurately capture near-vertical steam override an
ocity field within each control volume which is then used to trace the streamlines. Existing methods for the interpolation of the velocity field a
e an approach to history matching three-phase flow using a novel compressible streamline formulation and streamline-derived analytic sens
se flow. In our previous work we calibrated geologic models to production data by matching the water-cut and gas/oil ratio using the general
ain a probabilistic view of the reservoir performance. Once a suite of models that all match history has been obtained they are calibrated for
sidered.� We developed a dynamic workflow to create a range of probabilistic simulation models to forecast dry-gas production under sev
rease the computational demands of the method. This includes the use of purely local upscaling calculations for the initial estimation of coars
apply adaptive prolongation and restriction operators for flow and transport equations in constructing an approximate fine scale solution. This
‘external pressure’ in Hall’s formulation. We show that Hall’s formulation is a particular case of the proposed approach. Seve
o compute bottomhole pressure (BHP) from wellhead pressure (WHP) measured rates gravity of producing fluids and tubular dimensions.
nsient flow is to understand past production performance and to find ways to mitigate adverse well behavior.� Simulation showed that low
d expansivity. The approach taken in this study entails dividing the wellbore into many sections of uniform thermal properties and deviation a
present a comparative study involving the new model as well as those that are based on physical principles also known as semimechanistic
also warranted rock mechanics analyses. To make sound decisions on those issues building a well-calibrated geomechanical model was cr
mal temperature changes the primary temperature differences for each phase (oil water and gas) are caused by frictional effects. While ga
aximum reservoir pressure provides a better means to calculate a risk weighted Expected Net Present Value for management to make bette
ll available information directly. An iterative inversion scheme is used to integrate the pressure data into the conditional statistical moment eq
an occurs in more homogeneous cores highlighting the necessity of understanding the flow and transport in vuggy carbonates. The fact that
permeability which is applicable for the entire range of rock wettability conditions. The proposed formulation overcomes some of the limitatio
n sufficiently concentrated. This paper reports on a combined experimental and theoretical analysis on the vaporization portion of this problem
ssessment involved mapping fault orientations from seismic and analyzing image logs and cores for fractures. Fracture trends are in the NE
identified. We discuss the results of our study and compare the results with those from other studies conducted by the SPE and also by two
ater exploration campaign in the Gulf of Mexico a series of major discoveries were rapidly appraised and moved to development (Fig. 1). T
surance plan for subsea gas developments the strategies for managing hydrates and the wax deposition.� Hydrate management strateg
lprit. The main results presented in this paper were obtained using a modified conductivity cell to allow polymer concentration via leakoff a
> 0.934] in Brazil and the North Sea that otherwise would have been uneconomical. This article discusses where the industry started how te
consequence various correlations for PI or IPR calculation have been proposed from simple analytical solutions to rigorous numerical form
n-depth treatments will be particularly detailed.� There will be discussions on Best Practices/ Lessons Learnt to improve the success rates
ater-cut development to determine how the reservoir and water-flood is performing and provide little spatial information as to how the water-fl
ole pressure (BHP) and pressure/temperature monitored about midpoint of the flow string during a multirate-test sequence lasting approxima
PLT is run subsequent workover is routinely performed aiming at reducing water production while maintain or even increase oil and/or gas p
tal and individual layer rates can be computed independently with DTS completion tubular and other related data. To do the entire suite of
ently performed aiming at reducing water production while maintaining/increasing oil and/or gas production. Unfortunately in practice mixing
PLT is run subsequent workover is routinely performed aiming at reducing water production while maintain or even increase oil and/or gas p
ctions) and investigating the impact of continuous downhole rate data in analyzing well tests. We tested four different algorithms one based
erience has shown that the diameter of invasion can be greater than twenty inches by the time a well is logged with wireline which is beyond
om a centralized-detector C/O tool in water-filled boreholes; results reported here are primarily for this tool. The C/O technique is also being
el diagnostic plot is presented to assess well performance and identify problem wells for the field. Results from the application of these prac
enefit of incorporating the surveillance tool in an integrated workflow is to shorten decision time and improve the quality of the decision throu
easing pore pressures and a constant effective stress until steady state. Thus the amount of adsorption varied while the effective stress was
e been studied include gas content permeability and desorption characteristics. Net present value (NPV) has been used as the yard stick fo
require completely fresh construction of entire facilities which will involve project development management costs infrastructure cost and s
n economic completion strategy so that depletion of reservoirs occurs evenly at the project’s termination. Single-well compositional simu
as been recently drilled in this reservoir achieving about 5 000 ft of reservoir contact.� This paper details the process followed to achieve th
ontal wells completed with slotted liners. The semi-analytical model is obtained by coupling the reservoir flow and wellbore flow equations. Th
e pressures often would result in the need for surface treating pressures that exceed the limits of current surface equipment and tubulars. Su
authors pose the question of whether non-Darcy and multiphase flow effects are of concern in typical oil wells in Russia. For the analysis th
oject (JIP) active since the year 2002. The data discussed builds on the initial results published in early 2006 which indicated that the polyme
and untested technology for hydraulic fracture diagnostics. Analysis of the surface microseismic data was carried out for five (5) hydraulic fra
and assuring well deliverability often are important concerns when developing gas-condensate reservoirs. Many gas-condensate projects ar
have measured the high-velocity coefficient β in steady-state two-phase gas/liquid flow. The results are presented as a function of liquid rela
ntly developed for single-phase- and multiphase-fluid flow along a vertical deviated or horizontal well will first be briefly described. The mode
ntrol (MAC) injection and production at the zonal level. Analysis of sensor data will allow operations to estimate well capacity and calculate m
y-state based liquid load-up prediction approach and nodal analysis are insufficient to answer what happens when the well shuts in restarts a
h and to configure the approach for various well characteristics. Background Water enters most gas wells. At the early stages of production
sidered for liquid accumulation and slug height modeling. The new method improves the prediction precision compared to the conventional m
ar the wellbore and 4) decrease in pressure drop near the wellbore to values below the critical threshold for sanding. Even though there are
ethod that would help optimize well productivity and at the same time be cost effective without compromising the results of the operation an
wellsite and cumbersome logistics the main set back with the e-coil is its unavailability while the tractor has high operational cost. This pape
ing these case-history jobs. Introduction Chevron and Marathon each have a 50% working interest in the Petronius project which is operat
ly managed sand production) versus frac-packing. Sand onset prediction agrees fairly well with the observed drawdown/depletion for horizon
skins for the high-angle OHGP gas wells and finally to develop a recommendation for the optimized design. A comprehensive semi-analytic
rval has failed most times requiring production to be shut in for diagnosis. Not until that point can a remedy be evaluated. One GOM produc
ubing intervention matrix acidizing resin consolidation optimized fracturing with proppant flowback control and fines migration prevention. T
duction of massive amounts of solids. In addition to the cost of the recompletions problems associated with disposing of this amount of sand
treatment the SDVA barrier breaks when contacted either by formation hydrocarbons or pre- and postflush fluids. Quantifying diversion flui
ges in the production profiles. In one of the wells the formation was stimulated first with 15% HCl through coiled tubing and then with the v
d stimulation and are sometimes not profitable. New experimental core flooding data using chemical treatments show that the steady-state g
astic surfactant (VES) fluid system. It has recently been employed to eliminate the disadvantages of the traditional polymer-based fluid. This
an guide the design of pressure transient tests especially the test duration to evaluate key seismic anomalies.� Other data such as produc
tests and FloScan Imager (FSI) log has been carried out to evaluate this well. The material discussed in this paper provides a good basis f
es of the flowing phases and the same relative permeability relations used in characterizing the reservoir and predicting its future performanc
boration with COPNo. Specification of the system started in 2005 based on years of prior experience with network production modelling too
to combination of its low flow rate overly-sized pipeline ID and unfavorable pipeline profile.� Flow pattern transition exists at the low spots
.�Similar results were obtained whether the analyses were performed on single dual or triple lateral wells.�Interference between later
nvironment. The first ESP installations were challenged with high free gas and excessive sand production resulting in operational issues an
aneous injection of carbon dioxide and elemental sodium in a heavy oil reservoir. The main objective of using sodium in this process is the hi
mobile zone before steam condensation occurs. Because the solvent blends with the bitumen it significantly lowers (up to 5 fold) the oil visc
us heavy oil from sand stone reservoirs. Another thermal process SAGD (steam assisted gravity drainage) is being used for the recovery of
cing interval. The reservoir section is drilled with a water-based Drill-in-Fluid (DIF) consisting of polymer and CaCO3 particles and displaced t
construe trapping mechanisms. In view of these challenges a permeability model was developed primarily for the Travis Peak Formation of R
zones associated with reservoir scale faults. We include geomechanical constraints in our reservoir model and propose a workflow to more r
n geosteering and formation evaluation while drilling. It uses the tilted antenna concept to produce directionally sensitive measurements that
ess to an extent that sets a new industry standard. Applying an accurate 3D rotary steerable system with openhole sidetrack capabilities incre
creates challenges to perform measurements in a timely manner as well as the need for continuous circulation while testing to ensure wellb
nstrain petrophysical property distribution using elastic inversion products and therein reducing uncertainty in a reservoir model. Following de
on. �The mini-models are constructed on a by-facies basis honoring the spatial variability within each category. �The uncorrected mini-m
gional evacuation constraints imposed. To achieve this history-matched numerical reservoir models were first run within the framework of an
(SSDs). In the past few years more and more horizontal wells have been drilled and completed with expandable sand screens and premium
ating efficiency between and along the horizontal well pair during the SAGD circulation phase. By using the exponential integral solution for r
block Gauss-Seidel (3) upper block Gauss-Seidel and (4) one iteration of block Gauss-Seidel. The pressure block solution in each of these
ustry is currently pursuing on. A new generation of solvers seems to require capabilities to recapture part of the masked physics that is over
upling parameter between two coupled models. The unknowns located on nodes and block-centers in the two models are evaluated using a
uction systems and those where compressors are a constraint on total-system performance. The output from the optimization model princip
changing well conditions. The gridding and upscaling procedures presented here may also be suitable for use with other types of structured o
d production conditions using the acquired data and to make decisions for well performance optimization. We have successfully developed
CGI processes. A Hele-Shaw type model - consisting of two parallel glass plates (23 x 13 x � in size) with � gap between them filled wi
urations. The model experiments have shown that GAGD is a viable process for secondary and tertiary oil recovery. Oil recovery in the immis
a parameter sensitivity study. The results demonstrated how capillary continuity across open fractures may be obtained when wetting phase
a in the mid to late 1970’s. Alaska North Slope (ANS) and UK North Sea oil production rates were approximately equal in 1980 but UK
completion and production have matured and the price for natural has increased the development of unconventional natural gas has been
d production conditions using the acquired data and to make decisions for well performance optimization. We have successfully developed a
wells by Clarkson et al. (2007b).� The present study further enhances the flowing material balance for dry CBM reservoirs by presenting a
d strain. Recently a theoretical model for sorption-induced strain was developed and applied to single-component adsorption/strain experim
mechanisms (i.e. adsorption) but to date the focus has been on relatively simple CBM reservoir behavior such as single-phase (gas) reser
assessment process allows us to: gain local knowledge early at low cost; progressively acquire appropriate data to systematically assess the
ermeability.� Further the lateral continuities of the individual seams vary and are often not correlatable from well-to-well.� Recently ad
revealed that coal permeability does increase over time and is an exponential function of reservoir pressure depletion. While evidence for p
re solutions) to be used in a conventional analysis manner. The significant challenge in the application of production data analysis for shale
ane (CBM.) The term shale is a catchall for any rock consisting of extremely small framework particles with minute pores charged with hydro
ainty in more than 30 correlated variables is calculated on a dense 2D grid using all available information including wells seismic and geolog
with gas lift to increase the drawdown applied to the A sand. An overview of formation powered jet pumps used at Kuparuk Field is presente
e 2007 the wells completed with gas lift were placed on production. This paper will cover the data collection effort and analysis completed to
ndoned because of wellbore instability. Without the production contribution from these wells the first year’s production target would not b
quality found in the southwestern edge of the field required stimulation to produce at economic rates. A hydraulic fracture treatment was perf
nd production options. The database contains 56 wells from 4 different assets and 750 acid and proppant treatments in 663 perforated interv
ted annular jobs have been small size ranging from 40k to 200k lbs of proppant pumped at relatively low injection rates of 15-25 BPM. This
ons in the Colville River field. Three key parameters were critical to the success of horizontal openhole completions and could be applied br
sure region close to the fracture tip). The controlled laboratory experiments showed planar fracture propagation trends as expected from thre
uent effect of the acid in creating wormholes overcoming damage effects and stimulating productivity. The model tracks the interface betwe
erforated interval during the initial completion program was 310 ft with a maximum perforated interval of 571 ft. The typical production casing
ions are proposed. Introduction Perforation cavities are enlarged with sand production. The cavities become contiguous and form larger ca
analysis; (3) perform a series of formation failure and sanding potential analysis for a variety of possible well completion design scenarios us
tions and the blockage of the flow by the wellbore itself. Because of the orientation of a horizontal well relative to the anisotropic permeability
h solubility and highly fractured/vugular nature carbonate reservoirs in the Permian Basin show excellent response to acid fracturing treatme
nique and optimized glycol-alcohol solvent mixture. The chemical treatment alters the wettability of water-wet sandstone to neutral wet and in
ermal transient analysis (TTA) along the horizontal wellbore under a steam heating process. A novel concept of a heating ring is also introduc
s pore-scale model for two-phase fluid saturation and wettability alteration. We use standard 2D NMR methods to interpret synthetic data set
ly been developed to calculate apparent permeability (APERM) based on flow rate from production (PLT) logs.� Incorporation of this flow
s. However in the original MPS implementation all multiple-point statistics moments computed from the training image are exported to the r
� These measurements have been made on several reservoir rocks as well as outcrop rocks and over a range of temperature pressure
ferentially lower in the oil column in accord with the Boltzmann distribution. Relevant fluid features in this case the asphaltene concentration
production through depletion. A single-phase multirate experiment was also performed to assess inertial or non-Darcy effects. Correlations
d greater water. Comparison of results for cores from different diatomite reservoirs appears to indicate that dissolution of calcium-bearing mi
es from the other reservoir are clay-rich opal-A diatomites. The hot alkaline fluids produced porosity channels in samples from both reservo
r premature rate decline has a profound bearing on project economics and asset management. This talk attempts to address various issues
2-15% porosity and 2-5 mD permeability. A two stage design of experiments (DoE) based workflow was used to evaluate and optimize prima
design of experiment runs with uncontrollable uncertainties and decisions as factors. The goal was to validate that the previously selected m
reservoirs with thick-gas columns. Alternatively one can skip the initial oil completion where gas disposition is a nonissue. Gravity-stable flo
for simulators and external FM algorithms. Any black-box simulator or algorithm may become a part of the system by simply adhering to the
ses the growing need for produced water reuse highlights reuse options and gaps and specifically presents Constructed Treatment Wetlan
ement strategy lies in the ability to accurately forecast future water production. Using historical water production data from existing platforms
sands and to reduce water coning in thin remaining oil columns. Horizontal drilling best practices were applied during well planning and drillin
CO2 concentration in different areas of the field. Conventional fluid modeling could not explain the formation of gas caps at dissimilar structu
s. A volumetric uncertainty look-back (1998-2007) has allowed a historical assessment to be made for porosity and water saturation (Sw) un
l to the success of gel-polymer treatments. To date most candidate-well selections are based on anecdotal screening guidelines which ofte
s in an irregular well placement pattern as it attempts to conform to both time-invariant reservoir properties (e.g. permeability field which ma
ore the usual approach is to formulate this problem as a constrained nonlinear-programming (NLP) problem in which the constraints are cal
and stochastic perturbation methods. These methods are usually quite inefficient requiring hundreds of simulations and thus may have limite
ren field waterflood project to diagnose pressure response anomalies and provide estimates of injection targets to achieve any expected pre
0.06 in annular flow. For such values of thin-film thickness the computed friction factor is only slightly higher than that estimated with a smoo
automatic history matching experiment the same systematic approach was found when the convergence efficiencies were high. In this exp
re much better described by multipoint geostatistics which is capable of representing key geological structures such as channels. History ma
considerable international attention in a variety of disciplines can be easily combined with any reservoir simulator to do automatic history ma
entional flow simulations is needed. To achieve reasonable accuracy in estimating the statistical moments of flow performance predictions h
the drainage volume of each producer and a drainage volume between each injector/producer pair. Unlike the numerical simulation approa
e or a portion of a field. Significant insights about the flood performance over a short period can be gained by estimating fractions of injected
r a longer time compared to other designs. A comprehensive surfactant phase behavior model is required to take into account the salinity gra
energy interaction with over-burden and under-burden rocks.� The solution procedure and the treatment of phase transition to achieve sta
ount of CPU overhead. This general formulation approach was developed as part of a next generation reservoir simulation project (DeBaun e
tation of 4D seismic and reservoir flow modeling. Introduction Time-lapse (4D) seismic is a comparison of two 3D seismic surveys over the
e framing modeling static quality check initialization and dynamic quality check followed by forecasting. An IPM was built for Jack and use
mproved the calculated wellbore fluid-temperature profile which in turn increased the accuracy of pressure calculations at both bottomhole
at the decline is exponential and obtain an expression for the permeability. The results were applied to data from solution gas drive simulation
characterization procedure that is based on fracture measurements from wells we stochastically generate a network of hundreds of discrete
nt of existing upscaling techniques. For this purpose flow-based upscaling calculations are combined with a statistical procedure based on a
neity. The ideas were recently pursued in [2] where the L-method was introduced for general media in 2D. For homogeneous media and unif
flow curve.� A comparison with relative permeability curves obtained from special core analysis can be made to provide increased confid
displacement unless an impractical number of gridblocks is used in the simulations. In contrast the high-order FD simulator is demonstrate
nty and/or operational constraints. This paper presents a simple methodology for establishing reservoir parameters and predicting a well’
via faults from the lower reservoirs.� The new model has 100 m x 100 m areal cells and individual layers with an average thickness of 6 ft.
y assumed distribution of injection profile along the length of the well including injection profile that is uniform skewed toward the heel or the
with respect to each input combination. For the injector-producer relationship identification problem we use sensitivity analysis to determine th
approach used and model application. Given the presence of multiple reservoir models multiple PVT descriptions three-phase flow and
recast. The time required to generate the forecast output in the desired format depends on the duration of forecasting the size of the field a
erial balance method) is being used instead of a fine grid simulation model. The material balance method assumes every well contacts all hyd
ant overestimation in gas reserves. The authors in this paper simulate synthetic cases of gas reservoir/aquifer models using a forward mode
ugh the use of the pseudohistory concept. The pseudohistory is defined as the probable (future) response of the reservoir that is generated b
purpose simulator that allows the efficient long term maximization of NPV by optimally controlling well settings with time (similar developmen
thods in which some data are not honored.� The first part of the paper reviews the details of the PPM and the next part of this paper des
referred to as a multiple subregion (MSR) model represents an extension of an earlier method that did not account for gravitational effects
pscaled interblock transmissibilities required by the method. The resulting models are used for waterflood simulations and more interestingly
nditions are developed based on conservation laws. Thermal effects are generated by the temperature imbalance between the drilling fluid a
d water for a period of ten years. Due to a lack of specific protocols for this type of study the trial and error process was utilized to establish
r. This same model and an EKF were first used in Liu et al [5]. The modified EKF used in this paper avoids problems that can arise when pr
n particular the true predicted oil production lies within the band of predictions generated with the RML method and is not biased. We also a
uces zero slope. Mathematical justifications for these diagnostic signatures are presented. During PSS flow wells belonging to the same co
eration for the type of surveillance that is needed to apply the constraints.� Discussion within the paper shows that the most relevant type
m. The challenge therefore is how to generate production forecasts in the face of these uncertainties. Previous production forecasts have bee
atio between a group of injectors and producers. Second control systems are used for the prevention of gas/water coning for single and mul
option (i.e. the flow equations are re-solved from the previous assimilating step to the current step using the updated current permeability m
ahakam Fan area shows a high-resolution deepwater channel-levee system consisting of 10 migrating channels. Using an experimental des
er clastic reservoir in Venezuela.�Two dimensional cross section models of the deepwater clastic reservoir showed that cumulative produ
ed in constructing experimental designs and using response surface models to interrogate the experimental design outcomes. After extens
e coarse scale transmissibilities. The fine-scale pressure field is computed from the coarse grid pressure via superposition of the dual basis
esign truly multi-D schemes for transport that remove or at least strongly reduce the sensitivity to grid design. We present a new upwind bi
pture near-vertical steam override and oil drainage by gravity with a near-horizontal steam/oil interface. High injection pressures observed in
he interpolation of the velocity field and integration of the streamlines do not preserve the accuracy of the fluxes computed by MPFA discreti
and streamline-derived analytic sensitivities. First we utilize a generalized streamline model to account for compressible flow by introducing
ut and gas/oil ratio using the generalized travel time inversion (GTTI) technique. For field applications however the highly non-monotonic pr
een obtained they are calibrated for predicting the future performance and assessment of uncertainty and risk associated with a particular de
orecast dry-gas production under several production scenarios in the Chuchupa field.�Recent seismic re-interpretation a new stratigraph
tions for the initial estimation of coarse-scale transmissibilities and the use of reduced border regions during the iterations. This is shown to d
approximate fine scale solution. This new method eliminates inaccuracy associated with the traditional upscaling method which relies on pre
ase of the proposed approach. Several simulated and field examples demonstrate the value of reformulated Hall analysis. Because Hall form
cing fluids and tubular dimensions. BHP computations on three independent data sets comprising 167 gas/condensate-well tests suggest th
vior.� Simulation showed that low ESP efficiency could be related to down-hole slugging. GOR was the most significant factor for slugging
rm thermal properties and deviation angle. The governing differential equation is solved for each section with fluid temperature from the prio
ples also known as semimechanistic models. These models include those of Ansari et al Gomez et al. and OLGA. Two other widely used e
brated geomechanical model was critical. In this study we reviewed the drilling completion logging and production information from severa
aused by frictional effects. While gas production usually causes a temperature decrease water entry results in either warming or cooling of
Value for management to make better decisions on steam flooding and to anticipate potential consequences. In this study a geomechanical
the conditional statistical moment equations (CSMEs). That is the available information is used to condition or improve the estimates of the
rt in vuggy carbonates. The fact that acid channeled through the vugular cores following the path of the vug system was underlined with com
ation overcomes some of the limitations of existing trapping and relative permeability models. The new model is validated by means of pore-n
he vaporization portion of this problem for dry gas injection. Experiments have been performed previously to determine the rate of water vap
ctures. Fracture trends are in the NE and SW quadrants and fractures are mineralized toward the south and west of the field. Pressure falloff
onducted by the SPE and also by two integrated oil companies (IOCs). We address the goal of “reducing time to decision and show how
nd moved to development (Fig. 1). This paper will give a high level review of some of the recent development challenges for the deepwater a
on.� Hydrate management strategy must focus on preventing blockages versus preventing hydrate formation.� To this end the enginee
w polymer concentration via leakoff and measurements of flow initiation gradients. The paper will discuss the experimental set-up and som
es where the industry started how technology has evolved and the lessons learned that are being applied to increase the application envelo
solutions to rigorous numerical formulations in the literature. As horizontal or multilateral wells have been occupying an ever-increasing sha
Learnt to improve the success rates and mention of challenges ahead.
ial information as to how the water-flood is affected by faults preferential pathways and structural variation. 4D seismic methods represent a
ate-test sequence lasting approximately 60 hours. Calculations show that thermal effects are exacerbated by increasing flow rate and increa
tain or even increase oil and/or gas production from the well. Unfortunately mixing results have been obtained through workover operations
elated data. To do the entire suite of calculations a wellbore model handling steady fluid flow and unsteady-state heat transfer estimates a p
on. Unfortunately in practice mixing results have been obtained through workover operations designed based on PLTs due to poor logging
ain or even increase oil and/or gas production from the well. Unfortunately mixing results have been obtained through workover operations
d four different algorithms one based on the stationary Harr wavelet transform method and others based on nonwavelet approaches such as
logged with wireline which is beyond the limits of investigation for density and neutron tools rendering the interpretation of fluid types ambigu
ool. The C/O technique is also being tested in producers using the corresponding focused tool; we include an example of a successful test of
ults from the application of these practices in a pilot area are shared indicating that the nominal decline rate improved from 33 to 18% per ye
rove the quality of the decision through an automated process.� Other benefits include timelier proactive problem identification better use
varied while the effective stress was held constant. Results show that (i) permeability decreases with an increase of pore pressure at fixed in
V) has been used as the yard stick for comparing different drilling configurations. Configurations that have been investigated are single- dual
ment costs infrastructure cost and space limitation especially in the case of offshore locations. In the Southern Offshore Area of Chevron op
tion. Single-well compositional simulations formed the backbone for our evaluation of three completion options. Each reservoir was characte
ails the process followed to achieve this milestone for the first time in Kuwait. A multi-disciplinary team consisting of Geology Petrophysics G
flow and wellbore flow equations. The model includes the additional pressure drops due to mechanical skin and non-Darcy effect. Additiona
surface equipment and tubulars. Surface treating pressure can be calculated using the equation: Ps = BHTP + Pfric – Phyd …………â
wells in Russia. For the analysis the authors evaluate three primary categories of Russian production wells: gas wells oil wells producing a
2006 which indicated that the polymer concentrates only in the filter cake and that flow along the fracture encounters significant yield stress w
s carried out for five (5) hydraulic fracture stages to: (1) determine the applicability of the surface microseismic approach in the absence of a
rs. Many gas-condensate projects are in deep hot low-permeability reservoirs for which well costs are a significant part of the project econo
presented as a function of liquid relative permeability and liquid saturation. In our measurements the wetting state is varied by the treatment
l first be briefly described. The model can be applied for both wellbore temperature prediction (forward modeling) and for flow profiling using
stimate well capacity and calculate measure actual flow rates. Decisions for operational control will be made based on the data analysis the
ens when the well shuts in restarts and eventually dies. To address the intrinsically transient multi-phase flow problems a combined study o
lls. At the early stages of production the gas pressure is sufficiently large to lift the water that enters the wellbore. Gas and water mist flow to
sion compared to the conventional methods that assume the constant tubing pressure for the entire process. The resistance coefficients of t
d for sanding. Even though there are analytical tools available for predicting the initiation of sanding for simple well configurations there are
mising the results of the operation an improvement over traditional tubing-conveyed perforating (TCP) was required. A propellant-assisted (P
has high operational cost. This paper outlines the successful perforation of horizontal wells in the Niger Delta while addressing the operation
he Petronius project which is operated by Chevron. The field is located in the Gulf of Mexico 150 miles south of Mobile Alabama. The proje
erved drawdown/depletion for horizontal perforations. This benchmarking appears to support the validity of the shear-failure model. This is im
sign. A comprehensive semi-analytical model was developed based on modification of the horizontal well model. The additional pressure dro
edy be evaluated. One GOM producer engaged the services of a proppant supplier to determine whether a suite of proppants/gravel could
rol and fines migration prevention. The proper candidate selection treatment design treatment execution production management and co-
with disposing of this amount of sand--and the effect the produced solids have on the facilities such as stabilization of emulsions--are a larg
lush fluids. Quantifying diversion fluid efficiency and cleanup are important factors for successful candidate selection and job design. Labor
ugh coiled tubing and then with the viscoelastic diverting acid system bullheaded down the production tubing; production logs were acquired
atments show that the steady-state gas and condensate relative permeability in both outcrop and reservoir sandstones can be increased by
traditional polymer-based fluid. This VES-CO2 fluid system combines the benefits of viscoelastic surfactant-based fluid—such as low forma
malies.� Other data such as production history core data formation evaluation from well logs analog information on channel geometry etc
in this paper provides a good basis for evaluating long-term production potential of horizontal wells exploiting tight and thin reservoirs with re
and predicting its future performance. The method has been verified by comparing the results from analyzing several synthetic tests that we
ith network production modelling tools in the Ekofisk area to simulate and optimise production from the reservoir to the export meter. The sy
tern transition exists at the low spots and liquid accumulates and blocks the flow. In the low pressure system once gas blows out and system
wells.�Interference between laterals was not observed. Introduction The application of horizontal and multilateral wells is gaining mom
on resulting in operational issues and a number of failures. Even in this hostile environment production peaked at 37 800 BOPD during Nov
using sodium in this process is the highly exothermic reaction of sodium with the in-situ water that results in the liberation of heat that in turn
antly lowers (up to 5 fold) the oil viscosity. This process has the potential to accelerate recovery with less steam requirement per barrel of oil
ge) is being used for the recovery of higher viscosity heavy oil and bitumen from oil sand. Some of these processes are apparently very succ
and CaCO3 particles and displaced to a solids-free DIF prior to running the screens. Typically acid is used to degrade water-based DIF filte
ily for the Travis Peak Formation of Robertson and Leon counties where it has produced 96 BCF of gas and 0.54 MMbbl of oil. A permeabil
el and propose a workflow to more routinely incorporate damage zones into reservoir simulation models. The model we propose calculates
ionally sensitive measurements that are lacking in traditional LWD propagation tools. This paper also discusses the theory and the developm
openhole sidetrack capabilities increase well design flexibility and the ability to act on the real-time LWD data. The bottom hole assembly us
culation while testing to ensure wellbore safety. Formation testing at Bohai Bay is difficult because of the unconsolidated formations and all
ty in a reservoir model. Following detailed rock typing core and log analysis from approximately 5400 feet of core and from 26 wells and log
category. �The uncorrected mini-model flow results lead to a too-narrow range of permeability. �Geostatistical scaling laws are applied
re first run within the framework of an infill well-location optimization software package. Then drilling constraints were imposed with drilling p
pandable sand screens and premium screens. Most of the wells produce 10 000 to 15 000 BFPD using electrical submersible pumps (ESPs)
the exponential integral solution for radial heating in a long cylinder and superposition in space for multi-heating sources the proposed mode
ssure block solution in each of these different schemes is calculated using the Algebraic Multi Grid (AMG) method. The inverse of the saturat
rt of the masked physics that is overlooked by strictly algebraic procedures in order to retrieve part of the loss efficiency and furthermore to
he two models are evaluated using an area weighting technique The proposed model has been implemented on the Linux PC clusters for so
t from the optimization model principally comprises recommended values for individual-well gas lift injection rates separator pressures com
or use with other types of structured or unstructured grid systems. Introduction Modern geological and geostatistical tools provide highly deta
n. We have successfully developed a model to predict well flowing pressure and temperature (i.e. the forward model) and applied an invers
with � gap between them filled with Ottawa silica sand - has been used in all experiments with a perforated plastic tube serving as the ho
oil recovery. Oil recovery in the immiscible secondary mode was as high as 83% IOIP and the oil recovery in the immiscible tertiary mode was
may be obtained when wetting phase bridges were established. A viscous component over the open fractures was provided when the wetting
approximately equal in 1980 but UK North Sea oil production has exceeded that of the Alaska ANS by more than 40% in recent years. The
nconventional natural gas has been blossoming for last decade globally. Without question it is certain that the development of unconventio
. We have successfully developed a model to predict well flowing pressure and temperature (i.e. the forward model) and applied inversion
r dry CBM reservoirs by presenting a p/z* implementation of the concept. This application �while accounting for the distinguishing charact
omponent adsorption/strain experimental data. The new model was developed from basic thermodynamic principles and is more predictive
ior such as single-phase (gas) reservoirs with static effective permeability. The major contribution of the current work is the adaptation of m
ate data to systematically assess the geological situation and reservoir conditions; define and attempt to fill knowledge gaps that represent ri
e from well-to-well.� Recently advances in production data analysis (PDA) methodologies have been made for CBM wells; techniques de
sure depletion. While evidence for pressure dependent permeability in CBM reservoirs has been presented in the literature before this work
of production data analysis for shale gas systems is to determine what the parameter values (analysis results) represent within the context o
with minute pores charged with hydrocarbon and includes carbonate and quartz-rich rocks. Another type of unconventional reservoir is stacke
n including wells seismic and geologic trends. The correlation structure between the variables is modeled under a multivariate Gaussian mo
ps used at Kuparuk Field is presented. Formation powered jet pumps could be beneficial in other multi-zone oil fields around the world to inc
ion effort and analysis completed to determine the efficiency of the two types of gas lift nozzles used in the completions the methodology for
r’s production target would not be met. To meet the production targets a complete well redesign was undertaken. First the tubing was u
hydraulic fracture treatment was performed resulting in a 200% production increase. Over the past three years a stimulation program has ev
nt treatments in 663 perforated intervals. It was found that the absolute total production per interval is similar for all assets; however the draw
w injection rates of 15-25 BPM. This paper describes the practices of massive annular fracturing treatments down the 5-1/2 by 2-3/8 annulus
completions and could be applied broadly in other situations. Using these three criteria other major North Slope reservoirs were evaluated to
agation trends as expected from three-dimensional modeling. Introduction Since the inception of the hydraulic fracturing technique as a me
The model tracks the interface between the acid and the completion fluid in the wellbore models transient flow in the reservoir during acid in
571 ft. The typical production casing string for the wells consists of 10-3/4 in. casing with an 8-1/16 in. production liner. Drift diameter throug
come contiguous and form larger cavities around a cased hole. Finally they form irregular cavities as shown in Fig.1. � Fig.1 Cavity grow
well completion design scenarios using 3-D finite element technique for rock structure coupled with well production and fluid flow simulation.
elative to the anisotropic permeability field perforation skin models for vertical wells that consider these effects notably the Karakas and Tar
nt response to acid fracturing treatments. However inadequate diversion can leave substantial portions of the reservoir untreated. Different a
r-wet sandstone to neutral wet and increases the gas relative permeability. The increase in gas relative permeability was quantified by comp
cept of a heating ring is also introduced to measure the heat storage in the heated bitumen at the time of testing. Heating ring can be consid
ethods to interpret synthetic data sets for diverse petrophysical configurations including two-phase saturations with different oil grades mixe
) logs.� Incorporation of this flow calibrated apparent permeability into the static geologic earth model offers an elegant solution to the lon
e training image are exported to the reservoir model without processing which allows simulating only categorical or discretized variables. This
er a range of temperature pressure connate water saturation and hydrocarbon composition typical of gas-condensate reservoirs. PVT data
s case the asphaltene concentration gradient are then integrated in a geologic model and used to predict crude oil properties and DFA logs
l or non-Darcy effects. Correlations were developed to represent both the gas and condensate relative permeabilities as a function of capill
hat dissolution of calcium-bearing minerals tends to retard fines production and delay changes in core wettability. Longterm corefloods exam
annels in samples from both reservoir types. These small channels (10 mm to 2 mm in diameter) form initially at the inlet and grow slowly tow
lk attempts to address various issues starting with well productivity and considering various completion options to modeling the coupled rese
used to evaluate and optimize primary reservoir development. Reservoir uncertainties affecting volume and connectivity were assessed in th
validate that the previously selected models reasonably represented P10 P50 and P90 oil recoveries and net present value after including
sition is a nonissue. Gravity-stable flooding is required to maximize reserves. Extensive flow simulations in multiple history-matched models
the system by simply adhering to the FM interface which is discussed in this paper. The FM framework capabilities are demonstrated on se
sents Constructed Treatment Wetlands (CTW) as a technology for the treatment of produced water and the facilitation of water reuse. The C
duction data from existing platforms future drilling activities and impact of artificial lift we can generate forecasts of produced water. Current
pplied during well planning and drilling executions such as optimum well designs specific LWD/MWD tool selections low fluid loss drilling flu
ation of gas caps at dissimilar structural positions nor could it explain the existence of oil legs at pressures below the apparent (predicted) bu
porosity and water saturation (Sw) uncertainty. This look-back based assessment of porosity and Sw uncertainty allows the impact of increas
otal screening guidelines which often results in inconsistent treatment outcomes. With only pretreatment well data as input parameters the
ties (e.g. permeability field which may be nonuniform) and time-varying properties (e.g. pressure and saturation field).�As such it is a we
blem in which the constraints are calculated explicitly after the dynamic system is solved. The most popular of this category of methods for o
simulations and thus may have limited application to large-scale simulation models with many wells. We propose a novel continuous appro
targets to achieve any expected pressure response for the project reservoirs without the use of numerical models. It uses the slopes of the c
gher than that estimated with a smooth-channel assumption. When the homogeneous model is used to compute pressure gradient by ignorin
ce efficiencies were high. In this experiment a simple parametric search routine was used to compare the performance of a data weighted (
uctures such as channels. History matching algorithms that are able to reproduce realistic geology provide enhanced predictive capacity and
simulator to do automatic history matching. The SPSA method uses stochastic simultaneous perturbation of all parameters to generate a do
nts of flow performance predictions however large numbers of realizations are usually necessary. Here we use an alterative direct approac
like the numerical simulation approach the CRMs use only production/injection data to predict performance which provides simplicity and s
ed by estimating fractions of injected fluid being directed from an injector to various producers and the time taken for an injection signal to re
ed to take into account the salinity gradient design with all possible phase transitions. The development discussed in this paper enables accu
ent of phase transition to achieve stable non-linear iterations are discussed. The simulator is verified by comparing results from problem No.
eservoir simulation project (DeBaun et al. 2005) for “next generation is the ability to accommodate fluid models currently used in reservo
n of two 3D seismic surveys over the same spatial region at different points in time. Seismic attributes such as P-wave and S-wave velocities
g. An IPM was built for Jack and used as the primary forecasting method for (1) evaluation of artificial lift alternatives (gas lift sea floor boos
sure calculations at both bottomhole and wellhead. The proposed simulator accurately mimics afterflow during surface shut-in by computing
ata from solution gas drive simulation models and are presented. Application to field data is also presented. Introduction Decline curve anal
ate a network of hundreds of discrete fractures for a large sector (17 mi � 1.4 mi � 1.1 mi). A novel semi-automatic gridding technique is
ith a statistical procedure based on a cluster analysis. This approach allows us to compute numerically the upscaled two-phase flow function
D. For homogeneous media and uniform grid this method has four-point flux stencils and seven-point cell stencils in two dimensions. The re
be made to provide increased confidence. In order to develop an fw (water cut) versus Sw (prevailing water saturation) relationship from his
h-order FD simulator is demonstrated to accurately predict the liquid bank at much lower grid resolution providing for a more efficient simula
parameters and predicting a well’s future deliverability potential. Field examples show that computing reservoir parameters from buildup
ers with an average thickness of 6 ft. �Overall this new model has 18 times refinement compared to the previous model for the Wara rese
niform skewed toward the heel or the toe or exhibits some discontinuity (e.g. leakoff into a high permeability streak or fracture). This paper
se sensitivity analysis to determine the injector-producer relationships by varying the injection rates i.e. the inputs to a trained neural networ
descriptions three-phase flow and a variety of well types from infill to ‘new field’ the best source of reservoir performance profiles f
Introductio
of forecasting the size of the field and whether the output is to be produced as a text file or a Microsoft Excel spreadsheet. 1.
d assumes every well contacts all hydrocarbons and that geological heterogeneity is not a factor in recovery. It is necessary to know how reli
aquifer models using a forward model and an inverse model that were programmed in visual basic to show that the combination of certain ra
se of the reservoir that is generated by a probabilistic forecasting model. To test the results of the proposed approach an example reservoir
ettings with time (similar developments have also been reported by others). Furthermore our recent extensions namely a new “approxim
M and the next part of this paper describes the additional work that is required to history-match real reservoirs using this method. Then a geo
d not account for gravitational effects. The subregions (or subgrid) are constructed for each coarse block using the iso-pressure curves obtai
d simulations and more interestingly for compositional simulations of first-contactmiscible gas injection. In a series of flow simulations invol
mbalance between the drilling fluid and drilled formations and increase as the temperature imbalance increases. Cooling the formation is fo
ror process was utilized to establish guidelines and suggestions. The neural network was developed by using an inverse solution method to
oids problems that can arise when processing real data and provides additional information that is useful for future research. Our modified E
method and is not biased. We also apply the ensemble Kalman Filter (EnKF) method to the PUNQ data set and show that this method also
flow wells belonging to the same container will exhibit the same slope. Differences in slope are an indication of reservoir compartmentaliz
er shows that the most relevant types of operating constraints are often not being used and also addresses appropriate operating limits for c
evious production forecasts have been generated using deterministic values for these uncertainties at their end points – 3 forecasts. This m
gas/water coning for single and multiple wells. Finally the average temperature within a reservoir region is maintained at a critical value by c
ng the updated current permeability models). By doing so we ensure that the updated static and dynamic parameters are always consistent w
hannels. Using an experimental design framework and a series of three increasingly complex models we investigated the effect of nine diffe
ervoir showed that cumulative production and water breakthrough times were essentially the same for models using the two major stratigra
ental design outcomes. After extensively applying these concepts for over 18 months in identifying the major sub-surface uncertainties expl
e via superposition of the dual basis functions. Having a locally conservative fine scale velocity field is essential for accurate solution of the sa
design. We present a new upwind biased truly multi-D family of schemes for multi-phase transport capable of handling counter-current flow a
High injection pressures observed in many prior simulations are primarily a result of confined reservoir models. Steam-zone pressures and te
e fluxes computed by MPFA discretizations. Here we propose a method for the reconstruction of the velocity field with high-order accuracy f
for compressible flow by introducing an ‘effective density’ of total fluids along streamlines. This density term rigorously captures chan
owever the highly non-monotonic profile of the gas/oil ratio data often presents a challenge to this technique. In this work we present a trans
nd risk associated with a particular development plan. In this paper we demonstrate a structured approach to history matching uncertainty a
c re-interpretation a new stratigraphic study and a revision of the petrophysical model resulted in new probabilistic static models for the fiel
uring the iterations. This is shown to decrease the computational requirements of the reduced procedure significantly relative to the full metho
pscaling method which relies on prescribed inaccurate boundary conditions in computing upscaled variables. The new upscaling algorithm is
ated Hall analysis. Because Hall formulation involves an integral the resultant signature by nature is insensitive in revealing clues about su
gas/condensate-well tests suggest that the no-slip homogeneous model applies quite well. Statistical results show the homogeneous model
he most significant factor for slugging and increasing water cut made slugging worse. The sinusoidal wellbore trajectory was studied to optim
with fluid temperature from the prior section as the boundary condition. This piecewise approach makes the model versatile allowing step-
and OLGA. Two other widely used empirical models Hagedorn and Brown and PE- 2 are also included. The main ingredient of this study e
d production information from several wells across the field. We found that (1) The Kotabatak field has a general maximum horizontal stress
sults in either warming or cooling of the wellbore. Warmer water entry is a result of water flow from a warmer aquifer below the producing zo
nces. In this study a geomechanical model was established for the Batang Field Central Sumatra Indonesia. Using the geomechanical mo
ition or improve the estimates of the first two moments of permeability pressure and velocity directly. This is different from Monte Carlo (M
vug system was underlined with computerized tomography scans of the cores before and after acid injection. This observation proposes tha
model is validated by means of pore-network simulation of primary drainage and waterflooding. We study the dependence of trapped (residua
ly to determine the rate of water vaporization from Berea core samples at uniform initial water saturation (Zuluaga and Monsalve 2003). The
and west of the field. Pressure falloff tests on some peripheral injectors indicate partially sealing faults. Most of these wells lie on seismic-sca
cing time to decision and show how even the most basic data-integration gaps can slow decisions with great economic impact. In informatio
pment challenges for the deepwater and ultra deepwater fields in the GoM and will explain how these challenges were addressed and how th
rmation.� To this end the engineer must evaluate flow conditions system geometry and production profiles in addition to temperature an
ss the experimental set-up and some of the artifacts that had to be removed prior to ensuring more reliable data.�The results highlight th
ed to increase the application envelope and reliability of this completion method.�The review covers advances in openhole-drilling techniq
en occupying an ever-increasing share of hydrocarbon production since the 1980s more accurate PI or IPR estimation has been emerging a
ion. 4D seismic methods represent a powerful tool to assist reservoir management. This work describes the planning implementation of an
ed by increasing flow rate and increasing gauge distance from the perforations. Second we performed a detailed uncertainty analysis with e
btained through workover operations designed based on PLT due to poor logging procedure unreasonable PL tool selection poorly execute
ady-state heat transfer estimates a production rate given wellhead pressure and temperature. The same model is then used to compute the
based on PLTs due to poor logging procedure unreasonable PL tool selection poorly executed surveys inappropriate interpretation etc. I
tained through workover operations designed based on PLT due to poor logging procedure unreasonable PL tool selection poorly execute
d on nonwavelet approaches such as Savitzky-Golay Smoothing Filters and a novel pattern recognition approach called the Segmentation Me
he interpretation of fluid types ambiguous in most hydrocarbon bearing sands in this basin. To reduce this uncertainty comprehensive wirelin
e an example of a successful test of the tool in an unperforated well. The paper identifies further development needed to use C/O technique
ate improved from 33 to 18% per year without any infill drilling. The change in the decline rate is attributed primarily to effective waterflood m
tive problem identification better use of the practitioner's time (focus on analysis rather than identification) elimination of repetitive data gath
n increase of pore pressure at fixed injection gas composition and (ii) permeability change is a function of the injected gas composition. As th
e been investigated are single- dual- tri- and quadlateral wells along with fishbone (also known as pinnate) wells. In these configurations th
outhern Offshore Area of Chevron operations several wells have quit and require some kind of support to flow to surface. Artificial lift (gas lif
options. Each reservoir was characterized by history matching drillstem tests (DSTs). Experimental design (ED) reduced the large number o
onsisting of Geology Petrophysics Geophysics Drilling and Service Company was instrumental in utilizing state-of-the-art 3D seismic inter
skin and non-Darcy effect. Additionally the model could handle non-uniform flux non-uniform skin distribution and selective completion with
BHTP + Pfric – Phyd …………………….. (1) Ps = surface pressure BHTP = bottomhole treating pressure Pfrict = friction pressure P
wells: gas wells oil wells producing above the bubblepoint and oil wells producing below the bubblepoint. For each category the authors des
e encounters significant yield stress when the filter cake cumulative thickness dominates the width of the fracture. The new results presente
eismic approach in the absence of an offset observation well; and (2) characterize fracture height azimuth length and symmetry with respe
a significant part of the project economics. It is well known that the deliverability of gas-condensate wells can be impaired by the formation of
etting state is varied by the treatment with a fluorochemical compound. Then the effect of wettability on the high-velocity coefficient in two-ph
modeling) and for flow profiling using a measured temperature profile (inverse problem). The model has successfully been applied for invest
ade based on the data analysis the results of which will be used to optimize overall field performance and maximize financial returns. In this
e flow problems a combined study of completion inflow analysis and wellbore dynamic simulation was performed. The analysis indicates th
wellbore. Gas and water mist flow to the surface where the water content is easily separated from gas using separation equipment. As the p
cess. The resistance coefficients of the plunge motion in four different phases are determined by combining the dynamic model with field tes
simple well configurations there are very few models that are capable of predicting cavity stability or cavity growth for general field applicatio
as required. A propellant-assisted (PA) perforating method that could optimize well productivity while maintaining stringent health safety and
Delta while addressing the operational issues encountered. The first case history is Addax ORW-11H a horizontal well planned to have the
south of Mobile Alabama. The project was sanctioned in August of 1996 after both compliant-tower and subsea-development options were
of the shear-failure model. This is important because the model while fairly simple has many different inputs including depth profiles for un
ell model. The additional pressure drop is added to consider the mechanical skin and non-Darcy flow in the near-wellbore zones of drilling da
er a suite of proppants/gravel could be developed that could be uniquely identified and placed in each completion interval. In the event of pro
on production management and co-ordination of all services are essential to the success of the screenless completion. In this paper the co
stabilization of emulsions--are a large cost to operations. A program was initiated in 2002 to evaluate the effectiveness of the completions in
date selection and job design. Laboratory tests defining these key factors are presented in this paper. This paper demonstrates the diverting
ubing; production logs were acquired after each treatment. The results from comparison of pre- and post-job production logs clearly show
oir sandstones can be increased by a factor of 2 to 3 over a wide range of temperature (145 to 275��F). Spectroscopic data show that
tant-based fluid—such as low formation damage superior proppant transport and low friction pressures—with carbon dioxide advantages
information on channel geometry etc. is also important in getting a better understanding of reservoir description. While we briefly discuss all
oiting tight and thin reservoirs with reservoir pressures close to the bubble-point pressure. Test data interpretation highlights successful dev
lyzing several synthetic tests that were produced by a numerical simulator with the input values. Use of the method with field data is also des
reservoir to the export meter. The system is designed to fully utilise the OOC’s continuous measurement and recording systems throug
stem once gas blows out and system pressure drops the pipeline inlet gas increases velocity and picks up a new hydrodynamic slug.� Th
and multilateral wells is gaining momentum worldwide due to their ability to drain reservoirs more effectively.�This advantage is even mo
n peaked at 37 800 BOPD during November 2003 before declining as a consequence of reservoir pressure depletion. Moreover the lower re
s in the liberation of heat that in turn reduces the oil viscosity. Another important advantage of this process is the formation of sodium hydrox
s steam requirement per barrel of oil produced. The important factors that control the performance of the ES-SAGD process are the solvent
e processes are apparently very successful with ultimate recovery over 80%. Application of thermal processes to the carbonates poses a dif
used to degrade water-based DIF filtercake and remove CaCO3 contained in the filtercake. The use of a common acid was not an option for
and 0.54 MMbbl of oil. A permeability model was developed by integrating core and log data using the Adaptive Neuro Fuzzy Logic Inferenc
s. The model we propose calculates the extent of the damage zone along the fault plane by estimating the stress perturbation associated with
scusses the theory and the development of this tool as well as the experimentation and numerical modeling data used to characterize its azi
D data. The bottom hole assembly used consisted not only the standard LWD services such as gamma ray propagation resistivity density n
e unconsolidated formations and all aspects associated with this type of environment such as borehole stability hole washouts sanding wh
eet of core and from 26 wells and logs from 90 well penetrations the team observed that there was considerable heterogeneity in this “h
eostatistical scaling laws are applied to correct the permeability values. This paper presents a permeability modeling procedure with applica
nstraints were imposed with drilling planning software and facility constraints were included via a surface coupling system for multiple-reservo
electrical submersible pumps (ESPs). In these commingled completions the water cut rises from a few percent to 80% to 90% within the firs
heating sources the proposed model can be used to predict these temperature profiles provided that the steam temperatures or pressures
G) method. The inverse of the saturation (or more generally the nonpressure) blocks are approximated using Line Successive Over Relaxati
e loss efficiency and furthermore to obtain insights that make them adaptable to different reservoir situations. In this work we show that this
ented on the Linux PC clusters for solving 2D compositional reservoir problems considering geomechanics effects. These results indicate tha
tion rates separator pressures compressor discharge pressures and compressor use. Field results are presented in this paper to demonst
geostatistical tools provide highly detailed descriptions of the spatial variation of reservoir properties resulting in fine-grid models consisting o
orward model) and applied an inversion method to detect water and gas entry into�wellbore using synthetic data generated by the forward
orated plastic tube serving as the horizontal production well placed at the bottom of the model. Vertical tubes were placed at different depths
y in the immiscible tertiary mode was 54% ROIP. The model has also shown that the gas injection depth may not have an influence on oil re
ctures was provided when the wetting preference between the injected fluid and the rock surface allowed the formation of stable wetting phas
more than 40% in recent years. The UK North Sea and ANS share similar areal sizes and other similarities but differ in several key areas in
that the development of unconventional natural gas in China will be blossoming in the coming decades. However there are significant challe
rward model) and applied inversion method to detect water and gas entry into wellbore using the synthetic data generated by the forward mo
ounting for the distinguishing characteristics of a CBM reservoir �uses the industry-standard practice of p/z material balance to calculate o
mic principles and is more predictive than the empirically-based approaches. In this paper the theoretical model is expanded to incorporate m
e current work is the adaptation of modern PDA techniques (by use of modified material balance time/pseudotime and pseudopressure defin
fill knowledge gaps that represent risk and uncertainty; increasingly understand the distributions of key parameters that control reserves de
n made for CBM wells; techniques developed for tight gas and conventional oil and gas reservoirs have been adapted by incorporating som
nted in the literature before this work seeks to compare the magnitude and functional form in two different reservoir units. In the high produc
esults) represent within the context of the inherent complexity of these systems. In this work we propose a slight (but substantive) modificatio
of unconventional reservoir is stacked pay units exhibiting somewhat better pore characteristics than in the case outlined above but with the
ed under a multivariate Gaussian model. The local distributions of uncertainty have been checked with cross validation and with more than 1
zone oil fields around the world to increase oil production rate while reducing water production rate and lifting costs. Introduction Kuparuk Fi
the completions the methodology for optimization of SAGD gas lift systems and recommendations for future improvement. Background Sur
as undertaken. First the tubing was upsized from 7 in. to 9-5/8 in. Then semi-openhole completions with pre-drilled liners and openhole pack
years a stimulation program has evolved with improvements in candidate selection performance and predictability. Future plans include co
milar for all assets; however the drawdown applied in 1 asset is 4 times lower than the other assets. The performance of the wells in most as
ents down the 5-1/2 by 2-3/8 annulus used at the Bajiaochang Gas Field Sichuan Basin China as a substitute to fracturing down casing an
th Slope reservoirs were evaluated to determine their potential for horizontal-openhole-completion applications. Focus areas in this evaluatio
ydraulic fracturing technique as a means to improve productivity of oil and gas wells the hydraulic fracturing community has determined certa
ent flow in the reservoir during acid injection considers frictional effects in the tubulars and predicts the depth of penetration of acid as a func
production liner. Drift diameter through the tapered production casing is 9-1/2 in. and 6-1/2 in. respectively. The 6-1/2 in. drift diameter allows
own in Fig.1. � Fig.1 Cavity growth during sand production To model the sand flow each cavity must be meshed as shown in Fig.2 requ
production and fluid flow simulation.� The types of completion design analyzed include cased hole completion using conventional perfora
effects notably the Karakas and Tariq model (1991) are not directly applicable to perforated horizontal completions. Using appropriate varia
of the reservoir untreated. Different acid systems have been developed to counter the problems in acid fracture stimulations. Chemical and m
permeability was quantified by comparing the gas relative permeabilities before and after treatment. Improvements in the gas relative perme
f testing. Heating ring can be considered analogous to a drainage area in a conventional pressure transient analysis. The proposed cooling
rations with different oil grades mixed wettability or carbonate pore heterogeneity. Results from our study indicate that for both water-wet a
l offers an elegant solution to the long-standing problem of how to best incorporate dynamic PLT data into a reservoir model.� A reservoir
egorical or discretized variables. This implementation is appropriate with clastic reservoirs for which typically depositional facies are simulat
as-condensate reservoirs. PVT data of gas-condensate fluids can be used to predict the ratio of the gas to the condensate relative permeabi
ct crude oil properties and DFA logs for all hydraulically connected sections of the reservoir. Predicted and newly acquired DFA log data mat
permeabilities as a function of capillary number. A nearly 20-fold increase in gas relative permeability was observed from the low- to high-ca
ettability. Longterm corefloods examine the ability of diatomite to sustain thermal operations. Core permeabilities following significant volume
nitially at the inlet and grow slowly toward the outlet as experiments progressed. Fines mobilization and perhaps hydraulic action during force
options to modeling the coupled reservoir/wellbore/surface network system. In particular we explore how uncertainties in volumetrics and ca
and connectivity were assessed in the first stage of the workflow. The second stage of the workflow focused on dynamic uncertainties. The
nd net present value after including decisions in the design. The validation worked out properly reinforcing the confidence in the model sele
in multiple history-matched models have shown that the proposed strategy improves recovery significantly. Two field examples are present
k capabilities are demonstrated on several examples involving diversified production strategies and multiple surface/subsurface simulators. O
d the facilitation of water reuse. The Chevron/Cawelo water reuse project and demonstration CTW located in California’s San Joaquin V
orecasts of produced water. Currently in B8/32 asset we produce about 68 000 bbl/day of water and an additional 20 000 bbl/day of water i
ool selections low fluid loss drilling fluids real-time geosteering data monitoring and the cleaning of the pay zone during completions were ap
res below the apparent (predicted) bubble point pressure. A fluid characterization model was performed in the El Trapial field in order to imp
certainty allows the impact of increasing quantity of data changing analytical workflows and updating interpretations to be examined. Based
nt well data as input parameters the neural networks developed in this work can accurately predict the post-treatment cumulative oil product
aturation field).�As such it is a well placement strategy governed purely by reservoir drainage objectives rather than infrastructure conside
ular of this category of methods for optimal control problems has been the penalty-function method and its variants which are however extr
e propose a novel continuous approximation to the original discrete-parameter well placement problem such that gradients can be calculate
cal models. It uses the slopes of the cumulative net voidage curve and the measured change in pressure response to define reservoir specifi
compute pressure gradient by ignoring the wavy-liquid film on frictional pressure drop good agreement is achieved with field data and with th
he performance of a data weighted (DW-L2) to an equal weighted (EW-L2) objective function. The data weighted objective function tended t
de enhanced predictive capacity and are therefore more suitable for use with field optimization. In this work we apply a new parameterization
on of all parameters to generate a down hill search direction at each iteration. The theoretical basis for this probabilistic perturbation is that th
we use an alterative direct approach for model calibration and uncertainty quantification. Specifically we describe a Statistical Moment Equ
ance which provides simplicity and speed of calculation. Once the CRM is calibrated with historical production/injection data we use an opti
me taken for an injection signal to reach a producer. Injector-to-producer connectivity may be inferred directly during the course of error mini
discussed in this paper enables accurate modeling and optimization of chemical flooding designs for realistic field-scale projects where a sal
comparing results from problem No. 3 of the Fourth SPE Comparative Solution Projects� and a cyclic steam injection case with other com
luid models currently used in reservoir simulation as well as models that will be developed in the future. With this general formulation approa
uch as P-wave and S-wave velocities and impedances are obtained from each 3D seismic survey. In some cases changes in seismic attribu
t alternatives (gas lift sea floor boosting and electric submersible pumps) (2) identifying key artificial lift design parameters using Experimen
during surface shut-in by computing the velocity profile at each timestep and its consequent impact on temperature and density profiles in th
ted. Introduction Decline curve analysis has been in use for several years within the oil industry but limited to reserves estimation and future
semi-automatic gridding technique is developed to create a high-quality unstructured grid that conforms to discrete fractures and wells while
he upscaled two-phase flow functions for only a small fraction of the coarse blocks. For the majority of blocks these functions are estimated
ell stencils in two dimensions. The reduced stencils appear as a consequence of adapting the method to the closest neighboring cells. Here
water saturation) relationship from historical production data a simplified material balance algorithm and the Corey equation are solved simul
providing for a more efficient simulation approach. In 2D displacement calculations with gravity included the CPU requirement of the SPU s
ng reservoir parameters from buildup and drawdown data and establishing the deliverability relation instills confidence in analysis. We also s
the previous model for the Wara reservoir.� Thus this model is suitable for evaluating PMP infill drilling and pattern waterflood.� This p
ability streak or fracture). This paper also presents comparison of temperature profiles obtained with the analytical solution given in this pape
the inputs to a trained neural network model of the oilfield and analyzing the outputs i.e. the production rates.� With our approach we
ce of reservoir performance profiles for each well was the in-house Eclipseâ„¢ reservoir simulation models. The production profiles for each
Introduction The push towards “digital oilfields has highlighted the need for efficient decision support systems
ft Excel spreadsheet. 1.
very. It is necessary to know how reliable are final gas and condensate recovery factors and gas condensate and water production profiles p
ow that the combination of certain rate schedules and the unsteady state nature of aquifers can cause a straight-line p/z plot in waterdrive ga
sed approach an example reservoir was investigated with multiple realizations all of which match the same production history. The results o
ensions namely a new “approximate feasible direction algorithm enabled the treatment of nonlinear path inequality constraints efficientl
rvoirs using this method. Then a geological description of the reservoir case study is provided and the procedure to build 3D reservoir mode
k using the iso-pressure curves obtained from local pressure solutions of a discrete fracture model over the block. The subregions thus acco
. In a series of flow simulations involving both connected and disconnected fracture systems it is shown that the MSR method provides resu
ncreases. Cooling the formation is found to be helpful in lowering collapse pressure resulting in a more stable borehole. However it is also fo
using an inverse solution method to formulate the training and testing data. Normalization of the data simplified the neural network improve
l for future research. Our modified EKF is applied to real data from a section of an oil field. A validation strategy for the estimated IPR values
set and show that this method also gives a reasonable quantification of the uncertainty in performance predictions with an uncertainty range
dication of reservoir compartmentalization lateral or vertical.�Equally important we provide mathematical proof of why different wells in a
ses appropriate operating limits for completions with sand control.� Completion selection and design influence operating constraints.�
eir end points – 3 forecasts. This method however does not test the possible interactions between uncertainties which would lead to multi
n is maintained at a critical value by controlling flow into the formation so as to operate with the desired mobility of heavy-oil.� Traditional P
c parameters are always consistent with the flow equations at the current step. However it also creates some inconsistency between the sta
we investigated the effect of nine different geologic factors on several different measures of the flow behavior. Our results show that as expe
models using the two major stratigraphic picks as for models constrained by 12 detailed stratigraphic picks.�Three dimensional streamlin
major sub-surface uncertainties explaining observed production performance and in prescribing additional development options for fifteen re
ssential for accurate solution of the saturation equations (i.e. transport). The primal basis functions which are associated with the primal coa
ble of handling counter-current flow arising from gravity. The proposed family of schemes has four attractive properties: applicability within a
models. Steam-zone pressures and temperatures are similar to those typically observed in the field when the model is unconfined (i.e. the m
locity field with high-order accuracy from the fluxes provided by MPFA discretization schemes. This reconstruction relies on a correspondenc
density term rigorously captures changes in fluid volumes with pressure and is easily traced along streamlines. A density-dependent source
nique. In this work we present a transformation of the field production data that makes it more amenable to GTTI. Further we generalize the
ach to history matching uncertainty assessment and probabilistic forecasting for mature assets through application of global optimization me
probabilistic static models for the field.� While these static models were being built a parallel numerical simulation study was conducted
significantly relative to the full methodology while impacting the accuracy very little. The performance of the adaptive local-global upscaling
ables. The new upscaling algorithm is validated for two-phase incompressible flow in two dimensional porous media with heterogeneous per
sensitive in revealing clues about subtle changes that may occur during formation fracturing or plugging. We observed that the derivative of
sults show the homogeneous model compares quite favorably with mechanistic two-phase-flow models. However the main advantage of the
lbore trajectory was studied to optimize ESP operating conditions. It was found that reducing sinusoidal amplitude by half and flattening the h
es the model versatile allowing step-by-step calculation of fluid temperature for the entire wellbore. We present simple thermodynamically so
d. The main ingredient of this study entails the use of a small but reliable dataset wherein calibrated PVT properties minimizes uncertainty fr
a general maximum horizontal stress orientation of NESW. However there could be localized stress orientation variations depending on stru
armer aquifer below the producing zone (water coning). In contrast produced water can be cooler than produced oil because of differences in
onesia. Using the geomechanical model first a fault seal analysis was performed and indicated that all faults were sealed in sands under init
This is different from Monte Carlo (MC) -based geostatistical inversion techniques where conditioning on dynamic data is performed for one
ection. This observation proposes that local pressure drops created by vugs are more dominant in determining the wormhole flow path than t
y the dependence of trapped (residual) hydrocarbon saturation and waterflood relative permeability on several fluid/rock properties most not
n (Zuluaga and Monsalve 2003). These experiments were performed by injecting dry methane into core samples that contained immobile wa
Most of these wells lie on seismic-scale faults mapped in the reservoir. Some wells show fractured-reservoir production characteristics and r
great economic impact. In information management and decision-making the mondegreen “data commute is the biggest problem area.
allenges were addressed and how the Company plans to address even more demanding challenges in the future.
rofiles in addition to temperature and pressure conditions.� In particular a realistic water production profile during field life is needed to fr
able data.�The results highlight the crucial role played by the filter cake and present new data that would significantly change the commo
dvances in openhole-drilling techniques that eliminate hole tortuosity gravel-pack fluids that can reduce rig time and enhance well productiv
IPR estimation has been emerging as an important issue in the petroleum industry.11 The correlations become more and more complicated
the planning implementation of an early 4D program for the Enfield water-flood and history matching process. Pre-development feasibility w
a detailed uncertainty analysis with experimental design. Variables included in this analysis were perforation-to-gauge distance permeability
able PL tool selection poorly executed surveys inappropriate interpretation etc. With the existence of two or three phase flow in a well the
e model is then used to compute the flow profile based on measured DTS data across the producing intervals. The model rigorously account
s inappropriate interpretation etc. In the presence of multiphase flow in a well interpretation of production logs becomes critical for achievi
ble PL tool selection poorly executed surveys inappropriate interpretation etc. With the existence of two or three phase flow in a well the in
approach called the Segmentation Method.� These four methods were developed for accurate and reliable identification of break points us
is uncertainty comprehensive wireline formation pressure programs have been run to assess hydrocarbon gradients but because sands are
pment needed to use C/O techniques especially the focused tool optimally in either monitor or producer wells in diatomite. Introduction The
ed primarily to effective waterflood management with a methodical approach employing an integrated multifunctional team. Although the su
n) elimination of repetitive data gathering and reformatting tasks consistency and repeatability of evaluation and better knowledge manage
of the injected gas composition. As the concentration of CO2 in the injection gas increases the permeability of the coal decreases. Pure CO2
nate) wells. In these configurations the total length of horizontal wells and the spacing between laterals (SBL) have been studied. It was dete
to flow to surface. Artificial lift (gas lift) has been identified as the best method to optimize production from the wells reviewed in this case. Ho
gn (ED) reduced the large number of simulation runs to a manageable few for probabilistic forecasting. Comparison of three options sugges
zing state-of-the-art 3D seismic interpretation LWD resistivity at bit real-time imaging and distance to boundary measurements to place this
bution and selective completion with blank pipes. Both oil well and gas wells are evaluated. For gas wells the standard pseudo-functions ar
g pressure Pfrict = friction pressure Phyd = hydrostatic pressure The equation shows that an increase in hydrostatic pressure results in a re
t. For each category the authors describe the significance of non-Darcy and multiphase flow effects by use of the fracture-flow theory and st
e fracture. The new results presented here demonstrate successful strategies that mitigate the effects of excessive filter cake thickness. Exp
uth length and symmetry with respect to rock properties. Hydraulic fracture stimulations to date at SR have encompassed limited entry “
s can be impaired by the formation of a condensate bank once the bottomhole pressure drops below the dewpoint. This paper outlines the fiv
he high-velocity coefficient in two-phase flow is investigated. Results show that when the liquid is strongly wetting the high-velocity coefficien
successfully been applied for investigating key thermal characteristics of single-phase- and multiphase-fluid flow along a wellbore. In particu
nd maximize financial returns. In this study a strategy was developed to maximize Agbami’s full-field rate capacity in three production p
performed. The analysis indicates that the well’s productivity had been substantially reduced. Before shut-in the surface pipeline system
sing separation equipment. As the production of the well continues the reservoir pressure drops to the point where water can no longer be l
ning the dynamic model with field test data. An example is given to illustrate the dynamic performance of plunger lift and the optimal design.
vity growth for general field applications. This paper introduces results from a fully-coupled geomechanical/reservoir simulator GMRS� wh
aintaining stringent health safety and environmental standards was proposed. The propellant-assisted perforating method uses standard per
a horizontal well planned to have the lateral section slimmed down to 6 in. hole. After successfully drilling the hole to target depth (TD) a 6-in
d subsea-development options were evaluated. The compliant-tower alternative was selected because of its greater well-intervention capabil
nputs including depth profiles for unconfined compressive strength (UCS) and in-situ stresses which involve sophisticated prediction techni
he near-wellbore zones of drilling damage mud-cake gravel packs and the sand screen. This investigation indicates that the non-Darcy eff
ompletion interval. In the event of proppant production to surface (mechanical failure) the surface samples would be analyzed to directly det
ess completion. In this paper the common sequence of events for a screenless completion is presented as well as the key technologies inv
e effectiveness of the completions in the Duri field. This effort involved evaluated field data such as the frequency and type of workovers th
his paper demonstrates the diverting ability of the acid as a function of permeability characterized by introducing the concept of maximum p
ost-job production logs clearly show a change in the production profile after the stimulation with the viscoelastic diverting acid system with a
¿½F). Spectroscopic data show that the sandstone surface remains modified by the chemical even after flooding the core with large volume
s—with carbon dioxide advantages of enhanced cleanup and better hydrostatic pressure. This fluid was recently selected for the fracturing
cription. While we briefly discuss all relevant data the focus of this paper is primarily on integrating seismic amplitude response with pressur
erpretation highlights successful development of inflow and tubing performance relationships bubble-point pressure estimation as well as qu
the method with field data is also described. The new method could be applied wherever values of absolute permeability or fluids saturation
ement and recording systems throughout the entire production and process network. This pr
up a new hydrodynamic slug.� This slug moves through the road
ively.�This advantage is even more pronounced in tight gas or
ure depletion. Moreover the lower reservoir pressure increased the f
ss is the formation of sodium hydroxide that reduces the interfacial
he ES-SAGD process are the solvent type concentration operating pressure and the
cesses to the carbonates poses a different challenge. In general therma
a common acid was not an option for this development because of the
Adaptive Neuro Fuzzy Logic Inference System (ANFIS) that combines the
he stress perturbation associated with dynamic rupture propagation.
eling data used to characterize its azimuthal capabili
ray propagation resistivity density neutron porosity and LWD gamma ray
stability hole washouts sanding while testing or lost seals. This pap
siderable heterogeneity in this “hard well data and that distri
ility modeling procedure with application to the Surmont Lease in Nort
coupling system for multiple-reservoir models. Uncertai
percent to 80% to 90% within the first 2 years of production. Typically sidetrac
he steam temperatures or pressures are known during the circulation peri
using Line Successive Over Relaxation (LSOR). The second stage preconditi
tions. In this work we show that this physical information
cs effects. These results indicate that the geomechanics-coupled compositional reservoi
e presented in this paper to demonstrate how implementing the optimizer’s recomm
ulting in fine-grid models consisting of 107 to 108 gridbloc
nthetic data generated by the forward model (i.e. the inversion model). It is conclu
ubes were placed at different depths in the model to serve as gas inject
h may not have an influence on oil recovery as long as there is vertical commun
d the formation of stable wetting phase bridges. The combination of high sp
ties but differ in several key areas including government policy. This paper examines
However there are significant challenges and hurdles to overcome before that happens.
etic data generated by the forward model (i.e. the inversion model) in the previous
of p/z material balance to calculate original-gas-in-place. �As with the Agar
l model is expanded to incorporate multi-component adsorption models that are more
seudotime and pseudopressure definitions) to analyze producing wells completed in
parameters that control reserves deliverability and value and; stage
been adapted by incorporating some CBM reservoir properties.� For examp
ent reservoir units. In the high productivity Fairway well data monitored and gath
a slight (but substantive) modification to material balance time and apply
the case outlined above but with the individual units tending to be lent
ross validation and with more than 100 new wells drilled during the last two
lifting costs. Introduction Kuparuk Field (Fig.1) is the second largest oil field lo
uture improvement. Background Surmont an in-situ oil sands pro
pre-drilled liners and openhole packers were selected instead of the conv
predictability. Future plans include continuing to stimulate candidate well
e performance of the wells in most assets dropped st
bstitute to fracturing down casing and subsequent snubbing operations. Three t
cations. Focus areas in this evaluation include in-situ reservoi
ring community has determined certain containment mecha
depth of penetration of acid as a function of the acid v
ely. The 6-1/2 in. drift diameter allows using common size screen
st be meshed as shown in Fig.2 requiring 100-500 meshes aro
ompletion using conventional perforations or s
completions. Using appropriate variable transformations
fracture stimulations. Chemical and mechanica
provements in the gas relative permeability by a factor of about 2 were
ient analysis. The proposed cooling time and formation thermal diffusivit
udy indicate that for both water-wet and mixed-wet rocks T 2 (transverse relaxa
to a reservoir model.� A reservoir model recently built using A
ically depositional facies are simulated first using MPS then
to the condensate relative permeability and this simplifies the measurements and model
nd newly acquired DFA log data matched for the first produc
as observed from the low- to high-capillary-number flow regim
eabilities following significant volumes of high temperature fluid inje
perhaps hydraulic action during forced imbibition form the channels. Silica diss
w uncertainties in volumetrics and capital and operating
used on dynamic uncertainties. The results of the workflow defined the P10 P50 a
ing the confidence in the model selection. Finally the polynomial
ntly. Two field examples are presented to demonstrate t
iple surface/subsurface simulators. One real field case that requires advance/compl
ated in California’s San Joaquin Valley is presented in order to highl
n additional 20 000 bbl/day of water is expected from new projects and artifici
pay zone during completions were applied to maximize res
d in the El Trapial field in order to improve the unde
erpretations to be examined. Based on the standard deviation or range of the
post-treatment cumulative oil production of the well one month after treat
es rather than infrastructure considerations which may favor a mo
its variants which are however extremely inefficient. All ot
such that gradients can be calculated on the approximate problem and gradi
e response to define reservoir specific relationships between injection and pre
is achieved with field data and with the predictions of a semimechanisti
weighted objective function tended to reduce the highest errors first. Resu
ork we apply a new parameterization referred to as a kernel
his probabilistic perturbation is that the expectation of the search dir
we describe a Statistical Moment Equations (SME) framework for both th
duction/injection data we use an optimization technique to maximize
rectly during the course of error minimization. Because
alistic field-scale projects where a salinity gradient exis
c steam injection case with other commercial simulators. We also demonstrate the p
With this general formulation approach we can model most reservoir physics with a
me cases changes in seismic attributes over time can be detected and related to re
design parameters using Experimental Design and (3) su
emperature and density profiles in the wellbore. Surrounding formation temp
ted to reserves estimation and future well/reservoir
s to discrete fractures and wells while incorporati
locks these functions are estimated statistically on the basis
the closest neighboring cells. Here we extend the ideas for discretizati
the Corey equation are solved simultaneously.� A number of it
d the CPU requirement of the SPU scheme was found to be more than 50 times lar
lls confidence in analysis. We also show that the traditional l
ng and pattern waterflood.� This paper however focuses on PM
analytical solution given in this paper and those
n rates.� With our approach we first
els. The production profiles for each well are represen
or efficient decision support systems that enable the in
nsate and water production profiles predicted by a material balance model. I
straight-line p/z plot in waterdrive gas reservoirs. The authors
ame production history. The results of this study showed that subsequent we
r path inequality constraints efficiently and accurately unlike any exist
procedure to build 3D reservoir models that are only conditioned to
the block. The subregions thus account for the fracture distributi
n that the MSR method provides results of reasonable accuracy
stable borehole. However it is also found that a formation is more
mplified the neural network improved its effectiveness
strategy for the estimated IPR values is developed in terms of “pr
predictions with an uncertainty range similar to the one obtained with RML. In
atical proof of why different wells in a multiwell res
influence operating constraints.� Examples within the paper illustrate methods to determine a
certainties which would lead to multiple production forecasts
mobility of heavy-oil.� Traditional Proportional
some inconsistency between the static and dynamic parameters at the previous
avior. Our results show that as expected different geologic factors influence diff
icks.�Three dimensional streamline simulation was used to demonstra
al development options for fifteen reservoirs situated in four different
ch are associated with the primal coarse grid
ctive properties: applicability within a variety o
n the model is unconfined (i.e. the model area is greater th
onstruction relies on a correspondence between the MPFA fluxes an
mlines. A density-dependent source term in the saturation eq
to GTTI. Further we generalize the approach to incorporate bottom-
application of global optimization methods. This work involves appl
rical simulation study was conducted to determine the range of OGI
f the adaptive local-global upscaling technique is evaluated for
orous media with heterogeneous permeabilities. It is demonstrated that th
. We observed that the derivative of modified-Hall integral obtained ana
However the main advantage of the simplified model is that its recalibration with fiel
amplitude by half and flattening the heel-end entrance angle from 79 d
present simple thermodynamically sound approaches for estimating t
T properties minimizes uncertainty from this important source. Statistical a
entation variations depending on structure complexity near a spe
produced oil because of differences in the thermal properties of these fluids.
aults were sealed in sands under initial stress and pore pre
n dynamic data is performed for one realization of the permeability
mining the wormhole flow path than the chemical reactions occurring at the pore level. Fol
everal fluid/rock properties most notably the wettability and the in
samples that contained immobile water to represent water vaporiz
rvoir production characteristics and rate-transient analysis
ommute is the biggest problem area. The data commute absorbs over half the time
profile during field life is needed to frame a workable hydrate management strategy.
ould significantly change the common industry pra
rig time and enhance well productivity and improvements in downhole tools tha
become more and more complicated and rigorous in order to accurately describe
rocess. Pre-development feasibility work indicated that Enfield had rock
ation-to-gauge distance permeability geothermal gradient flow rate fluid viscosity t
wo or three phase flow in a well the interpretation of produ
ervals. The model rigorously accounts for various thermal prope
tion logs becomes critical for achieving successful estimate
wo or three phase flow in a well the interpretation of produc
liable identification of break points using both pressure and rate data. The new methods
bon gradients but because sands are thin and permeabilities are
r wells in diatomite. Introduction The Belridge Diatomite in
multifunctional team. Although the suggested techniqu
ation and better knowledge management. Developed in San Jo
ility of the coal decreases. Pure CO2 leads to the greatest permea
SBL) have been studied. It was determined that in t
m the wells reviewed in this case. However the in
Comparison of three options suggested that all of them nearly produced
boundary measurements to place this first MRC w
lls the standard pseudo-functions are used. Detailed discussion
n hydrostatic pressure results in a reduction in surface pressure. Th
use of the fracture-flow theory and state-of-the-art fracture-production
f excessive filter cake thickness. Experimental dat
have encompassed limited entry “waterfrac treatment techniques. The
dewpoint. This paper outlines the five steps—appropriate l
ly wetting the high-velocity coefficient increases
-fluid flow along a wellbore. In particular the dependence
ld rate capacity in three production phases; ramp-up pl
e shut-in the surface pipeline system induced unstable production
point where water can no longer be lifted to the surface by gas flow. Th
f plunger lift and the optimal design. The principle and approach
al/reservoir simulator GMRS� which predicts cavity geome
erforating method uses standard perforating components and procedures thus
g the hole to target depth (TD) a 6-in. h
of its greater well-intervention capability less-complex seawater-injection-system desi
nvolve sophisticated prediction techniques themselves. Continuous sand rate
ation indicates that the non-Darcy effect could significantly affect the product
les would be analyzed to directly determine which interval had fai
d as well as the key technologies involved from perforating to p
frequency and type of workovers the amount and size of produc
roducing the concept of maximum pressure ratio (dP max /dP 0
oelastic diverting acid system with a significant increase i
r flooding the core with large volumes of gas. A relative permeability model
s recently selected for the fracturing treatments on three wells. Initial prod
mic amplitude response with pressure transient
int pressure estimation as well as quantification o
olute permeability or fluids saturations are used in predicting we