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Unconventional Shale Gas Development Lessons Learned

Edited by

ROUZBEH G. MOGHANLOO Mewbourne School of Petroleum and Geological Engineering, The University of Oklahoma, Norman, OK, United States

Gulf Professional Publishing is an imprint of Elsevier 50 Hampshire Street, 5th Floor, Cambridge, MA 02139, United States The Boulevard, Langford Lane, Kidlington, Oxford, OX5 1GB, United Kingdom Copyright © 2022 Elsevier Inc. All rights reserved.

No part of this publication may be reproduced or transmitted in any form or by any means, electronic or mechanical, including photocopying, recording, or any information storage and retrieval system, without permission in writing from the publisher. Details on how to seek permission, further information about the Publisher’s permissions policies and our arrangements with organizations such as the Copyright Clearance Center and the Copyright Licensing Agency, can be found at our website: www.elsevier.com/permissions.

This book and the individual contributions contained in it are protected under copyright by the Publisher (other than as may be noted herein).

Notices Knowledge and best practice in this field are constantly changing. As new research and experience broaden our understanding, changes in research methods, professional practices, or medical treatment may become necessary.

Practitioners and researchers must always rely on their own experience and knowledge in evaluating and using any information, methods, compounds, or experiments described herein. In using such information or methods they should be mindful of their own safety and the safety of others, including parties for whom they have a professional responsibility.

To the fullest extent of the law, neither the Publisher nor the authors, contributors, or editors, assume any liability for any injury and/or damage to persons or property as a matter of products liability, negligence or otherwise, or from any use or operation of any methods, products, instructions, or ideas contained in the material herein.

British Library Cataloguing-in-Publication Data A catalogue record for this book is available from the British Library Library of Congress Cataloging-in-Publication Data A catalog record for this book is available from the Library of Congress ISBN: 978-0-323-90185-7 For Information on all Gulf Professional Publishing publications visit our website at https://www.elsevier.com/books-and-journals

Publisher: Charlotte Cockle Senior Acquisitions Editor: Katie Hammon Editorial Project Manager: Naomi Robertson Production Project Manager: Vignesh Tamil Cover Designer: Christian J. Bilbow Typeset by MPS Limited, Chennai, India

List of contributors

Gayan A. Abeykoon Hildebrand Department of Petroleum and Geosystems Engineering, The University of Texas at Austin, Austin, TX, United States Francisco J. Argüelles-Vivas Hildebrand Department of Petroleum and Geosystems Engineering, The University of Texas at Austin, Austin, TX, United States Arash Dahi-Taleghani John and Willie Leone Family Department of Energy and Mineral Engineering, The Pennsylvania State University, University Park, PA, United States Hassan Dehghanpour Department of Civil and Environmental Engineering, University of Alberta, Edmonton, AB, Canada Deepak Devegowda Mewbourne School of Petroleum and Geological Engineering, The University of Oklahoma, Norman, OK, United States Birol Dindoruk Cullen College of Engineering, Petroleum Engineering, University of Houston, Houston, TX, United States Tawfik Elshehabi Petroleum Engineering Department, University of Wyoming, Laramie, WY, United States Yingkun Fu School of Energy Resources, China University of Geosciences, Beijing, P.R. China; State Key Laboratory of Shale Oil and Gas Enrichment Mechanisms and Effective Development, Beijing, P.R. China; Department of Civil and Environmental Engineering, University of Alberta, Edmonton, AB, Canada Zoya Heidari The University of Texas at Austin, Austin, TX, United States Amirmasoud Kalantari-Dahaghi Department of Chemical and Petroleum Engineering, The University of Kansas, Lawrence, KS, United States Hamidreza Karami Mewbourne School of Petroleum and Geological Engineering, The University of Oklahoma, Norman, OK, United States Lucy Tingwei Ko Bureau of Economic Geology, The University of Texas at Austin, Austin, TX, United States Ademide O. Mabadeje Hildebrand Department of Petroleum and Geosystems Engineering, Cockrell School of Engineering, The University of Texas at Austin, Austin, TX, United States

xiii

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List of contributors

Mark William McClure ResFrac Corporation, Palo Alto, CA, United States Rouzbeh G. Moghanloo Mewbourne School of Petroleum and Geological Engineering, The University of Oklahoma, Norman, OK, United States Ryosuke Okuno Hildebrand Department of Petroleum and Geosystems Engineering, The University of Texas at Austin, Austin, TX, United States Felipe Perez Mewbourne School of Petroleum and Geological Engineering, The University of Oklahoma, Norman, OK, United States Michael J. Pyrcz Hildebrand Department of Petroleum and Geosystems Engineering, Cockrell School of Engineering, The University of Texas at Austin, Austin, TX, United States; Department of Geological Sciences, Jackson School of Geosciences, The University of Texas at Austin, Austin, TX, United States Ali Rezaei Midstream Production Systems, Houston, TX, United States Raki Sahai Mewbourne School of Petroleum and Geological Engineering, The University of Oklahoma, Norman, OK, United States Saeed Salehi Mewbourne School of Petroleum and Geological Engineering, The University of Oklahoma, Norman, OK, United States Carl H. Sondergeld Mewbourne School of Petroleum and Geological Engineering, The University of Oklahoma, Norman, OK, United States Fnu Suriamin Oklahoma Geological Survey, The University of Oklahoma, Norman, OK, United States Catalin Teodoriu Mewbourne School of Petroleum and Geological Engineering, The University of Oklahoma, Norman, OK, United States Ali Ousseini Tinni Mewbourne School of Petroleum and Geological Engineering, The University of Oklahoma, Norman, OK, United States Yuxing Wu Mewbourne School of Petroleum and Geological Engineering, The University of Oklahoma, Norman, OK, United States Mohamed Y. Soliman Cullen College of Engineering, Petroleum Engineering, University of Houston, Houston, TX, United States

List of contributors

Hao Yu State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University, Chengdu, China Sebastian Zavaleta Villarreal Mewbourne School of Petroleum and Geological Engineering, The University of Oklahoma, Norman, OK, United States

xv

Preface

Shale gas development has radically changed the natural gas market in North America.

Given the abundance of natural gas at historically low prices having become a possibility in the United States owing to technological advances, the presence of operators with sufficient risk appetite, and favorable monetary policies, as a result, the production of natural gas in the United States has seen an increasing trend for the past decade and had peaked at about 960 billion cubic meters in 2019. This bolstered domestic production has turned the country into a powerful player in global natural gas markets. Consequently, the United States has risen to become the world's top exporter from being in the lower 48 countries in just six years after its first LNG cargo was exported in 2016.

This book is an attempt to summarize the technological advances realized through shale gas revolution. The book has been specifically designed for asset managers, petroleum engineers, shale gas stakeholders, and graduate students who would like to learn more about the different aspects of and challenges associated with the production of natural gas from shale gas resources.

Chapter 1 delves into the details of asset management issues and delineates upon the reserves reporting for shale reservoirs. Chapter 2 addresses geological characterization covering topics such as heterogeneity and organic chemistry of shale gas and ends with case studies from multiple shale plays. Chapter 3 provides a comprehensive review of well construction and casing fatigue in multifractured horizontal wells.

Chapter 4 is specifically dedicated to well control challenges in horizontal wells and discusses operational complications that occur in shale gas wells. Chapter 5 is devoted to well integrity and wellbore stability issues and presents stability of wells in Tuscaloosa shale plays as the case study.

Chapter 6 highlights the challenges in formation evaluation of organic-rich mud rocks and goes into the details of recent advances to overcome them. Chapter 7 reviews interpretation methods used for diagnostic fracture injection tests and explains the author’s preferred approach. Chapter 8 outlines a new technique based upon wavelet analysis evaluating a fracture network in the system with some examples from Utah’s FORGE project. Chapter 9 elaborates proppant placement and the challenges associated with proppant transport in complex fracture networks.

Chapter 10 presents geomechanical modeling covering topics such as fracture propagation and casing deformation. Chapter 11 introduces a new decline model that can successfully describe water production during flow back. Chapter 12 outlines the implementation of molecular dynamics simulation to describe fluids distribution in

xvii

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Preface

organic matter. Chapter 13 provides a comprehensive review of recent efforts for wettability alteration in liquid-rich shale plays. Chapter 14 elaborates on the scale dependency of petrophysical properties of shale samples.

Chapter 15 addresses the challenges associated with fluid lifting and the practical treatments suggested for shale systems. Chapter 16 summarizes production data analysis developed for shale gas wells. Chapter 17 delineates on the applications of artificial intelligence and machine learning algorithms in building meaningful relations between experimental data and production performance. Chapter 18 unveils a new screening protocol for evaluation of gas injection experiments conducted to enhance liquid production and discusses the Eagle Ford case study. Chapter 19 deals with sampling bias in data-driven approaches used in shale gas development and introduces a new workflow for debiasing spatially clustered samples.

Contents

List of contributors Preface

xiii xvii

1.

1

Field development and asset management Raki Sahai

2.

1.1 Introduction 1.2 Background 1.2.1 How we got to where we are today?

1.3 Conventional versus unconventional reservoirs 1.4 Asset management 1.4.1 Field development plan for shale plays 1.4.2 Role of technologies in unconventional development 1.4.3 Shale development challenges 1.5 Reserves reporting for shale reservoirs 1.5.1 Proved (1P) and 3P reserves 1.5.2 Estimated ultimate recovery forecasting techniques 1.5.3 Stochastic reserve booking 1.5.4 Reserves-based lending 1.6 Future prospects of shale development References

1 3 4 8 10 14 17 19 20 21 24 26 27 29 29

Geological characterization of unconventional shale-gas reservoirs

33

Fnu Suriamin and Lucy Tingwei Ko 2.1 2.2 2.3 2.4 2.5

2.6 2.7 2.8 2.9 2.10

The history of shale gas Geological evaluations of shale gas prospects Proximate control on accumulation of organic-matter-rich shale Definition of shale/mudstone/mudrock Depositional environments of organic-matter-rich shale 2.5.1 Nonmarine depositional settings 2.5.2 Marine depositional settings 2.5.3 Transitional depositional settings Organic geochemistry of gas shale Other geological characterizations of successful shale gas plays Heterogeneity of shale-gas reservoirs Diagenetic impact on shale-gas reservoirs Distribution of shale-gas reservoirs worldwide

34 35 37 40 40 41 43 46 46 50 50 51 52

v

vi

Contents

3.

2.11 Case studies: The Middle Devonian Marcellus Formation and the Appalachian Basin 2.11.1 Organic matter, total organic matter, and thermal maturity 2.11.2 Key aspects of the Marcellus Formation 2.12 Geoenvironmental challenges in the development of shale-gas reservoirs 2.13 Conclusions References

52 57 58 60 63 63

Construction and completion of multifractured horizontal wells

71

Catalin Teodoriu

4.

3.1 3.2 3.3 3.4 3.5

Definitions Well construction The wellbore tubulars To rotate or not to rotate: the unconventional well dilemma!

Casing fatigue in unconventional wells 3.5.1 Fatigue induced while running the casing 3.5.2 Drilling-induced fatigue 3.5.3 Casing drilling-induced fatigue 3.5.4 Casing fatigue in unconventional wells 3.5.5 Internal pressure induced fatigue 3.5.6 Temperature variation induced fatigue 3.5.7 Casing cement system fatigue 3.5.8 Wellbore tubulars testing and qualification 3.5.9 Specimen geometry 3.5.10 Load envelope 3.5.11 Make and break tests 3.5.12 Baking (aging) test 3.5.13 Leak detection 3.6 An OCTG selection approach for unconventional wells 3.7 Wellbore completion of horizontal unconventional wells 3.8 Environmental aspects of well construction and completion References

71 71 81 85 87 87 88 88 88 88 88 89 89 89 90 90 91 91 93 97 101 102

Well control challenges in unconventional shale plays

105

Tawfik Elshehabi 4.1 4.2 4.3 4.4 4.5 4.6 4.7

Introduction Well control in unconventional shale plays Well control philosophy Well control complications in horizontal wells Well control challenges in nonaqueous drilling fluids Inclined upward laterals challenges Kicks while running casing or liners challenges

105 106 106 109 113 117 118

Contents

5.

4.8 Factors affecting well control practices in horizontal wells 4.9 Lessons learned References

120 122 123

Wellbore/borehole stability in shale formation

125

Yuxing Wu and Saeed Salehi

6.

5.1 Overview 5.2 Introduction 5.3 Geomechanical evaluation of well stability in shale formation 5.3.1 Mechanical stress around wellbore 5.3.2 Mud window estimation 5.3.3 In-situ stress estimation 5.4 Mud shale interaction affecting well stability in shale formation 5.4.1 Strength degradation in shale formation 5.4.2 Swelling and dispersion in shale formation 5.5 Well integrity in shale formation 5.5.1 Hydraulic degradation 5.5.2 Mechanical degradation 5.6 A case study in Tuscaloosa Marine Shale 5.6.1 Tuscaloosa Marine Shale wellbore stability 5.6.2 Tuscaloosa Marine Shale wellbore integrity 5.7 Summary Reference

125 125 126 127 130 132 134 135 136 138 138 142 145 145 147 148 149

Advances in formation evaluation of shale systems

155

Zoya Heidari 6.1 Overview of challenges in formation evaluation of organic-rich mudrocks 6.1.1 Composition 6.1.2 Rock fabric 6.1.3 Geochemistry 6.1.4 Solid fluid interfacial interactions 6.1.5 Ground truth measurements 6.1.6 Upscaling 6.2 Advanced formation evaluation in organic-rich mudrocks 6.2.1 Reserves evaluation 6.2.2 Wettability 6.2.3 Cation exchange capacity 6.2.4 Mechanical properties 6.3 Recap and the way forward References

156 156 158 159 161 161 162 162 163 166 171 173 176 178

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Contents

7.

Advances in interpretation of diagnostic fracture injection tests

185

Mark William McClure

8.

7.1 Introduction 7.1.1 What is a diagnostic fracture injection tests?

7.1.2 The basis for classical techniques, and why they become inaccurate in shale 7.2 The URTeC-2019 123 interpretation procedure 7.2.1 Overview 7.2.2 Prepare the data and make relevant plots 7.2.3 Estimate stress and effective initial shut-in pressure 7.2.4 Diagnose late-time impulse transients 7.2.5 Estimating pore pressure 7.2.6 Estimating permeability to the mobile reservoir fluid Acknowledgments References

185 185 187 192 192 192 196 199 203 207 213 213

Fracture diagnostic testing

217

Ali Rezaei, Mohamed Y. Soliman and Birol Dindoruk

9.

8.1 Overview 8.2 Testing types 8.3 Step-rate test 8.3.1 Step-up test 8.3.2 Step-down test 8.4 Pump in/shut-in test 8.4.1 Before closure analysis 8.4.2 After closure analysis 8.5 Pump-in/flow-back test (micro-frac) 8.6 New analysis technique 8.6.1 Wavelet analysis 8.6.2 Effect of natural fracture and temperature 8.6.3 Utah FORGE example (effect of heat exchange) 8.6.4 DFIT 1 8.6.5 DFIT 2 8.7 Summary References

217 217 218 218 218 220 221 226 228 229 229 238 238 239 242 245 246

Proppant placement

249

Raki Sahai and Rouzbeh G. Moghanloo 9.1 Introduction 9.1.1 Hydraulic fracturing process 9.1.2 Hydraulic fracturing in unconventional shale reservoirs

249 249 254

Contents

9.2 Sediment transport theory and transport mechanisms in noncrosslinked fluids 9.2.1 Single-particle settling and Stokes’ law 9.2.2 Deviations from Stokes’ law 9.3 Proppant transport in vertical fractures 9.3.1 Experimental work 9.3.2 Correlations to predict proppant settling 9.4 Proppant transport in complex fracture networks 9.4.1 Experimental work 9.4.2 Numerical simulations using computation fluid dynamics and discrete element method models References Further reading

10. Advances in geomechanical modeling

258 259 262 263 263 267 269 270 274 275 278

279

Hao Yu and Arash Dahi-Taleghani 10.1 Introduction to rock mechanics at granular mesoscale 10.2 Fracture propagation model 10.2.1 Cohesive zone method 10.2.2 Fracture network simulation using cohesive zone method 10.3 Mechanical earth modeling 10.4 Casing deformation problems References

11. Advances in flowback analysis: fracturing water production obeys a simple decline model

279 282 283 285 289 290 296

299

Yingkun Fu and Hassan Dehghanpour 11.1 Introduction 11.2 Methodology 11.3 Water-rate decline during flowback and postflowback 11.3.1 Reservoir and well-completion data 11.3.2 Field observations 11.3.3 The physics of water flowback 11.4 Harmonic water-rate decline model 11.5 Application and discussions 11.5.1 Validating harmonic-decline model 11.5.2 Fitting harmonic-decline model to field data 11.5.3 Water recovery factor 11.5.4 Ultimate water recovery volume 11.6 Limitations and recommendations 11.7 Conclusion Acknowledgments References

299 301 301 301 303 306 307 310 310 311 311 315 316 317 317 317

ix

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Contents

12. Application of molecular dynamics simulations for shale gas systems

323

Deepak Devegowda and Felipe Perez 12.1 Introduction

323

12.2 Basic theory

324

12.2.1 Potential fields 12.3 Description of kerogen and fluid models 12.3.1 Kerogen

325 329 330

12.3.2 Asphaltenes and resins 12.4 Water and carbon dioxide 12.5 Hydrocarbons 12.6 Simulation details 12.7 Organic matter models 12.8 Spatial distribution of fluids 12.9 Primary recovery from organic nanopores 12.10 Conclusions References

331 331 331 332 333 333 336 340 341

13. Wettability modifiers for enhanced oil recovery from tight and shale reservoirs

345

Francisco J. Argüelles-Vivas, Gayan A. Abeykoon and Ryosuke Okuno 13.1 Introduction 13.1.1 Distinctions between conventional and unconventional reservoirs 13.1.2 Wettability in shale reservoirs 13.2 Wettability-alteration agents for shales 13.2.1 Surfactant solutions 13.2.2 Low salinity water solutions

345 346 347 348 349 350

13.3 Ketone solvent as a new wettability modifier 13.3.1 Mechanism of wettability alteration by ketone solvent 13.3.2 3-Pentanone properties 13.3.3 Reservoir fluid properties 13.3.4 Aqueous stability test 13.3.5 Contact-angle and interfacial tension experiments

351 351 354 354 357 358

13.3.6 Spontaneous and forced imbibition experiments 13.3.7 Dynamic imbibition experiments 13.3.8 Huff-n-puff experiments with shales 13.3.9 Dynamic retention of 3-pentanone and 2-EH-4PO-15EO in shale minerals 13.4 Summary and conclusions References

359 364 376 380 386 387

Contents

14. Scale considerations during petrophysical characterization of shales

393

Ali Ousseini Tinni 14.1 Introduction and background 14.2 Scale dependent SEM properties of shales 14.2.1 Observations of scale dependent SEM porosity and TOC 14.2.2 Recommendations for SEM image area size 14.3 Sample size consideration for MICP of shales 14.3.1 Observations of sample size dependent MICP porosity and pore throat size distribution 14.3.2 Interpretation of sample size dependent MICP porosity and pore size distribution 14.4 Scale dependent shale pressure decay permeability 14.4.1 Observations of sample size dependent pressure decay permeability 14.4.2 Interpretation of the scale dependency of pressure decay permeability References

393 395 395 397 398

399 400 401 402 402

15. Challenges associated with lifting and loading in shale gas wellbore systems

405

398

Hamidreza Karami 15.1 Introduction 15.2 Multiphase flow fundamentals 15.3 Horizontal well flow assurance studies 15.4 Artificial lift practices in unconventional wells 15.5 Summary References

405 406 409 412 415 415

16. Production data analysis for shale gas wells

417

Sebastian Zavaleta Villarreal and Rouzbeh G. Moghanloo 16.1 Introduction 16.2 Straight line analysis 16.3 Distance of investigation and linear flow parameter 16.4 Material balance equation for shale gas reservoir 16.5 Dynamic drainage volume in the unstimulated shale matrix (tri-linear flow) Reference

417 417 419 423 426 431

17. Machine learning applications in unconventional shale gas systems

433

Amirmasoud Kalantari-Dahaghi 17.1 Introduction 17.2 Artificial intelligence/machine learning applications on production performance- lessons learned

433 434

xi

xii

Contents

17.2.1 Artificial lift selection and predictive maintenance for production enhancement using machine learning 17.2.2 Petrophysical and geomechanical evaluation on production using machine learning 17.3 Conclusions References

18. Experimental evaluation of enhanced oil recovery in unconventional resource plays: a new screening protocol

434 436 441 441

445

Carl H. Sondergeld 18.1 Introduction 18.2 Experimental Huff-n-Puff studies 18.3 New enhanced oil recovery screening experiments 18.4 Screening test example: Eagle Ford experiments 18.5 Microstructural changes 18.6 Discussion Acknowledgments References Further reading

19. Spatial data analytics for optimum data declustering in shale systems

445 446 447 448 450 454 454 455 456

457

Ademide O. Mabadeje and Michael J. Pyrcz 19.1 Introduction 19.2 Methodology 19.3 Results and discussions 19.4 Conclusions References Index

457 462 464 469 469 471

CHAPTER 1

Field development and asset management Raki Sahai1,2 1

Ascent Resources, Oklahoma City, OK, United States Mewbourne School of Petroleum and Geological Engineering, The University of Oklahoma, Norman, OK, United States

2

1.1 Introduction Hydrocarbon production from shale reservoirs has transformed the American oil and gas industry and has led to the country’s energy independence in recent years. The phenomenal growth in the last two decades, the resilience of the exploration and production (E&P) operators amidst commodity price volatility in the last few years, and a promising outlook for the coming decades sums up the story of America’s shale boom recently.

In the 1950s, when the American geophysicist M. King Hubbert made his predictions of oil production peaking in the lower 48 states of the United States, the oil industry was still in its technical infancy. While Hubert was right about the peak oil in the 1970s at 10 million barrels per day, commonly referred to as the “Hubbert’s Peak,” his statistical analysis did not consider the advances in technology that would make the extraction of hydrocarbons from ultra-tight reservoirs possible. The application of horizontal drilling in conjunction with advances in hydraulic fracturing has led to the economic extraction of oil and natural gas from tight, low-permeability unconventional formations, such as shale. The development of shale formations, once assumed to act as a “seal” in the conventional petroleum system, led to a reversal of US oil production decline, and in November 2017, the daily production once again surpassed the 10 million barrel mark for the first time since 1970 (Fig. 1.1). Fig. 1.2 shows the shale plays in the lower 48 states of the United States.

Although the United States and Canada are the two leading countries involved in the commercial development of shale reservoirs, an assessment by the United States Energy Information Administration in 2013 reported technically recoverable resources of 7299 tcf of shale gas and 345 MMbbls of shale oil in 137 shale formations across 41 countries (United States EIA, 2013). China and Argentina currently also have ongoing development programs but with limited commercial success.

Unconventional Shale Gas Development DOI: https://doi.org/10.1016/B978-0-323-90185-7.00019-4

r 2022 Elsevier Inc. All rights reserved.

1

2

Unconventional Shale Gas Development

Figure 1.1 1920 2020 US field daily production of crude oil (US EIA).

Figure 1.2 Shale plays in the US Lower 48 (United States EIA, 2009).

Field development and asset management

1.2 Background The term “shale” refers to a hard mudstone composed of fine clastic grains less than 1/16 mm in size, clay minerals, and organic matter with shaley or thinly laminar bedding.

Shale is considered the source rock for conventional and unconventional hydrocarbon accumulations. In terms of hydrocarbon accumulation and distribution, the shale formations are classified as “continuous” accumulations and are not confined to the geologic structure or trap. However, the formation is heterogeneous in nature, and the mineralogy, organic content, natural fractures, and other properties vary spatially. Shales are characterized by very low porosity (typically less than 5%) and ultra-low permeability (100 nD to 1 mD), making them challenging in recovering viable hydrocarbons economically without hydraulic fracturing. The hydrocarbon storage mechanism in shale formations is more complex than the conventional sandstone reservoirs. Since the shale formation act as both source rock and reservoir for hydrocarbon production, it is referred to as a resource play.

A recent article in the Wall Street Journal compared the various development variables for four different types of conventional and unconventional plays—conventional onshore play in Saudi Arabia, conventional play offshore, oil sands in Alberta, and shale reservoir in shale play (Fig. 1.3). With the technological advances in drilling and completions over the past decade in the US shale industry, the spud to first production cycle time is probably the fastest. The cost of developing wells has also decreased significantly over the past decade, making shale development on the low end of cost per barrel compared to other plays. However, due to the low porosity and permeability, the production decline rate is the highest among the four. The article provided an excellent analogy to explain the issue with the high production decline rate—producing oil and gas out of a conventional well is much like slowly pouring soda out of a can, whereas producing oil and gas from a hydraulically fractured shale well looks like what happens when you shake the can and open it. The hydrocarbons come out quickly

Figure 1.3 Comparison of oil and gas exploration technologies. (Modified from Lee, 2020).

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Unconventional Shale Gas Development

from a fractured shale well but start losing momentum rapidly, too. In an Eagle Ford well, the oil production declines 60% in the first year but more than 90% over the first 3 years. In comparison, conventional oil fields only decline 5% 10% a year (Lee, 2020). This has a direct implication on the field development with more shale wells (and more capital) needed each year for production maintenance (i.e., keeping field production flat) or growth, compared to a conventional field.

1.2.1 How we got to where we are today?

The shale gas revolution refers to the phenomenon that emerged in terms of domestic gas supply in the United States. The knowledge of the presence of large amounts of hydrocarbons in shale reservoirs is not new. The shale revolution is not driven by a recent discovery of a new type of formation; instead, the recent advances in drilling and stimulation technology allowed the geologists and engineers to exploit the shale formation in a cost-effective way. The natural gas was first extracted from shallow shale reservoirs in Fredonia, New York, in 1825 (Milam, 2011), three decades before the first commercial conventional well was drilled by Col. Edwin Drake in 1859. However, the first commercial development of naturally fractured Devonian shales started in 1915 (Nuttall, 2021). For most of the 20th century, shale formation was considered a “seal” for the conventional reservoirs. It was not until the US crude oil and natural gas production started to decline in the 1970s that the interest in shale reservoirs developed in the mid-1970s.

The federal government invested in a few supply alternatives, including the Eastern Gas Shales Project and the Gas Research Institute, to conduct research on shale gas development. The federal government also provided tax credits via the 1980 Energy Act and Section 29 tax credit to facilitate research and development from 1980 to 2000 (Stevens, 2012). Although the Eastern Gas Shale Project (1976 92) increased gas production in the Appalachian and Michigan basins, shale gas development was still widely regarded as marginal to uneconomic without tax credits (Wang & Krupnick, 2013).

One of the early innovations during this period was the development of microseismic mapping technology at Sandia National Laboratories in 1981. This technology was developed to map the created hydraulic fractures by locating the microseismic events, which helped evaluate the effectiveness of the stimulation. Although this technology was initially developed for the coal bed methane research, it was soon applied to map the hydraulic fracture growth during the stimulation of naturally-fractured shale formations. An estimate of created fracture dimensions, referred to as the stimulated reservoir volume (SRV), was then used to decide the well-to-well (or lateral) spacing for full-field development.

George P. Mitchell is credited with pioneering the economic extraction of shale gas from the Barnett Shale, which eventually led to the unprecedented boom in domestic energy production. It started with one of Mitchell’s geologists, Jim Henry, who indicated that the Barnett Shale had large natural fractures and that it might be

Field development and asset management

possible to extract natural gas. The technique of hydraulic fracturing was developed in the late 1940s. Mitchell Energy started implementing hydraulic fracturing in the early 1980s in an attempt to extract natural gas from these naturally-fractured Barnett Shale commercially. In 1984, Mitchell Energy switched from using foam-based to gel-based fracturing fluid, but it showed limited success. From 1987 to 1997, Mitchell Energy completed 304 wells considered commercial, and the economic returns were sufficient for continuing the Barnett development program (NTNG, 2016). It was not until 1998 when Mitchell Energy adapted a fracturing fluid recipe that Union Pacific Resources was using to complete the Cotton Valley wells. The new fracturing fluid, which was later called the “slick water,” used large volumes of water but lower concentrations of sand to create micro-fractures and helped unlock gas from tight Barnett shale. Fig. 1.4 shows the production response of a Barnett Shale well after refracs with gel frac and slick water. In addition to increasing the production rates, slick water fracturing reduced the costs from $375,000 per well for gel-based fracturing to $85,000 per well for a slick water treatment (NTNG, 2016).

Figure 1.4 Refracs of a shale well in Barnett Shale performed by Mitchell Energy. The slick water treatment delivered better results as compared to the foam and gel fracture treatments. (Modified from King, 2010).

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Unconventional Shale Gas Development

Between 1998 and 2002, Mitchell continued to implement slick water fracture treatments to other wells in the Barnett Shale, which resulted in a 250% increase in production from the area. Then, in 2002, Devon Energy, recognizing the potential that existed in the Barnett Shale, acquired Mitchell Energy. It was not long before the other operators, such as Chesapeake Energy, XTO Energy, and EOG Resources, acquired leases in the Barnett Shale, and by 2005 the play was producing half a trillion cubic feet of natural gas (NTNG, 2016).

The shale gas revolution was over 20 years in making, but the ramping up of production started in the mid-2000s. The shale gas and oil development and production in the United States can be summarized into four main phases: • 2003 08: Although Mitchell Energy experimented with the drilling and completion designs for the Barnett Shale since the early 1980s and found commercial success in 1998, the focus of shale testing was restricted to the Barnett Shale. The shale revolution across the United States gained momentum in the early 2000s with the rising natural gas prices and growing demand from power- and energy-intensive industries (Majumdar & Mittal, 2018). During this period, the gas price remained over $5 per MMBtu gas from early 2003 to mid-2008, and operators expanded their focus to shale gas formations across the country. In the summer of 2004, Southwestern Energy announced that Fayetteville Shale in Arkansas had many of the same geologic characteristics that made the Barnett Shale productive, which led to a drilling boom in northern Arkansas. With sustained high gas prices, similar drilling booms followed in the Haynesville Shale (Louisiana/East Texas) and Marcellus Shale (Pennsylvania) plays.

The WTI crude oil prices also posted one of their biggest rallies in this period, increasing from about $32 per barrel to $142 per barrel, due to the growing demand from developing nations, especially China that was rapidly ramping up its industry and infrastructure, and risking energy security concerns worldwide.

Development of shale resources during this period resulted in strong growth in investment and employment in the industry, with both spiking to the highest levels since 1990 (Majumdar & Mittal, 2018).

• 2008 14: The global financial crisis and Great Recession of 2008 negatively impacted the economy and induced a bear market on oil and gas prices. The crude oil prices dipped from the previous high of $142 to about $33 per barrel during the second half of 2008, while the gas price went from trading over $13 to ultimately sub-$3 per MMBtu in 2009. The industry rig activity decreased by about 45% during this time before recovering with the commodity prices in 2009 10.

Nevertheless, as a result of the shale gas revolution, shale gas production increased from contributing about 1.6% of the total US natural gas production to over 20% by 2010 (Fig. 1.2) (Wang & Krupnick, 2013).

Even though the shale gas development continued until 2012, the industry witnessed a gradual shift from natural gas to tight oil production during this phase.

Field development and asset management

Operators discovered that combined technologies of horizontal drilling and slick water hydraulic fracturing that have been successful in the shale gas reservoirs could be used to extract oil from the tight oil formations. With the oil prices stabilizing around $100 per barrel after the financial crisis, it started with the Bakken and Three Forks formations in the North Dakota/Montana, and led Eagle Ford Shale in South Texas to quickly becoming the most prolific oil field in the world.

Similarly, the Permian Basin in West Texas, which was on production decline with several decades of conventional development since the 1920s, was rejuvenated as operators found the technology effective in tapping the hydrocarbons from the highly productive shale formations sandwiched between the conventional reservoirs.

By 2014, the industry rig count reached an all-time high count of 2000 rigs. One issue identified with the low natural gas prices and focal shift toward more oil-based assets was the trend of operators’ outspending cash flow and accumulating debt.

• 2014 16: This phase saw the longest and one of the deepest downturns in oil prices, primarily driven by a growing supply glut. The 70% price drop between mid-2014 and early 2016 was one of the three most significant declines since World War II and the longest lasting since the supply-driven collapse of 1986. The initial drop in prices was primarily driven by oversupply with booming US shale oil production, a slowdown in global economic activity resulting in reduced oil imports, and other geopolitical concerns. In addition, drilling and completion efficiency gains reduced the breakeven prices considerably, making the US shale oil the de facto marginal cost producer on the international oil market (Stocker, Baffes, & Vorisek, 2018).

With the WTI oil price falling below $50 per barrel, concerns arose regarding the sustainability of shale resource development. Heavy debt and high capital requirements for continued shale development put pressure on the operators’ annual budgets and capital allocation process. Limited capital was deployed for the development of new (noncore) shale plays.

As shale plays matured, the shale development advanced to the next stage of hydrocarbon recovery. In 2015, EOG was the first company that reported successful pilot testing of gas injection EOR in the Eagle Ford Shale. Few other operators, including BHP Billiton, Marathon Oil, etc., have conducted field pilots in different shale reservoirs since then.

• 2017 Current: In early 2017, the oil market was in a situation in which supply was persistently higher than the demand. Short-term prices were very volatile and difficult to predict. The operators have built up a new inventory of drilled uncompleted wells (DUCs) as the rig count recovery outpaced completion activity. If the commodity prices were to decrease further, these DUCs would still be commercially viable for completion as the drilling costs were considered sunk costs. In 2018, OPEC plus helped bring the market back into supply-demand equilibrium.

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However, other geopolitical factors worldwide resulted in surplus production, causing the WTI prices to fluctuate between $45 and $65 per barrel for most of this phase. While the downturn in prices served as an opportunity for the operators to improve cost structure by further enhancing drilling and completion designs and efficiencies, the shale industry witnessed several consolidations across different plays amidst bankruptcy filings from small to large-size operators.

The covid-19 pandemic caused an unprecedented decline in the global oil demand, leading to a historic market collapse in oil prices. The oversupply of crude oil resulted in the WTI oil price plummeting from $18 per barrel to $37 per barrel for a short period in April 2020. The oil prices rebounded with the demand recovering after the lockdowns were lifted, OPEC agreeing to significant cuts in crude oil production, and global economic activity recovering later in the year. So far in 2021, operators have shown capital discipline focusing on cash flow distribution for the shareholders. In addition, operators have discussed concentrating on debt reduction and high-grading portfolios. The United States shale industry has survived the commodity price crash and Covid-19 pandemic and has emerged more resilient from the slump in recent years.

1.3 Conventional versus unconventional reservoirs One of the earliest distinctions of conventional and unconventional resources was made by the legal designation of specified gas resources for tax breaks in the United States. To reduce the country’s reliance on crude oil imports and achieve the goal of energy independence, the United States Congress has passed several statutes over the decades that promote the development of “alternative” energy resources outside the conventional oil reservoirs. The 1980 Crude Oil Windfall Profit Tax Act provided an additional tax break incentive of $3 (in 1979 dollars) per barrel of oil equivalent to stimulate the development of alternative energy resources such as oil shale, natural gas, etc. (Andrews, 2006). In the petroleum industry, these alternative energy resources were later known as “unconventional” to distinguish them from their taxable conventional counterparts. Most of these tax credits were used for the development of tight gas, coal bed methane, and shale gas projects (Campagna, 2015).

Geologically, the establishment of a petroleum system is essential for the accumulation, entrapment, and production of hydrocarbons. The conventional petroleum systems typically require the five key elements of mature source rock, migration pathway, reservoir rock, trap, and seal for hydrocarbon accumulation to be present.

The hydrocarbons were generated when the organic material in the source rock, usually shale or limestone, was subjected to heat and pressure over time. Migration refers to the movement of hydrocarbons from the source rock to porous and permeable reservoir rock and is critical to the formation of the conventional petroleum system. The impermeable seal and trap act as a barrier to prevent fluid migration beyond the

Field development and asset management

reservoir. Ultimately, the migration of hydrocarbons in conventional accumulations (structural or stratigraphic traps) is driven by the gravitational segregation and buoyancy forces, resulting in vertical segregation of gas, oil, and water within the reservoir (Fig. 1.5). With porosities usually around 10% or higher, the fluid flow in porous media follows Darcy’s law. These hydrocarbon accumulations are geographically discrete and are referred to as discontinuous accumulations.

In contrast, unconventional petroleum systems, such as shale and coal bed methane, act as self-sourced and self-sealed reservoirs. Traps have no effect on hydrocarbon accumulation, and migration is unnecessary. These are usually thick, laterally extensive, and continuous deposits of hydrocarbons. With much lower porosity and submicro to nano-Darcy permeability, a combination of horizontal wells and multistage hydraulic fracturing is required for the economic exploitation of the play. The production mechanisms are dominated by the small pore throat sizes and gas adsorbed to the kerogen matrix in these organic-rich reservoirs. With small pores, it is commonly believed that Darcy’s law may not be applicable and that the flow occurs due to advection or diffusion. Additionally, the shale formations are commonly believed to be naturally fractured, and would interact with created hydraulic fractures during stimulation and impact the stimulated rock volume and reservoir drainage during production.

Another way to explain the difference between conventional and unconventional reservoirs is through the Petroleum Resource Triangle, originally provided by Masters (1979). The conventional resources, the apex of the resource triangle (Fig. 1.6),

Figure 1.5 Schematic of conventional and unconventional (shale, coal bed methane, oil shale) hydrocarbon accumulations (Sonnenberg and Meckel, 2017).

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Figure 1.6 Petroleum Resource Triangle. (Modified from McKenzie-Brown, 2018).

represent small volumes of hydrocarbons accumulations in structural or stratigraphic traps that are easy to develop. As we move toward the unconventional resources, the base of the triangle, these represent large volumes that are difficult to develop due to increased operating challenges and would require improved technology, and would be more expensive to develop. The resources retained in the source rocks (shale and coal bed methane formations) account for approximately 50% of all remaining hydrocarbon resources. The word “unconventional” refers to shale gas, shale oil, coal bed methane (aka coal seam gas in Australia), and gas hydrates; the focus of this chapter (and this book) is on shale oil and shale gas production.

Cander (2012) argued that Petroleum Resource Triangle defines unconventional reservoirs qualitatively as difficult resources to develop. He delineated the conventional and unconventional reservoirs based on the rock and fluid properties—rock permeability (k), fluid viscosity (μ), and reservoir pressure—which are critical for understanding the hydrocarbon fluid mobility in oil and gas reservoirs. Carter plotted permeability vs. viscosity and defined unconventional reservoirs quantitively as resources in which technology must be used to increase the mobility ratio (k/μ) in order to achieve commercial flow rates (Fig. 1.7).

1.4 Asset management Managing the entire life cycle of oil and gas fields requires the collaboration of multidisciplinary teams equipped to understand the geological and engineering data, estimate hydrocarbon-in-place, and then create a plan to develop the field economically based on the expected production. The oil and gas fields usually have a life cycle of 30 60 years, from first hydrocarbon production to abandonment. For conventional field development, the E&P life cycle encompasses five major phases from exploration to field abandonment (Salazar, 2019):

Field development and asset management

Figure 1.7 Delineation of conventional and unconventional resources based on fluid mobility. (Modified from Cander, 2012).

• Preexploration: Before exploration, oil and gas companies focus on acquiring limited acreage where public or private data indicates the possibility of hydrocarbons being trapped or where commercial petroleum deposits have already been found.

The signing of a land contract and acreage acquisition is the milestone to move to the exploration phase.

• Exploration: This phase aims to identify the likelihood of hydrocarbon deposits in the subsurface and estimate how much oil and gas may be present. Usually, the exploration phase starts a few years before the first exploration well can be drilled.

Once the acreage has been acquired and is available for exploration activities, a team of geologists and geophysicists work together to map the oil and gas prospect (s) by acquiring and processing the detailed G&G (Geology and Geophysics) data, including the 2D and 3D seismic data, airborne magnetic survey, geochemical survey, etc. The data collected is then evaluated to identify a subsurface geological formation likely to produce hydrocarbons. Justification for drilling an exploration well is made by assembling geoscience and engineering evidence of the existence of an active petroleum system with a reasonable probability of encountering quality-reservoir rock, a trap of sufficient size, adequate sealing rock, and appropriate conditions for generation and migration of hydrocarbons to fill the trap. An initial exploration well is then planned to obtain additional subsurface information, including reservoir tops and depths, rock and fluid properties, production rates, and pressures by collecting well logs, mud logs, pressure and temperature gauges, etc.

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