Enhanced Oil Recovery in Shale and Tight Reservoirs

__Oil Recovery in Shale and Tight Reservoirs__ delivers a current, state-of-the-art resource for engineers trying to manage unconventional hydrocarbon resources. Going beyond the traditional EOR methods, this book helps readers solve key challenges on the proper methods, technologies and options available. Engineers and researchers will find a systematic list of methods and applications, including gas and water injection, methods to improve liquid recovery, as well as spontaneous and forced imbibition. Rounding out with additional methods, such as air foam drive and energized fluids, this book gives engineers the knowledge they need to tackle the most complex oil and gas assets. Cover Front-Matter_2020_Enhanced-Oil-Recovery-in-Shale-and-Tight-Reservoirs Enhanced Oil Recovery in Shale and Tight Reservoirs Copyright_2020_Enhanced-Oil-Recovery-in-Shale-and-Tight-Reservoirs Copyright Contents Acknowledgments_2020_Enhanced-Oil-Recovery-in-Shale-and-Tight-Reservoirs Acknowledgments Chapter-One---Introduction-to-shale-a_2020_Enhanced-Oil-Recovery-in-Shale-an One . Introduction to shale and tight reservoirs 1.1 Introduction 1.2 Definitions of shale and tight reservoirs 1.2.1 Shale tight reservoir 1.2.2 Shale oil versus oil shale 1.2.3 Injection modes 1.3 Shale and tight resources 1.4 Current production technologies Chapter-Two---Huff-n-puff-gas-injecti_2020_Enhanced-Oil-Recovery-in-Shale-an Two . Huff-n-puff gas injection in oil reservoirs 2.1 Introduction 2.2 Initial simulation studies of huff-n-puff gas injection 2.3 Experimental methods 2.3.1 Core saturation with oil 2.3.2 Huff-n-puff experiments 2.3.3 Experimental verification of huff-n-puff effectiveness 2.4 Effect of core size 2.5 Effects of pressure and pressure depletion rate 2.6 Effect of soaking time 2.7 EOR performance with number of cycles 2.8 Effect of injected gas composition 2.9 Minimum miscible pressure 2.10 Effect of diffusion 2.11 Effect of water saturation 2.12 Effect of stress-dependent permeability 2.13 Huff-n-puff mechanisms 2.14 Gas penetration depth 2.15 Field projects 2.15.1 CO2 huff-n-puff in Bakken formation, Elm Coulee field 2.15.2 CO2 huff-n-puff in Burning Tree-State No. 36-2H well in the Montana part of Bakken formation 2.15.3 Huff-n-puff CO2 injection in Parshall field 2.15.4 Eagle Ford project in La Salle County, TX 2.15.5 CO2 injection in an unfractured vertical well in the Middle Bakken 2.15.6 Summary of gas huff-n-puff performance Chapter-Three---Asphaltene-precipitation-an_2020_Enhanced-Oil-Recovery-in-Sh Three . Asphaltene precipitation and deposition in a huff-n-puff process 3.1 Introduction 3.2 Experiments of asphaltene precipitation and permeability reduction 3.3 Deposition mechanisms 3.4 Numerical analysis 3.5 Effect of asphaltene deposition on huff-n-puff optimization Chapter-Four---Huff-n-puff-injection-in-s_2020_Enhanced-Oil-Recovery-in-Shal Four . Huff-n-puff injection in shale gas condensate reservoirs 4.1 Introduction 4.2 Experimental setup 4.3 Huff-n-puff gas injection 4.4 Huff-n-puff versus gas flooding 4.5 Core-scale modeling of gas and solvent performance 4.6 Reservoir-scale modeling of gas and solvent performance 4.7 A field case of methanol injection 4.8 Surfactant treatment 4.9 Factors that affect huff-n-puff gas injection performance 4.9.1 Effect of huff pressure 4.9.2 Effect of puff pressure 4.9.3 Effect of cycle time 4.9.4 Effect of soak time 4.9.5 CO2 injection performance 4.10 Optimization of huff-n-puff injection 4.11 Mechanisms of huff-n-puff injection 4.10.1 Revaporization by gas 4.10.2 Swelling by a solvent 4.10.3 Changed phase behavior Chapter-Five---Optimization-of-huff-n-puff-ga_2020_Enhanced-Oil-Recovery-in- Five . Optimization of huff-n-puff gas injection in shale and tight oil reservoirs 5.1 Introduction 5.2 Setup of a base simulation model 5.3 Optimization principles 5.4 Optimization criteria 5.4.1 Optimum huff time and puff time 5.4.2 Optimum soaking time 5.4.3 Number of cycles 5.4.4 Start time of huff-n-puff Chapter-Six---Gas-flooding-compared-with_2020_Enhanced-Oil-Recovery-in-Shale Six . Gas flooding compared with huff-n-puff gas injection 6.1 Introduction 6.2 Research results on gas flooding 6.3 Gas flooding versus huff-n-puff gas injection 6.4 Field applications of gas flooding 6.4.1 Gas flooding in Viewfield Bakken field, Saskatchewan (Schmidt and Sekar, 2014) 6.4.2 Gas flooding in Bakken formation in North Dakota (Hoffman and Evans, 2016) 6.4.3 CO2 injection in Song-Fang-Dun Field, Daqing (Jiang et al., 2008) 6.4.4 CO2 injection in Yu-Shu-Lin Field, Daqing (Wang, 2015) 6.4.5 Summary of gas flooding performance 6.5 Feasibility of gas flooding Chapter-Seven---Water-injec_2020_Enhanced-Oil-Recovery-in-Shale-and-Tight-Re Seven . Water injection 7.1 Introduction 7.2 Waterflooding 7.2.1 Waterflooding in Bakken and Lower Shaunavon, Saskatchewan 7.2.2 Waterflooding in Bakken formation in North Dakota 7.2.3 Waterflooding in Bakken formation in Montana 7.2.4 Waterflooding in Bakken Viewfield in Saskatchewan 7.2.5 Waterflooding in Pembina Cardium in Alberta 7.2.6 Waterflooding in Vinogradova field in Russia 7.2.7 Summary of waterflooding performance 7.3 Water huff-n-puff injection 7.3.1 Huff-n-puff water injection in Bakken formation in North Dakota 7.3.2 Huff-n-puff water injection in Parshall Field 7.3.3 Huff-n-puff water injection followed by huff-n-puff CO2 injection in Parshall Field 7.3.4 Summary of water huff-n-puff performance 7.4 Waterflooding versus huff-n-puff water injection 7.5 Water injection versus gas injection 7.6 Water-alternating-gas (WAG) 7.7 Huff-n-puff water and surfactant injection 7.8 Water injection in China 7.8.1 Pulsed water injection 7.8.2 Asynchronous water injection 7.8.3 Huff-n-puff water injection Chapter-Eight---Fluid-rock-inte_2020_Enhanced-Oil-Recovery-in-Shale-and-Tigh Eight . Fluid-rock interactions 8.1 Introduction 8.2 Evidences of microfractures generated or existing natural fractures reopened 8.3 Effect of confining stress 8.4 Effect of bedding 8.5 Effect of existing natural fractures 8.6 Permeability changes from water-rock interactions 8.7 Effect on rock mechanical properties 8.8 Further discussions and summary of views and hypotheses 8.9 Effect of low-pH and carbonated water 8.10 Effect of high-pH water 8.11 Cooling effect of injected water 8.12 Reaction-induced fractures 8.13 Surfactant effects Chapter-Nine---EOR-mechanisms-of-wettability_2020_Enhanced-Oil-Recovery-in-S Nine . EOR mechanisms of wettability alteration and its comparison with IFT 9.1 Introduction 9.2 Mechanisms of interfacial tension (IFT) reduction 9.3 Mechanisms of wettability alteration on oil recovery 9.4 Mathematical treatments of wettability alteration and IFT effect 9.4.1 UTCHEM model 9.4.2 Adibhatla et al. (2005) model 9.4.3 A proposed simply model 9.4.4 CMG-STARS model 9.5 IFT reduction versus wettability alteration 9.5.1 Effect of combined wettability alteration and IFT reduction 9.5.2 Relative importance of wettability alteration and IFT reduction 9.5.3 Effect of IFT on spontaneous oil recovery with and without wettability alteration 9.6 Specific surfactant EOR mechanisms related to shale and tight formations 9.6.1 Bilayer mechanism by anionic surfactants 9.6.2 Micellar solubilization of organic component by anionic surfactants 9.6.3 Ion-pair mechanism 9.6.4 Surfactant adsorption mechanism 9.6.5 Monolayer adsorption by nonionic surfactants 9.6.6 Effect of IFT reduction on wettability alteration 9.7 Surfactant selection for wettability alteration 9.8 Determination of wettability 9.8.1 Commonly used methods 9.8.2 Capillary rise method and thin layer wicking method 9.8.3 Spontaneous imbibition method 9.8.4 Pore-space imaging methods 9.8.5 Nuclear magnetic resonance (NMR) method 9.8.6 Zeta potential (ζ-potential) measurements 9.8.7 Discussion of methods to determine wettability 9.9 Conversion of wetting angles 9.10 More on wettability of shale and tight formations Chapter-Ten---Spontaneous-imb_2020_Enhanced-Oil-Recovery-in-Shale-and-Tight- Ten . Spontaneous imbibition 10.1 Introduction 10.2 Discussion of some theoretical equations on spontaneous imbibition 10.2.1 Washburn's equation 10.2.2 Handy (1960) method 10.2.3 Mattax and Kyte (1962) method 10.2.4 Li and Horne (2006) method 10.3 Effect of permeability and porosity 10.3.1 Simulation results 10.3.2 Theoretical considerations 10.3.3 Experimental observation 10.4 Effect of initial wettability and wettability alteration 10.5 Effect of interfacial tension (IFT) 10.5.1 Theoretical and experimental analysis 10.5.2 Simulation analysis 10.6 Effect of diffusion 10.7 Effect of gravity 10.8 Effect of viscosity ratio 10.9 Effect of initial water content 10.10 Countercurrent flow versus cocurrent flow 10.11 Behaviors of different surfactants Chapter-Eleven---Forced-imbi_2020_Enhanced-Oil-Recovery-in-Shale-and-Tight-R Eleven . Forced imbibition 11.1 Introduction 11.2 Description of a base shale model 11.3 Shale rock versus sand rock 11.4 Relative permeability change versus capillary pressure change 11.5 Effect of capillary pressure 11.6 Effect of pressure gradient (injection rate) 11.7 Experimental study of forced imbibition 11.8 Field tests of surfactant EOR Chapter-Twelve---Fracturing-fluid_2020_Enhanced-Oil-Recovery-in-Shale-and-Ti Twelve . Fracturing fluid flow back 12.1 Introduction 12.2 Field observations and experimental results on flow back 12.2.1 Low flow back 12.2.2 Flow back versus hydrocarbon production 12.3 Proposed mechanisms of low flow back 12.3.1 Subirreducible initial water saturation 12.3.1.1 Vaporization (gas reservoirs) 12.3.1.2 Geological compression and diagenesis 12.3.1.3 Hydration 12.3.2 Capillary imbibition 12.3.3 Fluid entrapment 12.3.4 Osmosis 12.3.4.1 Osmosis in shale 12.3.4.2 Osmotic mechanism in shale 12.3.4.3 Implications of osmotic phenomenon 12.3.5 Evaporation 12.3.6 Permeability jail 12.4 Effect of shut-in time on flow back 12.5 Shut-in time effect on fracture conductivity 12.6 Effect of initial wettability on flow back 12.7 Effect of invasion depth on flow back efficiency and late time oil rate 12.8 Effect of surfactants on flow back 12.9 Solutions to deal with flow back 12.9.1 Avoid using trapping fluids 12.9.2 Early high drawdown 12.9.3 CO2 injection 12.9.4 Solvent injection 12.9.5 Use of surfactants 12.9.6 Injection of dry gas 12.9.7 Formation heating Chapter-Thirteen---Air-inje_2020_Enhanced-Oil-Recovery-in-Shale-and-Tight-Re Thirteen . Air injection 13.1 Introduction 13.2 Laboratory experimental facilities 13.2.1 Thermogravimetry 13.2.2 Differential scanning calorimetry 13.2.3 Small batch reactor 13.2.4 Ramped temperature oxidation (RTO) 13.2.5 Combustion tube test 13.2.6 Accelerating rate calorimeter (ARC) 13.3 Kinetic parameters 13.3.1 Thermogravimetric analysis (TGA) 13.3.2 Differential scanning calorimetry (DSC) 13.3.3 Practical values of kinetic parameters 13.3.4 Exothermic and endothermic behavior 13.3.5 A simulation approach to estimate kinetic parameters and heating values 13.3.6 An example to build a kinetic simulation model Step 1 model grids Step 2 define pseudocomponents Step 3 define parameters for oxidation reactions Step 4 define reaction scheme 13.4 Oxidation reactions 13.4.1 Terminologies and principles to define reaction scheme 13.4.2 Factors that affect oxidation reactions 13.4.2.1 Pressure effect 13.4.2.2 Catalytic effect of additives 13.4.2.3 Gas phase versus oil phase 13.4.2.4 Light oil versus heavy oil 13.5 Spontaneous ignition 13.5.1 Field observations 13.5.2 Laboratory observations 13.5.3 Simulation studies 13.5.4 Delay time of spontaneous ignition 13.5.5 Prediction of spontaneous ignition using the Frank-Kamenestskii method 13.5.6 Thermal effect in low-temperature oxidation 13.5.7 Experimental 13.5.8 Results and discussion 13.5.9 Numerical analysis 13.6 Oxygen consumption rate in low-temperature oxidation 13.7 Minimum oil content for combustion 13.8 Air requirement in combustion 13.9 EOR mechanisms and EOR potential in shale and tight reservoirs Chapter-Fourteen---Other-enhanced-oi_2020_Enhanced-Oil-Recovery-in-Shale-and Fourteen . Other enhanced oil recovery methods 14.1 Introduction 14.2 Sequential method of huff-n-puff CO2 injection and surfactant-assisted spontaneous imbibition 14.3 Chemical blends 14.4 Air foam drive 14.5 Branched fractures 14.6 Zipper fracture 14.7 Refracturing 14.8 Diversion technology in fracturing 14.9 Energized fluids 14.10 Thermal recovery 14.11 Microbial EOR Nomenclature_2020_Enhanced-Oil-Recovery-in-Shale-and-Tight-Reservoirs Nomenclature Greek symbols Superscripts Subscript References_2020_Enhanced-Oil-Recovery-in-Shale-and-Tight-Reservoirs References Index_2020_Enhanced-Oil-Recovery-in-Shale-and-Tight-Reservoirs Index A B C D E F G H I K L M N O P Q R S T U V W Z Backcover Today's Unconventional Reservoirs Are More Complex And Engineers Are Still Trying To Learn Fundamental Knowledge Of How To Adjust Current Known Enhanced Oil Recovery (eor) Methods And Mechanisms To Solve And Optimize More Unconventional Reservoirs Which Have Immense Potential To Meet Future Oil And Gas Demand. Enhanced Oil Recovery In Shale And Tight Reservoirs Delivers A Current State-of-the-art Resource In This Unknown Area For Engineers Trying To Manage Unconventional Hydrocarbon Resources. Going Beyond The Traditional Eor Methods, This Product Answers Key Challenges On The Proper Methods, Technology, And Options Available That Can Be Applied In The Production Process, Followed By The Most Current Field Applications. The First Of Its Kind To Be Offered In One Source, Enhanced Oil Recovery In Shale And Tight Reservoirs Provides Engineers And Researchers With A Systematic List Of Methods And Applications, Including Gas And Water Injection, Methods To Improve Liquid Recovery, As Well As Spontaneous And Forced Imbibition. Rounding Out With Additional Methods Such As Air Foam Drive And Energized Fluids, Enhanced Oil Recovery In Shale And Tight Reservoirs Gives Engineers The Knowledge Needed To Tackle The Most Complex Oil And Gas Assets. Understand Methods And Mechanisms For Enhanced Oil Recovery Technology Specifically For Shale And Tight Oil Reservoirs Obtain Deep Analysis Through Author's Research On Available Eor Methods As Well As Recent Practical Case Studies, Including Fracturing Fluid Flow Back Learn About Additional Methods Such As Soaking After Fracturing, Thermal Recovery, And Microbial Eor Oil Recovery in Shale and Tight Reservoirs delivers a current, state-of-the-art resource for engineers trying to manage unconventional hydrocarbon resources. Going beyond the traditional EOR methods, this book helps readers solve key challenges on the proper methods, technologies and options available. Engineers and researchers will find a systematic list of methods and applications, including gas and water injection, methods to improve liquid recovery, as well as spontaneous and forced imbibition. Rounding out with additional methods, such as air foam drive and energized fluids, this book gives engineers the knowledge they need to tackle the most complex oil and gas assets. Helps readers understand the methods and mechanisms for enhanced oil recovery technology, specifically for shale and tight oil reservoirs Includes available EOR methods, along with recent practical case studies that cover topics like fracturing fluid flow back Teaches additional methods, such as soaking after fracturing, thermal recovery and microbial EOR Oil Recovery in Shale and Tight Reservoirs delivers a current, state-of-the-art resource for engineers trying to manage unconventional hydrocarbon resources. Going beyond the traditional EOR methods, this book helps readers solve key challenges on the proper methods, technologies and options available. Engineers and researchers will find a systematic list of methods and applications, including gas and water injection, methods to improve liquid recovery, as well as spontaneous and forced imbibition. Rounding out with additional methods, such as air foam drive and energized fluids, this book gives engineers the knowledge they need to tackle the most complex oil and gas assets. -- Provided by publisher