Recovery improvement / edited by Qiwei Wang.

Format:

Book

Author/Creator:

Wang, Qiwei, author.

Series:

Oil and Gas Chemistry Management ; v.Volume 3

Language:

English

Subjects (All):

Enhanced oil recovery.

Petroleum engineering.

Physical Description:

1 online resource (614 pages)

Place of Publication:

Amsterdam, Netherlands : Elsevier, [2022]

Summary:

Oil and Gas Chemistry Management Series brings an all-inclusive suite of tools to cover all the sectors of oil and gas chemicals from drilling, completion to production, processing, storage, and transportation. The third reference in the series, Recovery Improvement, delivers the critical chemical basics while also covering the latest research developments and practical solutions. Organized by the type of enhanced recovery approaches, this volume facilitates engineers to fully understand underlying theories, potential challenges, practical problems, and keys for successful deployment. In addition to the chemical, gas, and thermal methods, this reference volume also includes low-salinity (smart) water, microorganism- and nanofluid-based recovery enhancement, and chemical solutions for conformance control and water shutoff in near wellbore and deep in the reservoir. Supported by a list of contributing experts from both academia and industry, this book provides a necessary reference to bridge petroleum chemistry operations from theory into more cost-efficient and sustainable practical applications.

Contents:

Front Cover

Recovery Improvement

Copyright Page

Contents

List of contributors

1 Conformance control and water shut-off

1.1 Introduction

1.2 Root causes for conformance problems

1.2.1 Mobility-driven viscous fingering

1.2.2 Reservoir heterogeneity

1.2.2.1 Vertical heterogeneity: the effects of crossflow

1.2.2.2 The impacts of fractures and vuggy features within the reservoir body

1.2.3 Water conning

1.2.4 Wellbore integrity

1.3 Bulk gel technology

1.3.1 Mechanism of action

1.3.2 Applications

1.3.3 Case studies

1.3.3.1 Conformance improvement on the North Slope of Alaska

1.3.3.2 Conformance improvement in Canadian Bakken

1.3.3.3 Water shut-off in Manitoba

1.4 Relative permeability modifiers

1.4.1 Mechanism of action

1.4.2 Applications

1.4.3 Deployment history

1.5 Sodium silicate gels

1.5.1 Mechanism of action

1.5.2 Applications

1.6 Colloidal dispersion gels

1.6.1 Candidate selection for colloidal dispersion gels

1.6.2 Expected results

1.6.3 Case studies

1.6.3.1 North Rainbow Ranch

1.6.3.2 Dina field

1.7 Thermally active polymers

1.7.1 Working mechanism

1.7.2 Applications

1.7.3 Basic screening criteria

1.7.4 Development history and field statistics

1.7.5 Field case study

1.8 Preformed particle gels

1.8.1 Basic screening criteria

1.8.2 Deployment history

1.9 Foams

1.9.1 Basic screening criteria

1.9.2 Development history

1.9.3 Case study

1.10 Summary

Nomenclature

References

2 Low-salinity (enhanced) waterflooding in carbonate reservoirs

2.1 Introduction

2.1.1 Different names of the technology and the misconceptions

2.1.2 The ultimate aim of low-salinity waterflooding

2.1.3 Target field candidates

2.2 Fundamentals

2.2.1 Carbonate chemistry

2.2.2 Carbonate surface charge.

2.2.3 Petrophysical characteristics of carbonate rocks

2.2.4 Current opinions on low-salinity waterflooding mechanisms

2.2.5 Low-salinity waterflooding "cause and effect" issue

2.3 Low-salinity waterflooding from laboratory to field

2.3.1 Length- and time-scale consistency

2.3.2 Assessment of LSWF efficiency

2.3.3 Considerations for the design of laboratory experiments

2.3.3.1 Core preparation steps

2.3.3.2 Coreflooding experimental protocols

2.3.4 Field candidate screening criteria

2.3.4.1 Initial reservoir wettability

2.3.4.2 Formation brine composition and pH

2.3.4.3 Oil composition

2.3.4.4 Reservoir temperature

2.3.4.5 Rock composition and presence of dissolvable minerals, such as anhydrite

2.3.4.6 Initial oil saturation/water saturation

2.3.4.7 Other important considerations

2.3.5 Upscaling workflow and field assessment

2.4 Field case histories

2.5 Modeling and numerical simulation of low-salinity waterflooding

2.5.1 Length scales of simulation

2.5.2 Current approaches to simulation at core and reservoir scale

2.5.3 Wettability alteration criterion

2.5.4 Pore-scale simulation of LSWF

2.5.5 Molecular dynamic simulation

2.5.6 Density functional theory (DFT)

2.5.7 Surface complexation modeling (SCM)

2.6 Concluding remarks, remaining challenges, and future of low-salinity waterflooding technology

2.6.1 Mechanisms

2.6.2 Improved evaluation of LSWF-experiments

2.6.3 Improved simulation of LSWF-next-generation, multiscale, multiphysics simulation

2.6.4 Field projects

2.6.5 Candidate screening

2.6.6 Economics

3 Enhanced oil recovery by Smart Water injection in sandstone reservoirs

3.1 Introduction

3.2 Initial wettability of sandstone reservoirs

3.2.1 Mineralogy in porous sandstones

3.2.1.1 Quartz.

3.2.1.2 Feldspar minerals

3.2.1.3 Clay minerals

3.2.1.4 Evaporites

3.2.2 Formation water

3.2.3 Brine-rock interactions

3.2.3.1 Surface area and ion exchange

3.2.3.2 Surface reactivity of sandstone cores

3.2.4 Crude oil and adsorption of its components onto sandstone surfaces

3.2.4.1 Polar organic components

3.2.4.2 pH-dependent polar organic component adsorption on clay mineral surfaces

3.2.4.3 Adsorption of polar crude oil components in sandstone cores

3.2.5 Core restoration

3.2.6 Wettability measurements

3.2.6.1 Contact angle measurements on smooth surfaces

3.2.6.2 Wettability in porous media

3.3 Smart Water enhanced oil recovery in sandstones

3.3.1 Mechanistic studies and proposed mechanisms

3.3.1.1 Migration of fines/limited fines release

3.3.1.2 In situ surfactant generation

3.3.1.3 Multicomponent ion exchange

3.3.1.4 Electrical double layer expansion

3.3.1.5 Local pH increase-pH-induced wettability alteration

3.3.1.6 Integrated pH-ion-surface electrostatics model

3.3.2 pH-induced wettability alteration mechanism in sandstones

3.3.3 Smart Water enhanced oil recovery on a model sandstone system

3.3.3.1 Tertiary Smart Water enhanced oil recovery effect

3.3.3.2 Wettability alteration and capillary forces

3.3.3.3 Effect of oil-brine interfacial tension

3.3.3.4 Effect of temperature on surface reactivity and Smart Water enhanced oil recovery potential

3.3.3.5 Salinity effects on Smart Water enhanced oil recovery in sandstones

3.3.4 Smart Water injection strategies for sandstones

3.3.4.1 LS slug injection in sandstones

3.3.4.2 Secondary Smart Water enhanced oil recovery effect

3.3.4.3 Seawater as Smart Water in sandstone

3.3.5 Smart Water enhanced oil recovery observations in reservoir systems.

3.3.5.1 Enhanced oil recovery effects by viscous flooding

3.3.5.2 Enhanced oil recovery effects by spontaneous imbibition

3.4 Summary

4 Chemical enhanced oil recovery

4.1 Introduction

4.2 Polymer flooding

4.2.1 Principles

4.2.2 Characterization and evaluation of commonly used polymer agents

4.2.2.1 Hydrolyzed polyacrylamide

4.2.2.2 Polysaccharide

4.2.2.2.1 Xanthan gum

4.2.2.2.2 Scleroglucan

4.2.2.2.3 Guar gum

4.2.2.2.4 Cellulose

4.2.2.3 Hydrophobically associating polymers

4.2.3 Impacting factors on treatment efficiency

4.2.3.1 Molecular weight

4.2.3.2 Polymer concentration

4.2.3.3 Salt concentration

4.2.3.4 Temperature

4.2.3.5 Shear rate

4.2.3.6 Polymer stability

4.2.3.6.1 Chemical stability

4.2.4 Screening criteria and status of the application

4.2.4.1 Screening criteria

4.2.4.2 Application status

4.2.4.2.1 Daqing oilfield, China

4.2.4.2.2 North Oregon Basin Field and Byron Field, United States

4.2.4.2.3 Milne Point Field, Alaska's North Slope, United States

4.2.4.2.4 East Bodo reservoir, Canada

4.2.4.2.5 SZ36-1 field in Bohai Bay, China

4.2.5 Future development of polymer flooding

4.2.6 Remaining challenges

4.3 Surfactant flooding and wettability alternation

4.3.1 Characterization and evaluation of commonly used surfactant agents

4.3.1.1 Types of surfactants

4.3.1.2 Surfactant characterization

4.3.1.2.1 Hydrophile-lipophile balance

4.3.1.2.2 Micelles and critical micelle concentration

4.3.1.2.3 Krafft temperature

4.3.1.3 Macroemulsion and microemulsion

4.3.1.4 Types of microemulsions

4.3.1.5 Surfactant retention

4.3.1.5.1 Adsorption

4.3.1.5.2 Precipitation

4.3.1.5.3 Phase trapping

4.3.2 Surfactant enhanced oil recovery mechanisms

4.3.2.1 Interfacial tension reduction.

4.3.2.2 Wettability alteration of the rock

4.3.2.2.1 Wettability alteration by cationic surfactants

4.3.2.2.2 Wettability alteration by anionic surfactants

4.3.2.3 Formation of emulsions

4.3.3 Characterization and evaluation of commonly used surfactant agents

4.3.4 Surfactant screening criteria

4.3.5 Application limitation and the status of the application

4.3.6 New development of surfactant flooding

4.3.7 Remaining challenges

4.4 Alkaline flooding

4.4.1 Alkaline enhanced oil recovery mechanisms

4.4.1.1 Interfacial tension reduction

4.4.1.2 Emulsification

4.4.1.2.1 Emulsification and entrainment

4.4.1.2.2 Emulsification and coalescence

4.4.1.2.3 Emulsification and entrapment

4.4.1.3 Wettability reversal (oil wet to water wet)

4.4.1.4 Wettability reversal (water wet to oil wet)

4.4.2 Characterization and evaluation of commonly used alkaline agents

4.4.2.1 pH values of commonly used alkalis

4.4.2.2 Properties of commonly used alkalis

4.4.3 Impacting factors on treatment efficiency

4.4.3.1 Acid number

4.4.3.2 Alkaline concentration and type

4.4.4 Application limitation and the status of the application

4.4.4.1 Screening criteria

4.4.4.1.1 Oil properties

4.4.4.1.2 Reservoir properties

4.4.4.2 The status of the application

4.4.4.2.1 North Gujarat oilfield, India

4.4.4.2.2 The North Ward-Estes field, TX, United States

4.4.4.2.3 The Court Bakken heavy oil reservoir in Saskatchewan

4.4.5 Future development of alkaline flooding

4.4.6 Remaining challenges

4.5 Surfactant-polymer flooding

4.5.1 Synergy between surfactant and polymer

4.5.2 Surfactant-polymer flooding enhanced oil recovery mechanisms

4.5.3 Field applications

4.5.3.1 Status of surfactant-polymer flooding in China

4.5.3.1.1 Shengli Gudong oilfield, China.

4.5.3.1.2 CNOOC JZ 9-3 oilfield, Bohai Bay, China.

Notes:

Description based on print version record.

Other Format:

Print version: Wang, Qiwei Recovery Improvement

ISBN:

9780128234389

0128234385