Fluid chemistry, drilling and completion / edited by Qiwei Wang.

Format:

Book

Contributor:

Wang, Qiwei, editor.

Series:

Oil and Gas Chemistry Management

Oil and Gas Chemistry Management ; v.Volume One

Language:

English

Subjects (All):

Oil well drilling.

Physical Description:

1 online resource (494 pages)

Edition:

1st ed.

Place of Publication:

Cambridge, Mass. ; London : Elsevier, [2022]

Summary:

Fluid Chemistry, Drilling and Completion, the latest release in the Oil and Gas Chemistry Management series that covers all sectors of oil and gas chemicals (from drilling to production, processing, storage and transportation), delivers critical chemical oilfield basics while also covering the latest research developments and practical solutions.

Contents:

Front Cover

Fluid Chemistry, Drilling and Completion

Copyright Page

Contents

List of contributors

1 Reservoir fluid geodynamics

1.1 Introduction

1.2 Reservoir fluid geodynamics

1.2.1 Asphaltene science

1.2.1.1 AFM and STM molecular imaging of asphaltenes

1.2.1.2 AFM and STM images of diverse asphaltenes

1.2.1.3 Asphaltene gradients in reservoirs

1.2.2 Ora intelligent wireline formation testing platform and DFA

1.3 RFG oilfield case studies

1.3.1 RFG applied to a light oil reservoir

1.3.1.1 RFG processes in this reservoir

1.3.2 RFG applied to a black oil field

1.3.2.1 RFG processes in this reservoir

1.4 RFG workflow

1.5 Conclusions

Nomenclature

References

2 Sampling petroleum fluids

2.1 Introduction

2.1.1 From upstream to downstream

2.1.2 Sampling types-the short list

2.1.3 Defining reservoir type

2.1.4 Fluid initialization

2.1.5 In situ-representative versus reservoir representative samples

2.1.6 Developing PVT models

2.1.6.1 Why do we need PVT data?

2.1.6.2 How do we get PVT data?

2.2 Sampling procedures and measurements

2.2.1 Sampling types

2.2.1.1 STO sampling

2.2.1.2 Separator sampling

2.2.1.3 Conventional Bottomhole sampling

2.2.1.4 Openhole formation testing

2.2.2 How do we use samples?

2.2.2.1 Water samples

2.2.2.2 STO samples

2.2.2.3 Separator samples

2.2.3 Sampling standards

2.2.4 Compositional analyses

2.3 Sampling strategies

2.3.1 Balancing wish lists and costs

2.3.2 Discovery wells

2.3.3 Delineation wells

2.3.4 Production wells

2.3.5 EOR wells

2.3.6 Problem wells

2.3.7 Fluid system considerations

2.3.7.1 Saturated gas-oil systems

2.3.7.2 Near-saturated systems

2.3.7.3 Highly undersaturated systems

2.3.7.4 Compositionally grading systems

2.4 Special issues in sampling.

2.4.1 Sample storage

2.4.2 Separator sampling

2.4.2.1 Liquid carryover in the gas wellstream

2.4.2.2 Isokinetic sampling

2.4.3 Using contaminated PVT samples

2.4.4 Wax, asphaltenes, scale, and hydrates

2.4.5 Mud gas sampling

2.4.6 Tight unconventionals

2.4.6.1 Recommended sampling strategy

2.4.6.2 PVT data

2.5 Conclusions

3 Water chemistry

3.1 Introduction

3.2 Types of water samples

3.3 Water sampling and analysis

3.4 Water data evaluation

3.5 Water chemistry data interpretation and reconciliation

3.6 Factors that impact/change water chemistry

3.7 Field case examples of water chemistry application

3.7.1 Original oil in place (OOIP) estimate

3.7.2 Water source identification

3.7.3 Management of scale, corrosion, and other water-related production problems

3.7.4 Produced water chemistry surveillance and applications in shale and tight plays

3.8 Final remarks

4 Drilling fluids

4.1 Introduction

4.2 Drilling fluid functions

4.2.1 Formation pressure management and wellbore stability-fluid density

4.2.2 Hole cleaning-fluid rheological properties

4.2.3 Seal permeable formations-fluid loss control and bridging

4.2.4 Reduce friction-fluid lubricity

4.2.5 Other functions

4.3 Drilling fluid types

4.4 Aqueous-based fluids

4.4.1 Water-based fluid additives

4.4.1.1 Weighting agents

4.4.1.2 Rheology modifiers

4.4.1.3 Fluid loss control additives

4.4.1.4 pH and corrosion control

4.4.1.5 Shale inhibitors

4.4.1.6 Thinners/dispersants

4.4.1.7 Lubricants

4.4.2 Water-based fluids types

4.4.2.1 Dispersed water-based fluids

4.4.2.2 Low-solids, nondispersed water-based fluids

4.5 Nonaqueous fluids

4.5.1 Nonaqueous fluids additives

4.5.1.1 Weighting agents.

4.5.1.2 Emulsifiers and wetting agents

4.5.1.3 Base oil

4.5.1.4 Rheology modifiers

4.5.1.5 Shale inhibitors

4.5.1.6 Fluid loss control additives

4.5.1.7 pH and corrosion control

4.5.1.8 Lubricants

4.5.1.9 Thinners/dispersants

4.5.2 Nonaqueous fluid types

4.5.2.1 Conventional nonaqueous fluids

4.5.2.2 High-performance nonaqueous fluids

4.6 Reservoir drilling fluids

4.6.1 Reservoir drilling fluid additives

4.6.1.1 Weighting agents

4.6.1.2 Filtration control (bridging)

4.6.1.3 Viscosifiers

4.6.1.4 Shale inhibition

4.6.1.5 Lubricants

4.6.1.6 Surfactants

4.6.1.7 pH and corrosion control

4.7 Conclusion

5 Cementing additives

5.1 Introduction

5.2 Cement basics

5.2.1 Chemical notation

5.2.2 Portland cement chemistry

5.2.3 Hydration of Portland cement

5.2.3.1 Silicate phases

5.2.3.1.1 Metastable barrier hypothesis

5.2.3.1.2 Slow dissolution step hypothesis

5.2.3.2 Aluminates

5.2.3.3 Portland cement

5.2.3.3.1 Chemical shrinkage

5.2.4 Interparticle interactions

5.2.5 Application to well cements

5.3 Slurry formulation

5.3.1 Temperature

5.3.2 Slurry density

5.3.2.1 Changing the water-to-cement ratio

5.3.2.2 Including density adjusting additives

5.3.2.3 Foaming

5.3.2.4 Extenders

5.3.2.4.1 Bentonite

5.3.2.4.2 Sodium silicate

5.3.2.4.3 Pozzolans

5.3.2.5 Commercial lightweight cements

5.3.2.6 Density adjusting particles

5.3.3 Placement time

5.3.3.1 Retarders

5.3.3.1.1 Sugars

5.3.3.1.2 Lignosulfonates

5.3.3.1.3 Hydroxycarboxylic acids

5.3.3.1.4 Synthetic polymeric retarders

5.3.3.1.5 Organophosphonates

5.3.3.1.6 Borates

5.3.3.1.7 Phosphates

5.3.3.1.8 Silicates

5.3.3.1.9 Zinc oxide

5.3.3.1.10 Summary

5.3.3.2 Accelerators

5.3.3.2.1 Inorganic calcium salts.

5.3.3.2.2 C-S-H seeds

5.3.3.2.3 Sodium silicate

5.3.3.2.4 Colloidal silica

5.3.4 Rheological properties

5.3.4.1 Properties under shear

5.3.4.2 Properties at rest

5.3.4.3 Dispersants

5.3.4.3.1 Sulfonated polyanionic resin dispersants

5.3.4.3.2 PCE dispersants

5.3.4.4 Antisettling agents

5.3.5 Fluid loss control

5.3.5.1 Filtration control and testing

5.3.5.2 "Particulate" fluid loss control additives

5.3.5.3 Soluble polymers as fluid loss control additives

5.3.5.4 "Combined mechanism" fluid loss control additives

5.3.6 Gas migration control

5.3.7 Other additives

5.3.7.1 Antifoam/defoamers

5.3.7.2 Foaming agents

5.3.7.3 Expansion additives

5.3.7.3.1 Delayed ettringite formation

5.3.7.3.2 Magnesium oxide

5.3.7.4 Special blends

5.3.7.4.1 CO2-resistant cement

5.3.7.4.2 Flexible cement systems

5.3.7.4.3 Self-healing cement systems

5.4 Summary

5.4.1 Polymers in cement formulations

5.4.2 Formulation approach

Conversion Factors

Acknowledgments

6 Completion and workover fluids

6.1 Introduction

6.2 Types of completion brines

6.2.1 Halide brines (inorganic salts)

6.2.2 Formate brines (organic salts)

6.2.3 Potassium carbonate brine

6.3 Considerations for completion brine selection

6.3.1 Density requirement

6.3.2 Crystallization temperature

6.3.3 Hydrate inhibition

6.3.4 Compatibility with formation fluids

6.3.5 Compatibility with reservoir matrix

6.3.6 Corrosion of completion hardware

6.3.7 Environmental and safety

6.3.8 Cost

6.4 Completion brine properties measurement

6.4.1 Density

6.4.2 Iron content

6.4.3 Turbidity

6.4.4 Total suspended solids

6.5 Completion brine additives

6.5.1 Corrosion inhibitors

6.5.2 Lubricants

6.5.3 Viscosifier and fluid loss control.

6.5.3.1 Hydroxyethylcellulose

6.5.3.2 Cross-linked HEC pills

6.5.3.3 Solid laden pills

6.5.3.4 Solid-sized salt pills

6.6 Conclusion

7 Packer fluids

7.1 Introduction

7.2 Types of packer fluids

7.3 Solids-free brines

7.4 Packer fluid properties

7.4.1 Density

7.4.2 Crystallization temperature

7.4.3 Fluid clarity

7.4.4 Corrosion and corrosion inhibition

7.4.5 Fluid compatibility

7.5 Displacement

7.6 Safety

7.7 Summary

8 Carbonate matrix stimulation

8.1 Introduction

8.2 Candidate selection

8.3 Chemical and physical processes in carbonate acidizing

8.3.1 Reactions of carbonate rocks with strong inorganic acids

8.3.2 Reactions of carbonate rocks with weak organic acids and chelants

8.3.3 Carbonate dissolution patterns: influence of transport and reaction

8.3.4 Wormhole growth models

8.3.5 Influence of mineralogy and porosity type

8.4 Stimulation fluid engineering

8.4.1 Single-phase retarders for HCl-carbonate reaction

8.4.2 Organic acids and chelants

8.4.3 Polymer and viscoelastic surfactant gelled acids

8.4.4 Emulsified acids

8.4.5 Foamed acids

8.5 Stimulation treatment design

8.5.1 Design challenges

8.5.1.1 Placement of acid in each pay zone

8.5.1.2 Fluid selection

8.5.1.3 Treatment simulation

8.5.2 Design optimization

8.6 Summary

9 Sandstone matrix stimulation

9.1 Introduction

9.2 Formation damage mechanisms in sandstone reservoirs

9.2.1 Clay swelling

9.2.2 Fines migration

9.2.3 Inorganic scale deposition

9.2.4 Organic scale deposition

9.2.5 Damage during drilling and completion

9.2.6 Damage during reservoir stimulation

9.3 Acid types

9.3.1 Hydrofluoric acid and mud acid

3.1.1 Mud acid-mineral reaction stoichiometry.

Notes:

Includes bibliographical references and index.

Description based on print version record.

Description based on publisher supplied metadata and other sources.

ISBN:

0-12-822741-9

OCLC:

1285165122