Unconventional Shale Gas Development: Lessons Learned

Unconventional Shale Gas Development: Lessons Learned gives engineers the latest research developments and practical applications in today’s operations. Comprised of both academic and corporate contributors, a balanced critical review on technologies utilized are covered. Environmental topics are presented, including produced water management and sustainable operations in gas systems. Machine learning applications, well integrity and economic challenges are also covered to get the engineer up-to-speed. With its critical elements, case studies, history plot visuals and flow charts, the book delivers a critical reference to get today’s petroleum engineers updated on the latest research and applications surrounding shale gas systems.

• Bridges the gap between the latest research developments and practical applications through case studies and workflow charts
• Helps readers understand the latest developments from the balanced viewpoint of academic and corporate contributors
• Considers environmental and sustainable operations in shale gas systems, including produced water management

• Language: English
• Publisher: Elsevier Science
• Release date: Feb 23, 2022
• ISBN: 9780323905299

Book preview

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 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.

Chapter 1

Field development and asset management

Raki Sahai¹,²,    ¹Ascent Resources, Oklahoma City, OK, United States,    ²Mewbourne School of Petroleum and Geological Engineering, The University of Oklahoma, Norman, OK, United States

Abstract

This chapter focuses on the multidisciplinary field development of unconventional shale reservoirs. The chapter begins with the geologic and petrophysical background of shale reservoirs. Next, it covers the history of shale exploration and development trials and events that started with the decline of production from the conventional reservoirs in the mid-1970s and eventually led to the shale gas revolution in the early 2000s. The modern shale gas revolution is chronologically summarized into four main phases from 2003 to the Covid-19 pandemic. The following section compares the asset management and field development of shale plays to conventional reservoirs. The production from shale reservoirs differs from conventional reservoirs primarily due to extremely low permeability and other petrophysical characteristics. Horizontal drilling and hydraulic fracturing are required to increase the contact area and produce hydrocarbons from ultra-tight pores of shale reservoirs in commercial quantities. Finally, the chapter focuses on reserve reporting and reserve-based lending in shale reservoirs.

Keywords

Field development; asset management; economics; reserves reporting

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.

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).

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.

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 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.

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

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 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).

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. 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. 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 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.

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

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), 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.

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

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).

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

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):

• 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. Generally, the exploration phase contains a high level of uncertainty and risk. Historically, two out of three wells turn out to be dry holes in conventional exploration. The exploration phase could take 3–5 years as it involves collecting detailed G&G data.

• Appraisal: Once a successful exploration well (or wildcat) has been drilled and a commercial petroleum discovery has been made, the appraisal and delineation phase is planned to reduce uncertainty further. In this phase, the team of geoscientists and reservoir engineers works together to determine the size, quality, and extent of the geological play and to estimate the hydrocarbons-in-place. This is accomplished by collecting additional data (seismic data and logs) and drilling appraisal wells to complete the initial definition of the reservoir by mapping potential reservoir boundaries. The number of appraisal wells to be drilled depends on the complexity of the reservoir structure and the aerial extent of the reservoir. The appraisal phase can take additional 2–4 years beyond the exploration phase.

• Development: The development phase occurs after the successful completion of the appraisal phase. This phase requires the definition of a detailed field development plan (FDP) to exploit the reservoir effectively and safely to generate an optimum return on investment. The preparation of FDP requires the coordinated efforts and expertise of different disciplines for successful execution during the development and production phases. The information collected during the exploration and appraisal phases is used to determine the optimum well spacing and the number of drilling locations. The drilling, completion, and surface facility designs, along with the pace of field development (drilling rig and completion crew activity), are optimized based on the takeaway capacity for the field and the commodity pricing. The development phase usually lasts a few years and is dependent on the pace of field development.

The success of the FDP depends on the reservoir size, complexity, productivity, and the hydrocarbon fluid type and quantity. Usually, a combination of geological and reservoir numerical simulation models is used to define the geological system, assign petrophysical properties, and run fluid flow simulations to estimate rates and recoveries based on the development assumptions. These models are continuously updated as more field data becomes available during the development and production phases. The FDP is then used on evaluating multiple development options for operating the field and selecting the one based on assessing tradeoffs among various factors (Salazar, 2019):

• Technical hydrocarbon recoveries

• One or more financial metrics, such as Net Present Value (NPV), Rate of Return (ROR), Payback Period, or Profitability Index (i.e., the ratio between the present value of future expected cash flows and the initial investment amount)

• Capex versus Opex cost profiles

• Operational flexibility and scalability

• Technical, operating, and financial risks

•Production: During this phase, the oil and gas production rates are expected to ramp up to maximum takeaway capacity for the field and are kept reasonably flat by drilling additional development wells. As the natural drive mechanism for the field is exhausted, the development plan may require additional in-fill drilling campaigns, recompletions, EOR, or additional surface pipeline compression to sustain the production rates flat. Eventually, the field production starts to decline and reaches the economic limit of the field. Depending on the hydrocarbon resource size, the production phase may last for 25–40 years. Among the four phases, the production phase is the best for positive cash flow and profitable return of investment.

•Field abandonment: Once the field production reaches its economic limit, the wells are plugged and abandoned, the surface facilities are removed according to the land reclamation regulations, and the field is abandoned.

Conventional reservoir exploration and development resemble high-risk/high-reward investments, which involve drilling many dry holes in search of a few highly productive ones. This stands in stark contrast to unconventional reservoir development, which resembles a manufacturing process. In shale plays, once the play is delineated using the seismic data and a few exploratory/appraisal wells, the development phase can start a lot sooner than in a conventional play. In the case of resource plays, such as shale, the key elements for technical success include:

• thermal maturity,

• high Total Organic Content (5%–15%),

• porosity and permeability of rock matrix,

• the thickness of the formation,

• rock brittleness (or fraccability) with high Young’s modulus and low Poisson’s ratio,

• characteristics of natural fractures (frequency and properties—calcite-filled, open, etc.), and

• low structural complexity (simplicity).

Given the heterogeneities and complexities of shale formations, there are sweet spots within each play that are more productive and produce the highest return on investment using the currently available technology. The abundance of shale reserves in the United States also helped with the simultaneous development of various technologies as every shale play is unique from a depositional environment to differences in rock and fluid properties, and therefore required a fit-for-purpose development strategy.

Other commercial and economic factors which contributed to the success of the shale industry boom in the United States include:

• Private mineral ownership: private ownership of subsurface rights provided a strong incentive for landowners to see shale development accelerate; operators received quicker access to large acreage to develop and test technological innovations and obtain reasonable returns on their investments.

• Availability of water resources: hydraulic fracturing using slick water fluid requires a few million gallons of water to stimulate each well. In the United States, water needed for fracturing was generally readily available. As the development matured, there were water shortages in some plays; however, the industry responded with the re-use of produced water during well flow back.

• Pipeline/takeaway infrastructure: commercial exploitation requires takeaway capacities to markets or refineries. The United States already had an extensively developed pipeline network to transport natural gas to market before shale gas became a major gas resource. Also, transport of crude oil via rail and trucking was present from conventional hydrocarbon exploration and development.

• Availability of many independent E&P operators and expertise of service companies.

• Financial investment: Operators had significant support from the financial industry with access to public and private equity money, reserve-based loans, etc.

• The continued increase in oil and gas demand with population and economic growth.

• High commodity prices: improved oil and gas prices during the early shale development further facilitated the growth of the shale industry.

1.4.1 Field development plan for shale plays

Once the play is in the development stage, a detailed FDP is prepared to efficiently recover hydrocarbons from the subsurface while maximizing an economic criterion such as ROR, NPV, etc. The preparation of FDP requires the coordinated efforts of a multidisciplinary team of land professionals, geoscientists, reservoir, drilling, completion, production, and facility engineers for successful execution in the field. It comes down to a two-step process: (1) maximizing hydrocarbon recovery from the subsurface, and (2) maximizing the Net Asset Value (NAV) by optimizing the drilling and fracturing activity. The different elements which feed into the FDP include: the horizontal well placement and spacing; drilling and completion—designs, cycle time and associated capital; expected production profile for type wells; drilling location inventory (well counts) by type curve; operating costs; midstream takeaway capacities; and commodity prices. The economics are highly dependent on the commodity prices and the activity schedule, both of which would impact the drilling rig(s) and frac crew(s) needed for development.

• Horizontal well placement: this includes the lateral orientation (relative to North), wellbore inclination (toe up, toe down, or straight wellbore), and stratigraphic landing within the formation to maximize the contact area and hydrocarbon production from the zone of interest.

The lateral orientation is an important parameter that needs to be decided during the appraisal or early development phase as it impacts the resultant hydraulic fracture network and the SRV. The horizontal well can be oriented throughout the 360-degree rotation (unless governed by regulatory regulations); however, the hydraulic fracture direction is dictated by the current in situ stress state and propagates parallel to the maximum horizontal stress. If the wellbore is oriented parallel to the maximum horizontal stress, the hydraulic fracture will propagate along the wellbore and is referred to as a longitudinal fracture (Fig. 1.8). If the wellbore is oriented perpendicular to the maximum horizontal stress, the hydraulic fracture will propagate normal to the wellbore and is referred to as a transverse fracture. If the wellbore deviates from the two horizontal stress directions, the resulting fracture will oblique the wellbore and is referred to as an oblique fracture. Out of three possible fracture geometries, transverse fractures are more effective in draining the low-permeability shale reservoirs due to increased contact area with the reservoir matrix. In addition to resulting in smaller SRV, the wellbore with oblique fractures can have increased drilling risk due to smaller safe mud weight window, and also encounter higher breakdown pressure during stimulation due to the reorientation of the hydraulic fracture away from the wellbore (Wutherich, Xu, Walker, Sawyer, & Aso, 2013; Zinn, Blood, & Morath, 2011).

• Lateral (or well) spacing: this is another important parameter for full-field development as it directly impacts the hydrocarbon recovery and the capital costs required for the development. In multifractured horizontal wells, the optimal lateral spacing is generally tied to the fracture treatment design and the resultant SRV. A well spacing tighter than the SRV extent could result in overcapitalization to develop the field; however, it could help accelerate production and cash flows during high commodity prices. Conversely, well spacing larger than the SRV extent could result in delayed hydrocarbon production from the matrix beyond fracture tips, and in some cases, leave behind undrained reserves.

• Fracture geometry: typically, the hydraulic fracture network generated during stimulation is reported at four scales:

• Microseismically-mapped fracture geometry refers to the fracture geometry mapped using far-field fracture diagnostic techniques, such as microseismic mapping. The dimensions could be the same or, in most instances, greater than the created hydraulic fracture geometry due to rock slippage or fault activation around the hydraulic fractures (Warpinski, Mayerhofer, Agarwal, & Du, 2013).

• Created or hydraulic fracture geometry refers to the fracture geometry generated due to the injection of fracturing fluid.

• Propped fracture geometry is the fracture network supported by the injected proppant after the fracture closes, and is dependent on the proppant carrying properties of the fracturing fluid.

• And lastly, producing or effective fracture geometry refers to the fracture network that is open or contributing to hydrocarbon production after the fracture closes.

Figure 1.8 Hydraulic fracture orientation relative to horizontal well (in red). (Modified from Yang, 2014).

The SRV or fracture network shrinks over time, from hydraulic/created lengths to effective lengths, as the well is flowed back and put on production (Cipolla, Lolon, & Mayerhofer, 2008). Therefore, for determining the lateral (or well) spacing, effective fracture length should be used as it generally represents the drainage area for the well. Based on the matrix permeability, the drainage area may extend beyond the fracture tips, but usually, it is restricted to few inches to few feet only.

• Drilling and completion designs, cycle time, and associated capital: drilling and completion designs impact the cycle times and capital required, which increases with lateral length. As the designs are optimized based on the additional data collected later, the capital and cycle times are updated in the model to reflect the revised cash