Acid Gas Extraction for Disposal and Related Topics

 
 
Wiley-Scrivener (Verlag)
  • erschienen am 22. Januar 2016
  • |
  • 400 Seiten
 
E-Book | PDF mit Adobe DRM | Systemvoraussetzungen
978-1-118-93863-8 (ISBN)
 
This is the fifth volume in a series of books focusing on natural gas engineering, focusing on the extraction and disposal of acid gas. This volume includes information for both upstream and downstream operations, including chapters on modeling, carbon capture, chemical and thermodynamic models, and much more.
Written by some of the most well-known and respected chemical and process engineers working with natural gas today, the chapters in this important volume represent the most cutting-edge and state-of-the-art processes and operations being used in the field. Not available anywhere else, this volume is a must-have for any chemical engineer, chemist, or process engineer working with natural gas.
There are updates of new technologies in other related areas of natural gas, in addition to the extraction and disposal of acid gas, including testing, reservoir simulations, acid gas injection, and natural gas hydrate formations. Advances in Natural Gas Engineering is an ongoing series of books meant to form the basis for the working library of any engineer working in natural gas today. Every volume is a must-have for any engineer or library.
1. Auflage
  • Englisch
  • Hoboken
  • |
  • USA
  • Für Beruf und Forschung
  • 8,51 MB
978-1-118-93863-8 (9781118938638)
1118938631 (1118938631)
weitere Ausgaben werden ermittelt
  • Cover
  • Title Page
  • Copyright Page
  • Contents
  • Preface
  • 1 Rate-Base Simulations of Absorption Processes
  • Fata Morgana or Panacea?
  • 1.1 Introduction
  • 1.2 Procede Process Simulator (PPS)
  • 1.3 Mass Transfer Fundamentals
  • 1.4 CO2 Capture Case
  • 1.5 Conclusions and Recommendations
  • References
  • 2 Modelling in Acid Gas Removal Processes
  • 2.1 Introduction
  • 2.2 Vapour-Liquid Equilibria
  • 2.3 Modelling
  • 2.3.1 Empirical Models
  • 2.3.2 Activity Coefficient Models
  • 2.3.3 Two (and more) Solvent Models
  • 2.3.4 Single Solvent Models
  • 2.3.5 Equation of State Models
  • 2.4 Conclusions
  • References
  • 3 Thermodynamic Approach of CO2 Capture, Combination of Experimental Study and Modeling
  • 3.1 Introduction
  • 3.2 Thermodynamic Model
  • 3.3 Carbon Dioxide Absorption in Aqueous Solutions of Alkanolamines
  • 3.4 Conclusion
  • References
  • 4 Employing Simulation Software for Optimized Carbon Capture Process
  • 4.1 Introduction
  • 4.2 Acid Gas Cleaning - Process and Business Goals
  • 4.3 Modeling Gas Treating in Aspen HYSYS®
  • 4.3.1 Inbuilt Thermodynamics
  • 4.3.2 Rate-Based Distillation in Aspen HYSYS
  • 4.4 Conclusion
  • References
  • 5 Expectations from Simulation
  • 5.1 Introduction
  • 5.2 Realism
  • 5.2.1 Conclusion 1
  • 5.2.2 Conclusion 2
  • 5.2.3 Conclusion 3
  • 5.2.4 Conclusion 4
  • 5.3 Reliability of Simulation Data: What's Data and What's Not
  • 5.3.1 Conclusion 5
  • 5.3.2 Conclusion 6
  • 5.3.3 Conclusion 7
  • 5.3.4 Conclusion 8
  • 5.4 Case Studies
  • 5.4.1 Hellenic Petroleum Refinery Revamp
  • 5.4.2 Treating a Refinery Fuel Gas
  • 5.4.3 Carbon Dioxide Removal in an LNG Unit
  • 5.4.4 Tail Gas Treating
  • 5.5 Concluding Remarks
  • References
  • 6 Calorimetry in Aqueous Solutions of Demixing Amines for Processes in CO2 Capture
  • 6.1 Introduction
  • 6.2 Chemicals
  • 6.3 Liquid-Liquid Phase Equilibrium
  • 6.4 Mixing Enthalpies of {Water-Amine} and {Water-Amine-CO2}
  • 6.4.1 Excess Enthalpies
  • 6.4.2 Enthalpies of Solution
  • 6.5 Acknowledgements
  • References
  • 7 Speciation in Liquid-Liquid Phase-Separating Solutions of Aqueous Amines for Carbon Capture Applications by Raman Spectroscopy
  • 7.1 Introduction
  • 7.2 Experimental
  • 7.2.1 Materials
  • 7.2.2 Sample Preparation
  • 7.2.3 Raman Spectroscopic Measurements
  • 7.2.4 Methodology Validation
  • 7.2.5 Laser Selection Optimization
  • 7.3 Results and Discussion
  • 7.3.1 Ammonium Carbamate System
  • 7.3.2 Methylpiperidine Band Identification
  • 7.3.3 (N-methylpiperidine + Water + CO2) System
  • 7.3.4 (2-methylpiperidine + Water + CO2) System
  • 7.3.5 (4-methylpiperidine + Water + CO2) System
  • 7.4 Conclusions
  • 7.5 Acknowledgements
  • References
  • 8 A Simple Model for the Calculation of Electrolyte Mixture Viscosities
  • 8.1 Introduction
  • 8.2 The Expanded Fluid Viscosity Model
  • 8.3 Results and Discussion
  • 8.3.1 EF Model for Salts Neglecting Dissociation
  • 8.3.2 EF Model for Ionic Species
  • 8.4 Conclusions
  • References
  • 9 Phase Equilibria Investigations of Acid Gas Hydrates: Experiments and Modelling
  • 9.1 Introduction
  • 9.2 Experimental Methods
  • 9.3 Results and Discussion
  • 9.4 Conclusions
  • 9.5 Acknowledgements
  • References
  • 10 Thermophysical Properties, Hydrate and Phase Behaviour Modelling in Acid Gas-Rich Systems
  • 10.1 Introduction
  • 10.2 Experimental Setups and Procedures
  • 10.2.1 Saturation and Dew Pressure Measurements and Procedures
  • 10.2.2 Hydrate Dissociation Measurements and Procedures
  • 10.2.3 Water Content Measurements and Procedures
  • 10.2.4 Viscosity and Density Measurements and Procedures
  • 10.2.5 Frost Point Measurements and Procedures
  • 10.2.6 Materials
  • 10.3 Thermodynamic and Viscosity Modelling
  • 10.3.1 Fluid and Hydrate Phase Equilibria Model
  • 10.4 Results and Discussions
  • 10.5 Conclusions
  • 10.6 Acknowledgements
  • References
  • 11 "Self-Preservation" of Methane Hydrate in Pure Water and (Water + Diesel Oil + Surfactant) Dispersed Systems
  • 11.1 Introduction
  • 11.2 Experiments
  • 11.2.1 Material
  • 11.2.2 Apparatus
  • 11.2.3 Experimental Procedure
  • 11.3 Results and Discussion
  • 11.3.1 Self-Preservation Effect without Surfactant in Low Water Cut Oil-Water Systems
  • 11.3.2 Self-Preservation Effect without Surfactant in High Water Cut Oil-Water Systems
  • 11.3.3 The Effect of Different Surfactants on Self-Preservation Effect in Different Water Cut Oil-Water Systems
  • 11.4 Conclusions
  • 11.5 Acknowledgement
  • References
  • 12 The Development of Integrated Multiphase Flash Systems
  • 12.1 Introduction
  • 12.2 Algorithmic Challenges
  • 12.3 Physical-Chemical Challenges
  • 12.4 Why Solids?
  • 12.5 Equation of State Modifications
  • 12.6 Complex Liquid-Liquid Phase Behaviour
  • 12.7 Hydrate Calculations
  • 12.7 Conclusions and Future Work
  • References
  • 13 Reliable PVT Calculations - Can Cubics Do It?
  • 13.1 Introduction
  • 13.2 Two Parameter Equations of State
  • 13.3 Two Parameter Cubic Equations of State Using Volume Translation
  • 13.4 Three Parameter Cubic Equations of State
  • 13.5 Four Parameter Cubic Equations of State
  • 13.6 Conclusions and Recommendations
  • References
  • 14 Vapor-Liquid Equilibria Predictions of Carbon Dioxide + Hydrogen Sulfide Mixtures using the CPA, SRK, PR, SAFT, and PC-SAFT Equations of State
  • 14.1 Introduction
  • 14.2 Results and Discussion
  • 14.3 Conclusions
  • 14.4 Acknowledgements
  • References
  • 15 Capacity Control Considerations for Acid Gas Injection Systems
  • 15.1 Introduction
  • 15.2 Requirement for Capacity Control
  • 15.3 Acid Gas Injection Systems
  • 15.4 Compressor Design Considerations
  • 15.5 Capacity Control in Reciprocating AGI Compressors
  • 15.6 Capacity Control in Reciprocating Compressor/PD Pump Combinations
  • 15.7 Capacity Control in Reciprocating Compressor/Centrifugal Pump Combinations
  • 15.8 Capacity Control When Using Screw Compressors
  • 15.9 Capacity Control When Using Centrifugal Compression
  • 15.10 System Stability
  • 15.11 Summary
  • Reference
  • 16 Review and Testing of Radial Simulations of Plume Expansion and Confirmation of Acid Gas Containment Associated with Acid Gas Injection in an Underpressured Clastic Carbonate Reservoir
  • 16.1 Introduction
  • 16.2 Site Subsurface Geology
  • 16.2.1 General Stratigraphy and Structure
  • 16.2.2 Geology Observed in AGI #1 and AGI #2
  • 16.3 Well Designs, Drilling and Completions
  • 16.3.1 AGI #1
  • 16.3.2 AGI #2
  • 16.4 Reservoir Testing and Modeling
  • 16.4.1 AGI #1
  • 16.4.2 Linam AGI #2
  • 16.4.3 Comparison of Reservoir between Wells
  • 16.4.4 Initial Radial Model and Plume Prediction
  • 16.4.5 Confirmation of Plume Migration Model and Integrity of Caprock
  • 16.5 Injection History and AGI #1 Responses
  • 16.6 Discussion and Conclusions
  • References
  • 17 Three-Dimensional Reservoir Simulation of Acid Gas Injection in Complex Geology - Process and Practice
  • 17.1 Introduction
  • 17.2 Step by Step Approach to a Reservoir Simulation Study for Acid Gas Injection
  • 17.3 Seismic Data and Interpretation
  • 17.4 Geological Studies
  • 17.5 Petrophysical Studies
  • 17.6 Reservoir Engineering Analysis
  • 17.7 Static Modeling
  • 17.8 Reservoir Simulation
  • 17.9 Case History
  • 17.10 Injection Interval Structure and Modeling
  • 17.11 Petrophysical Modeling and Development of Static Model
  • 17.12 Injection Zone Characterization
  • 17.13 Reservoir Simulation
  • 17.14 Summary and Conclusions
  • References
  • 18 Production Forecasting of Fractured Wells in Shale Gas Reservoirs with Discontinuous Micro-Fractures
  • 18.1 Introduction
  • 18.2 Multi-Scale Flow in Shale Gas Reservoir
  • 18.2.1 Multi-scale Nonlinear Seepage Flow Model of Shale Gas Reservoir
  • 18.2.2 Adsorption - Desorption Model of Shale Gas Reservoir
  • 18.3 Physical Model and Solution of Fractured Well of Shale Gas Reservoir
  • 18.3.1 The Dual Porosity Spherical Model with Micro-Fractures Surface Layer
  • 18.3.2 The Establishment and Solvement of Seepage Mathematical Model
  • 18.4 Analysis of Influencing Factors of Sensitive Parameters
  • 18.5 Conclusions
  • 18.6 Acknowledgements
  • References
  • 19 Study on the Multi-Scale Nonlinear Seepage Flow Theory of Shale Gas Reservoir
  • 19.1 Introduction
  • 19.2 Multi-Scale Flowstate Analyses of the Shale Gas Reservoirs
  • 19.3 Multi-Scale Nonlinear Seepage Flow Model in Shale Gas Reservoir
  • 19.3.1 Nonlinear Seepage Flow Model in Nano-Micro Pores
  • 19.3.2 Multi-Scale Seepage Model Considering of Diffusion, Slippage
  • 19.3.3 Darcy Flow in Micro Fractures and Fractured Fractures
  • 19.4 Transient Flow Model of Composite Fracture Network System
  • 19.5 Production Forecasting
  • 19.6 Conclusions
  • 19.7 Acknowledgements
  • References
  • 20 CO2 EOR and Sequestration Technologies in PetroChina
  • 20.1 Introduction
  • 20.2 Important Progress in Theory and Technology
  • 20.2.1 The Miscible Phase Behaviour of Oil-CO2 System
  • 20.2.2 CO2 Flooding Reservoir Engineering Technology
  • 20.2.3 Separated Layer CO2 Flooding, Wellbore Anti-Corrosion and High Efficiency Lift Technology
  • 20.2.4 Long Distance Pipeline Transportation and Injection Technology
  • 20.2.5 Produced Fluid Treatment for CO2 Flooding and Cycling Gas Injection Technology
  • 20.2.6 CO2 Flooding Reservoir Monitoring, Performance Analysis Technology
  • 20.2.7 Potential Evaluation for CO2 Flooding and Storage
  • 20.3 Progress of Pilot Area
  • 20.3.1 Block Hei59
  • 20.3.2 Block Hei79
  • 20.4 Conclusions
  • 20.5 Acknowledgements
  • References
  • 21 Study on the Microscopic Residual Oil of CO2 Flooding for Extra-High Water-Cut Reservois
  • 21.1 Introduction
  • 21.2 Overview of CO2 EOR Mechanisms for Extra High Water Cut Reservoirs
  • 21.3 Experimental Microscopic Residual Oil Distribution of CO2 Flooding for Extra High Water Cut Reservoirs
  • 21.3.1 NMR Theory
  • 21.3.2 In situ NMR Test for Water Flooding and CO2 Flooding
  • 21.4 Displacement Characteristics of CO2 Flooding and Improve Oil Recovery Method for Post CO2 Flooding
  • 21.4.1 CO2 Displacement Characteristics for Extra High Water Cut Reservoirs
  • 21.4.2 Improved Oil Recovery for Post CO2 Flooding
  • 21.5 Conclusions
  • References
  • 22 Monitoring of Carbon Dioxide Geological Utilization and Storage in China: A Review
  • 22.1 Introduction
  • 22.2 Status of CCUS in China
  • 22.3 Monitoring of CCUS
  • 22.3.1 Monitoring Technology at Home and Abroad
  • 22.3.2 U-tube Sampling System
  • 22.3.3 Monitoring Technologies in China's CCUS Projects
  • 22.4 Monitoring Technology of China's Typical CCUS Projects
  • 22.4.1 Shenhua CCS Demonstration Project
  • 22.4.2 Shengli CO2-EOR Project
  • 22.5 Environmental Governance and Monitoring Trends in China
  • 22.6 Conclusion
  • 22.7 Acknowledgements
  • References
  • 23 Separation of Methane from Biogas by Absorption-Adsorption Hybrid Method
  • 23.1 Introduction
  • 23.2 Experiments
  • 23.2.1 Experimental Apparatus
  • 23.2.2 Materials
  • 23.2.3 Synthesis and Activation of ZIF-67
  • 23.2.4 Gas-Slurry Equilibrium Experiments
  • 23.2.5 Data Processing
  • 23.2.6 Breakthrough Experiment
  • 23.3 Results and Discussions
  • 23.3.1 Adsorbent Characterization
  • 23.3.2 Ab-Adsorption Isothermal
  • 23.3.3 Breakthrough Experiment
  • 23.4 Conclusions
  • 23.5 Acknowledgements
  • References
  • Index
  • EULA

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