Gas Injection Methods

Front Cover
Gas Injection Methods
Copyright Page
Contents
List of contributors
Preface
1 Introduction to gas flooding technique: fundamentals and applications
1.1 Overview
1.1.1 Miscible flooding
1.1.1.1 Miscible slug process
1.1.1.2 Enriched gas drive
1.1.1.3 Vaporizing gas drive
1.1.1.4 CO2 miscible
1.1.1.5 N2 miscible
1.2 Gas injection methods
1.2.1 Continuous flooding
1.2.2 Water-alternating-gas technique
1.2.3 The huff-n-puff method
1.3 Gas types
1.3.1 Gas condensate
1.3.2 Wet gas
1.3.3 Dry gas
1.3.4 Carbon dioxide flooding
1.3.5 Nitrogen flooding
1.3.6 Gravity-assisted gas drainage
1.4 Gas flooding design
1.4.1 Enhanced oil recovery mechanisms of carbon dioxide flooding
1.4.1.1 Reducing interfacial tension
1.4.1.2 Oil swelling and viscosity reduction
1.4.1.3 Effect of dissolved gas drive
1.4.1.4 Variations of formation pressure
1.5 Macroscopic displacement efficiency
1.6 Microscopic displacement efficiency
1.7 Vaporizing and condensing mechanisms
1.8 Screening criteria
1.8.1 Reservoir depth
1.8.2 Temperature
1.8.3 Pressure
1.8.4 Porosity and permeability
1.9 Geological factors
1.10 Reservoir heterogeneity and rock structure
1.11 Fluid characterization
1.11.1 PVT data
1.11.2 Pseudocomponent selection
1.11.3 Validation of lumped EOS models
1.12 Mineralogy
1.12.1 X-ray μ-computed tomography imaging
1.12.2 Scanning electron microscopy
1.12.3 Scanning electron microscopy-energy dispersive X-ray spectra
1.12.4 Image registration
1.13 Economic consideration
1.14 Soft issue evaluation
1.14.1 Regulations
1.14.2 Public opinion
1.14.3 Expiration dates
1.14.4 New technologies
1.14.5 Public information
1.14.6 Cost of imports
1.14.7 Labor
1.15 Environmental considerations
References
2 Cyclic gas injection
2.1 Introduction to cyclic gas injection
2.2 Process definition
2.2.1 Gas injection into the reservoir (huff process)
2.2.2 Waiting time (soaking time)
2.2.3 Production from the well (puff process)
2.3 Recovery mechanisms
2.3.1 Viscosity reduction
2.3.1.1 Oil viscosity determination
2.3.1.2 Viscosity reduction during gas injection
2.3.2 Oil swelling
2.3.2.1 Laboratory determination of oil swelling
2.3.2.2 Oil Swelling in cyclic gas injection
2.3.3 Gas diffusion
2.3.3.1 Laboratory measurement of gas diffusivity
2.3.3.2 Gas diffusion in oil samples
2.3.4 Solution gas drive
2.3.5 Relative permeability hysteresis
2.4 Experimental investigation on huff and puff process
2.4.1 Effects of soaking time
2.4.2 Injection pressure
2.4.3 Number of cycles
2.5 Field application of huff and puff enhanced oil recovery method
2.5.1 Application of cyclic gas injection for conventional oil reservoirs
2.5.2 Application of cyclic gas injection in unconventional reservoirs
2.5.2.1 Experimental study on huff and puff process for shale oils
2.5.2.2 Field applications of cyclic gas injection in unconventional reservoirs
2.6 Limitation and challenges
References
3 Immiscible carbon dioxide injection
3.1 Introduction
3.2 Carbon dioxide sources
3.2.1 Natural carbon dioxide reservoirs
3.2.2 Carbon dioxide impurity contained in natural hydrocarbon gas reservoirs
3.2.3 Industrial sources with various carbon dioxide percentages (flue gas)
3.3 Analytical models for immiscible displacement
3.3.1 Buckley–Leverett model
3.3.2 Shock wave model
3.3.3 Models considering the capillary pressure and gravity effects
3.3.4 Models for heterogeneous systems
3.3.5 Models for complex systems
3.4 Recovery mechanisms of immiscible carbon dioxide Injection
3.5 Limitations and challenges
3.5.1 Asphaltene precipitation
3.5.2 Inorganic scales and fine migration
3.5.3 Gas fingering, channeling, and gravity override
3.6 Carbon dioxide immiscible field experience
3.7 Vapor extraction of heavy oils
References
4 Carbon dioxide miscible flooding
4.1 Minimum miscibility pressure
4.2 Reservoir fluid thermodynamics
4.2.1 Dominating phenomena
4.2.2 Diffusion–dispersion
4.2.3 Advection
4.2.4 Reactions within porous media
4.2.5 Primary and secondary species
4.2.6 Characterization of reactions in the aqueous phase
4.2.7 Characterization of precipitation/dissolution reactions
4.2.8 Characterization of reaction between the gaseous and aqueous phases
4.2.9 Interactions within the nonaqueous phase liquid and other phases
4.2.10 Interphase mass transfer
4.2.11 Liquid–gas interphase mass transfer
4.2.12 Nonaqueous phase liquid-aqueous interphase mass transfer
4.3 Reservoir fluid condition
4.4 First-contact miscibility
4.5 Multiple-contact miscibility
4.6 Using carbon dioxide for shale oil recovery
4.7 Field experience
References
5 Carbon dioxide huff-n-puff
5.1 Introduction
5.2 Stages of huff-n-puff processes
5.2.1 Injection stage (huff stage)
5.2.2 Soaking stage (shut-in stage)
5.2.3 Production stage
5.3 Recovery mechanisms
5.3.1 Miscibility
5.3.2 Reduction of interfacial tension
5.3.3 Molecular diffusion
5.3.4 Vaporization of components
5.3.5 Oil viscosity reduction
5.3.6 Oil swelling
5.3.7 Wettability alteration
5.4 Factors affecting carbon dioxide huff-n-puff
5.4.1 Impact of three-phase relative permeability
5.4.2 Matrix permeability
5.4.3 Injection rate
5.4.4 Slug size
5.4.5 Soaking time
5.5 Mathematical and numerical studies
5.6 Experimental studies
5.7 Screening criteria for carbon dioxide huff-n-puff
5.8 Pilot test studies
5.9 Field cases
5.10 Advantages and disadvantages of carbon dioxide huff-n-puff
5.11 Challenges of carbon dioxide huff-n-puff
5.12 Pre-Darcy flow in carbon dioxide huff-n-puff
References
6 Carbon dioxide injection enhanced oil recovery and carbon storage in shale oil reservoirs
6.1 Introduction
6.2 Enhanced oil reocvery methods in shale oil reservoirs
6.3 Carbon dioxide-enhanced oil recovery in shale reservoirs
6.3.1 Effect of fracture system in carbon dioxide huff-n-puff
6.3.2 Effect of molecular diffusion
6.3.2.1 Empirical correlations of the diffusion coefficient
6.3.2.2 Diffusion in porous media
6.3.2.3 Molecular diffusion in the shale reservoirs
6.3.3 Effect of heterogeneity
6.3.4 Effect of pore confinement
6.3.5 Upscaling carbon dioxide injection in shale reservoirs
6.3.6 Comparison of carbon dioxide and other types of gas injection
6.4 Experimental carbon dioxide studies
6.5 Carbon dioxide-enhanced oil recovery pilot projects
6.6 Field-scale simulations
6.7 Carbon dioxide adsorption and storage potential in shales
6.8 Environmental considerations
6.9 Economic evaluation
References
7 Carbonated water injection
7.1 Introduction
7.2 Carbon dioxide-brine system
7.2.1 Carbon dioxide solubility in brine
7.2.2 Phase behavior
7.2.3 Carbon dioxide-brine system viscosity
7.2.4 Carbon dioxide-brine system density
7.2.5 Diffusion coefficient of carbon dioxide-brine system
7.2.6 Interfacial tension of carbon dioxide-brine system
7.3 Carbonated water–oil system
7.3.1 Interfacial tension of carbonated water–oil system
7.3.2 Partition coefficient of carbon dioxide
7.4 Carbonated water-rock system
7.5 Impact of pertinent parameters during the carbonated water injection process
7.5.1 Carbon dioxide content
7.5.2 Oil properties
7.5.3 Pressure and temperature
7.5.4 Rate of injection
7.5.5 Heterogeneity
7.5.6 Reservoir rock wettability
7.6 Mechanistic investigation of carbonated water injection
7.7 Carbon dioxide storage capacity of carbonated water injection
7.8 Operational challenges associated with carbonated water injection
7.8.1 Carbonated water preparation
7.8.2 Corrosion
7.8.3 Injectivity issues
7.8.4 Water weakening effect
7.9 Key research findings and gaps
7.10 Exercises
References
8 Enhanced oil recovery by water alternating gas injection
8.1 Introduction
8.2 Water alternating gas recovery factor and mechanisms
8.3 Classification of the water alternating gas process
8.3.1 Gas phase
8.3.1.1 Miscible water alternating gas injection
8.3.1.2 Immiscible water alternating gas Injection
8.3.1.3 CO2- water alternating gas
8.3.1.4 Foam assistant water alternating gas injection
8.3.1.5 Water alternating steam process
8.3.2 Liquid phase
8.3.2.1 Low salinity water
8.3.2.2 Polymer alternating gas injection
8.3.3 Simultaneous water alternating gas injection
8.3.4 Hybrid-water alternating gas
8.3.5 Selective simultaneous water alternating gas
8.4 Effects of petrophysical properties on water alternating gas
8.4.1 Reservoir heterogeneity and stratification
8.4.2 Relative permeability
8.4.3 Wettability
8.5 Effects of fluid properties on water alternating gas
8.5.1 Brine salinity
8.5.2 Gas type
8.5.3 Fluids miscibility
8.6 Effects of operational parameters on water alternating gas
8.6.1 Injection pattern
8.6.2 Water alternating gas ratio
8.6.3 Tapering
8.7 Challenges of water alternating gas implementation
8.7.1 Early breakthrough
8.7.2 Reduced injectivity
8.7.3 Corrosion
8.7.4 Scale formation
8.7.5 Hydration and asphlatene formation
8.8 Screening criteria
8.9 Economical aspects
References
9 Carbon dioxide injection in tight oil reservoirs
9.1 Introduction
9.2 Effect of carbon dioxide molecular diffusion
9.3 Comparison of continuous carbon dioxide injection and carbon dioxide huff-n-puff
9.4 Impacts of the various reservoir and fracture properties
9.5 Optimization operational parameters of carbon dioxide enhanced oil recovery in tight reservoirs
9.6 Carbon dioxide flooding coupled with pressure maintenance
9.7 Effect of well-pattern on carbon dioxide flooding
9.7.1 Modeling of well pattern
9.7.2 Impact of well pattern in a carbon dioxide flooding operation
9.7.3 Challenges for the future studies
9.8 Molecular dynamic simulation of carbon dioxide flooding in tight oil reservoirs
9.8.1 Softwares for molecular dynamics simulations
9.8.2 Carbon dioxide-hydrocarbone-rock interaction system
9.8.3 Challenges for the future studies
References
10 Formation damage in gas injection methods
10.1 Introduction
10.2 Probable formation damage mechanisms for CO2 flooding and/or sequestration
10.2.1 Mineral dissolution
10.2.2 Mineral precipitation
10.2.3 Emulsion blockage
10.2.4 Hydrate formation
10.2.5 Corrosion
10.2.5.1 Effect of CO2-induced corrosion on metallurgy
10.2.5.2 Effect of CO2-induced corrosion on cement
10.2.6 Asphaltene precipitation
10.3 Potential formation damage mechanisms for water alternating gas injection
10.4 Challenges of CO2 huff-n-puff operation
10.5 Summary and conclusions
References
11 Application of data mining in gas injection methods
11.1 Introduction
11.2 Modeling minimum miscibility pressure of gas–crude oil
11.3 Modeling solubility of gases in crude oil
11.4 Modeling properties of gases
11.5 Modeling gas–oil relative permeability
11.6 Multiobjective optimization of water alternating gas flooding
11.7 Proxy model for gas injection
References
12 Field case studies of gas injection methods
12.1 Field case studies of carbon dioxide injection
12.1.1 Carbon dioxide injection in Chattanooga shale formation in Morgan County, Tennessee
12.1.2 Carbon dioxide injection in East Vacuum Grayburg San Andres Unit
12.1.3 Trinidad’s carbon dioxide immiscible pilot project
12.1.4 Yaoyingtai oil field pilot carbon dioxide flooding
12.2 Field case studies of nitrogen injection
12.2.1 Nitrogen injection in Jay little Escambia Creek field
12.2.2 Nitrogen injection in the Cantarell complex
12.3 Field case studies of lean gas injection
12.3.1 Lean gas injection in Handil field
12.3.2 Pilot miscible and immiscible gas injection in offshore Abu Dhabi carbonate field
12.3.3 Gas recycling in field D, Balingian province offshore western Sarawak
12.3.4 Pilot gas injection in Iwafune-Oki oil field reservoir
12.4 Field case studies of enriched gas injection
12.4.1 Miscible gas injection in South Brae field, UK North Sea field
12.4.2 Huff and puff miscible gas injection in the Eagle Ford
12.5 Field case studies of carbonated water injection
12.5.1 Carbonated water injection in Dewey-Bartlesville field in Northeastern Oklahoma
12.5.2 Carbonated water injection in Domes unit/west of Bartlesville
12.6 Field case studies of water alternating gas injection
12.6.1 Water alternating gas injection in Statfjord field
12.6.2 Water alternating gas injection in Gullfaks field
12.6.3 Water alternating gas injection in Ekofisk field
References
Index
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