Tight oil reservoirs : characterization, modeling, and field development /

Mostrar otras versiones (1)
Detalles Bibliográficos
Clasificación:Libro Electrónico
Autor principal: Belhaj, Hadi
Formato: Electrónico eBook
Idioma:Inglés
Publicado: Cambridge, MA : Gulf Professional Publishing, an imprint of Elsevier, [2023]
Colección:Unconventional reservoir engineering series
Temas:
Oil reservoir engineering.
Étude des gisements pétrolifères.
Oil reservoir engineering
Acceso en línea:Texto completo
Tabla de Contenidos:
  • Intro
  • Tight Oil Reservoirs: Characterization, Modeling, and Field Development
  • Copyright
  • Dedication
  • Contents
  • About the author
  • Preface
  • Acknowledgment
  • Chapter 1: Introduction
  • References
  • Chapter 2: Classification of unconventional reservoirs
  • 2.1. Reservoir classification strategy
  • 2.2. Classification of petroleum systems
  • 2.2.1. Classification of conventional petroleum reservoirs
  • 2.2.1.1. Classification on the basis of storage and flow characteristics of the reservoir
  • 2.2.1.2. Classification on the basis of reservoir geometry
  • 2.2.2. Classification of unconventional petroleum reservoirs
  • 2.2.2.1. Tight oil reservoirs
  • 2.2.2.2. Tight gas reservoirs
  • 2.2.2.3. Deep and ultra-deep gas reservoirs
  • 2.2.2.4. Shale gas reservoirs
  • 2.2.2.5. Gas hydrate reservoirs (GHRs)
  • 2.2.2.6. Heavy and extra heavy oil reservoirs
  • 2.2.2.7. Coalbed methane (CBM) reservoirs
  • 2.3. What makes reservoirs unconventional
  • 2.4. Classification of tight unconventional reservoirs
  • References
  • Chapter 3: Geology of tight unconventional oil reservoirs
  • 3.1. Petroleum geology of tight unconventional reservoirs
  • 3.1.1. Geological generation of unconventional hydrocarbon resources
  • 3.1.2. Sedimentation environment of tight UCRs
  • 3.2. Geological aspects of shale and tight plays
  • 3.3. Source and near-source rock-type unconventional reservoirs
  • References
  • Chapter 4: Formation evaluation of tight unconventional reservoirs
  • 4.1. Tight unconventional reservoir production background
  • 4.2. Formation evaluation: Conventional versus unconventional reservoirs
  • 4.3. Formation evaluation of conventional reservoirs
  • 4.4. Formation evaluation of unconventional reservoirs
  • 4.4.1. Unconventional reservoir concept
  • 4.4.2. Importance of unconventional reservoirs.
  • 4.4.3. Challenges in formation evaluation of unconventional reservoirs
  • 4.4.4. Typical tight UCR formation evaluation steps
  • 4.4.5. Assessing tight unconventional reservoirs
  • 4.4.6. Hydrocarbon-in-place assessment
  • 4.4.7. Reservoir performance assessment
  • 4.5. Assessment case study # 1
  • 4.6. Assessment case study # 2
  • 4.7. Data source and valuation
  • 4.7.1. Petrophysical assessment
  • 4.7.1.1. Lithology
  • 4.7.1.2. Bulk density
  • 4.7.1.3. Porosity
  • 4.7.1.4. Permeability
  • 4.7.1.5. Resistivity
  • 4.7.1.6. Water saturation
  • 4.7.2. Geochemical assessment
  • 4.7.2.1. Vitrinite reflectance
  • 4.7.2.2. Types and maturity of the organic matter
  • 4.7.2.3. Total organic carbon (TOC)
  • 4.7.2.4. Mineral content
  • 4.7.2.5. Gas content
  • 4.7.3. Geomechanical evaluation
  • 4.7.3.1. Poisson's ratio
  • 4.7.4. Shear modulus
  • 4.7.4.1. Young's modulus
  • 4.7.4.2. Stress intensity factor
  • 4.7.4.3. Formation stress
  • 4.8. Role of macro-, micro-, and nanoscale assessment of tight unconventional reservoirs
  • 4.8.1. Mercury intrusion capillary pressure (MICP)
  • 4.8.1.1. Example of the use of MICP
  • 4.8.2. Gas adsorption method
  • 4.8.2.1. Example of the gas adsorption
  • 4.8.3. Scanning electron microscopy (SEM)
  • 4.9. Static modeling role in formation evaluation of unconventional reservoirs
  • 4.9.1. Reservoir-scale model
  • 4.9.2. Basin-scale model
  • 4.9.2.1. Case study
  • 4.9.3. Burial history model
  • 4.10. Hydrocarbon enrichment spot identification
  • References
  • Chapter 5: Reservoir characterization of tight unconventional reservoirs
  • 5.1. Reservoir description
  • 5.1.1. Conventional reservoir description
  • 5.1.2. Differences between conventional and unconventional reservoirs
  • 5.1.3. Source-reservoir characteristics
  • 5.1.4. Migration and accumulation characteristics
  • 5.1.5. Reservoir characteristics.
  • 5.1.6. Distribution characteristics
  • 5.1.7. Flow characteristics
  • 5.1.8. Significance of tight unconventional reservoir description
  • 5.1.9. Complications/remedies of unconventional reservoir description
  • 5.2. Macro-/micro-/nanoscale role in tight unconventional reservoir characterization
  • 5.2.1. Scale definition
  • 5.2.2. Significance of nanoscale
  • 5.2.3. Interrelations of reservoir scales
  • 5.3. Flow mechanisms of shale nanochannels
  • 5.3.1. Problem definition
  • 5.3.2. Nanoscale flow
  • 5.3.3. Nanoscale debate
  • 5.3.3.1. Slip flow
  • 5.3.3.2. Adsorption
  • 5.3.3.3. Inorganic and organic matter
  • 5.3.4. Summary of nanoscale
  • 5.4. Tight unconventional reservoir transition zone description
  • 5.4.1. Tools for determining transition zone
  • 5.4.1.1. Scanning electron microscope (SEM)
  • 5.4.1.2. Mercury injection capillary pressure (MICP)
  • 5.4.1.3. Reservoir rock typing (RRT)
  • 5.4.1.4. Special core analysis (SCAL)
  • 5.4.1.5. Conventional core analysis (CCA)
  • 5.4.2. Significance of transition zone investigation
  • 5.4.3. Factors affecting transition zone characteristics
  • 5.4.3.1. Static and dynamic reservoir rock typing
  • 5.4.3.2. Petrophysical analysis and diagenesis
  • 5.4.3.3. Hysteresis capillary pressure and relative permeability behaviors
  • 5.4.3.4. Wettability envelope
  • 5.4.3.5. Electrical resistivity and saturation exponent
  • 5.5. Role of CT/XRD/NMR/SEM
  • 5.5.1. CT
  • 5.5.2. XRD
  • 5.5.3. NMR
  • 5.5.4. SEM
  • 5.6. Tight unconventional reservoir data integration
  • 5.6.1. Well logging data
  • 5.6.2. Core analysis data
  • 5.6.3. Well testing data
  • 5.7. Ordos basin, Northcentral China case study
  • 5.7.1. Static and dynamic modeling
  • 5.7.2. Research on the Ordos Basin, Northcentral China
  • References
  • Chapter 6: Dynamic modeling of tight unconventional reservoirs.
  • 6.1. Main differences between conventional and tight unconventional reservoirs flow modeling
  • 6.2. Dynamic/static model projection
  • 6.3. Mechanisms controlling fluid flow through tight UCRs
  • 6.3.1. Non-Darcy flow mechanism
  • 6.3.2. The eight governing flow mechanisms in tight UCR porous media
  • 6.3.2.1. Viscous forces
  • 6.3.2.2. Inertial forces
  • 6.3.2.3. Capillary forces
  • 6.3.2.4. Diffusion forces
  • 6.3.2.5. Sorption forces
  • 6.3.2.6. Desorption forces
  • 6.3.2.7. Advection forces
  • 6.3.2.8. Viscoelastic forces
  • 6.4. Dynamic model development
  • 6.4.1. Modified Buckingham-Reiner equation
  • 6.4.2. Model related to slip boundary conditions
  • 6.4.3. Enskog equation
  • 6.4.4. Model considering the viscous and diffusion
  • 6.4.5. Physical implications of the eight mechanisms
  • 6.4.5.1. Viscous forces
  • 6.4.5.2. Diffusion forces
  • 6.4.5.3. Sorption forces
  • 6.4.5.4. Desorption forces
  • 6.4.5.5. Inertial forces
  • 6.4.5.6. Advection forces
  • 6.4.5.7. Capillary forces
  • 6.4.5.8. Viscoelastic forces
  • 6.4.6. Mathematical expression of eight mechanisms
  • 6.4.6.1. Viscous force
  • 6.4.6.2. Diffusion force
  • 6.4.6.3. Sorption forces
  • 6.4.6.4. Desorption forces
  • 6.4.6.5. Advection forces
  • 6.4.6.6. Inertial forces
  • 6.4.6.7. Capillary forces
  • 6.4.6.8. Viscoelastic forces
  • 6.4.7. Model development sample
  • 6.5. Dynamic model validation
  • 6.5.1. Parametric validation
  • 6.5.2. Experimental data validation
  • 6.5.3. Field data validation
  • 6.6. Mathematical expressions
  • 6.6.1. Combination of viscous flow and Knudsen diffusion
  • 6.6.2. Adsorption and desorption
  • 6.6.3. Diffusion
  • References
  • Chapter 7: Field development of tight unconventional reservoirs
  • 7.1. Tight unconventional reservoirs development criteria
  • 7.1.1. Total organic carbon (TOC)
  • 7.1.2. Kerogen type and thermal maturity.
  • 7.1.3. Storage mechanism
  • 7.1.4. Mineralogy
  • 7.1.5. Hydrocarbon-in-place
  • 7.1.6. Reservoir formation thickness
  • 7.1.7. Reservoir fluids saturation, distribution, and fluid contact (egg-box-stack theory)
  • 7.1.8. Reservoir pressure
  • 7.1.9. Reservoir rock brittleness and fractures
  • 7.1.10. Stimulation conditions
  • 7.2. Current practice
  • 7.2.1. Identifying the hydrocarbon enrichment spots (HES)
  • 7.2.2. Tight unconventional reservoir well development
  • 7.2.3. Well spacing
  • 7.2.4. Pad development
  • 7.3. Horizontal drilling and hydraulic fracturing challenges
  • 7.3.1. Horizontal wells
  • 7.3.2. Fracturing tight unconventional reservoirs
  • 7.3.3. Fracturing fluids
  • 7.4. Tight unconventional reservoir production profile
  • 7.4.1. Nature of production profiles
  • 7.5. Production profile comparison of conventional and tight unconventional reservoirs
  • 7.6. Advancement in hydraulic fracturing technologies
  • 7.6.1. Development of hydraulic fracturing
  • 7.6.2. Fracturing fluids
  • 7.6.3. Proppants
  • 7.6.4. Pumping and blending equipment
  • 7.6.5. Fracture treatment design
  • 7.7. Refracturing
  • 7.8. Advancements in slim wells
  • 7.9. EOR for tight unconventional reservoirs
  • 7.9.1. Gas injection
  • 7.9.1.1. Traditional gas injection
  • 7.9.1.2. Gas injection huff-n-buff
  • 7.9.2. Water injection
  • 7.9.2.1. Continuous water injection
  • 7.9.2.2. Water injection huff-n-buff
  • 7.9.3. Surfactant injection
  • 7.9.4. Other potential EOR techniques
  • 7.10. Case studies
  • 7.10.1. Wattenberg field case study
  • 7.10.2. Eagle ford case study
  • References
  • Chapter 8: Economics and risk analysis of tight oil unconventional reservoirs
  • 8.1. Background
  • 8.2. Economic and risk analysis of conventional reservoirs
  • 8.2.1. Economic analysis
  • 8.2.2. Net cash flow
  • 8.2.3. Revenue estimation
  • 8.2.4. Taxes and royalties.

Ejemplares similares