In This Issue
Spring Issue of The Bridge on Emerging Issues in Earth Resources Engineering
April 14, 2014 Volume 44 Issue 1

Shale Gas: Development Opportunities and Challenges

Friday, April 18, 2014

Author: Mark D. Zoback and Douglas J. Arent

The use of horizontal drilling and multistage hydraulic fracturing technologies has enabled the production of immense quantities of natural gas, to date principally in North America but increasingly in other countries around the world. The global availability of this resource creates both opportunities and challenges that need to be addressed in a timely and effective manner.

There seems little question that rapid shale gas development, coupled with fuel switching from coal to natural gas for power generation, can have beneficial effects on air pollution, greenhouse gas emissions, and energy security in many countries. In this context, shale gas resources represent a critically important transition fuel on the path to a decarbonized energy future. For these benefits to be realized, however, it is imperative that shale gas resources be developed with effective environmental safeguards to reduce their impact on land use, water resources, air quality, and nearby communities.


Geologists have long known that large amounts of organic matter and natural gas are trapped (usually by clay and other fine-grained minerals) in many shale formations. The principal reason these formations have not been exploited is their extremely low permeability (the measure of the ease with which fluids flow through them): on average, it is about 6 orders of magnitude lower than that of conventional oil and gas reservoirs. As a result, commercial production of shale gas did not take off until about a decade ago, when the combination of horizontal drilling and hydraulic fracturing were used extensively in the Barnett Shale in the Ft. Worth/Dallas area of north-central Texas.

Figure 1

To access trapped natural gas, the operator drills a vertical wellbore to near the depth of the shale (Figure 1), typically about 2–3 km (Fisher and Warpinski 2011). During the drilling, steel casing is cemented into the well to stabilize the wall of the wellbore and to prevent well fluids from contaminating the geologic formations being drilled through. It is particularly important to protect shallow aquifers from contamination as these could be a current or future source of potable water. When the well almost reaches the depth of the shale, its direction is deviated as the drilling shifts to progressively higher angles until the wellbore is horizontal through the layer of shale that contains the natural gas. The length of this horizontal section averages about 1.5 km, although this varies by region. Pad drilling is quite common, in which multiple wells (commonly 4 to 12, but as many as 75) are drilled at the same site to optimize the efficiency of drilling operations. This approach also dramatically lowers the amount of land used, new road and pipeline construction, and overall impact on communities.

Once this drilling is completed, the horizontal section is typically fully cased and cemented. (Alternatively, a length of steel tubing is run into the well with attached packers that isolate the sections of the wellbore to be hydraulically fractured.) Small shape charges are then used to perforate the casing in the sections of the well to be hydraulically fractured.

As discussed in detail by King (2012), hydraulic fracturing uses water at elevated pressure to extend fractures through the shale. The fracturing is done in stages, starting at the toe of the well (the most distant part) and working back toward the heel (closest to the vertical section). A wellbore that extends 1.5 km laterally may be hydraulically fractured in 10 to 20 stages spaced more or less evenly along its length.

Fracturing fluids used for shale formations are usually 99 percent water and sand, which is used as a proppant to hold open the hydraulic fractures when the well goes into production. Approximately 1 percent of the fracturing fluid consists of acid, an organic viscosifier (to help suspend the proppant), and other chemicals that reduce friction, prevent growth of microorganisms, and reduce corrosion of the casing.

Because of shale’s extremely low permeability, it is only through the use of horizontal drilling and multistage hydraulic fracturing that commercial quantities of natural gas can be produced. It is worth noting that these technologies are also proving to be quite successful in stimulating oil production in low-permeability oil reservoirs in geologic formations in North America and elsewhere.


A number of gains are already apparent from the widespread development of North American shale gas resources, including the direct economic benefit of jobs created, taxes paid, and overall stimulus associated with development activities and royalty payments to the mineral interest owners. According to IHS (2012), unconventional oil and gas development in the United States is responsible for approximately 1.7 million jobs, $63 billion in federal, state, and local taxes, and an overall contribution to the US economy of $238 billion. IHS predicts that both the number of jobs and economic benefits will roughly double by 2020.

In addition, many other countries that are now heavily dependent on coal for electricity generation are considering development of their domestic shale gas resources (Figure 2).

Figure 2

When natural gas is used for electrical power generation in place of coal it has the potential to reduce postcombustion CO2 emissions by more than 50 percent (see discussion below under Methane Emissions and Greenhouse Gases). Thus a substantial shift from coal to natural gas in China, Australia, South Africa, and countries in Europe could result in a significant reduction in global CO2 emissions.

In the United States, for example, coal-generated electricity produces roughly 2 billion metric tonnes of CO2 annually. But in the past six years a switch from coal to natural gas, along with continued growth in renewables and expansion of energy efficiency measures, has resulted in a 20 percent reduction of CO2 emissions associated with electrical power generation. In China, on the other hand, coal-generated electricity currently produces about 7 billion tonnes of CO2 each year, and growth in energy consumption over the next ~25 years is expected to double these emissions. Preventing such a dramatic increase in emissions should be a first-order global priority among efforts to combat climate change.

Increased natural gas use mitigates air pollution, thanks to the absence of mercury and particulate matter in flue gas as well as significantly reduced sulphur content. It also significantly reduces emissions of NOx (e.g., NO and NO2), approximately 70 percent of which are from oxidation of the nitrogen in the coal. Hence, switching from coal to natural gas would lead to significant health and quality-of-life improvements, especially in large urban centers in the developing world and in coal mining communities.

But to realize the many benefits of enhanced use of natural gas, it is critically important for shale gas resources to be developed safely and in an environmentally responsible and socially acceptable manner.

Challenges: Limiting the Environmental Impacts of Shale Gas Development

Development of shale gas resources is a large-scale industrial process that involves drilling tens of thousands of wells, carrying out hundreds of thousands of hydraulic fracturing operations, and building numerous roads and pipelines. Associated environmental concerns include surface contamination due to spills; localized increases in air pollution resulting from drilling, trucking, and hydraulic fracturing operations; potential contamination of subsurface aquifers by hydraulic fracturing; the use of large quantities of fresh water in arid regions; the safe disposal of wastewater; and the cumulative impact of traffic, drilling operations, and road and pipeline construction on residents and ecosystems. In addition, land disturbance and community issues such as truck traffic raise concerns.

The industrial nature of shale gas development, the rights of owners to access their mineral resources, and the need for reasonable setback distances from residential communities (currently 150 m or less in many jurisdictions) introduce tensions among developers, mineral rights owners, and land owners. Even in traditional oil and gas regions such as Weld County, Colorado, where more than 18,000 wells have been drilled in recent years and most residents have been strongly supportive of the industry, recent activities at the edge of residential communities have given rise to discussions about appropriate setbacks from residential property lines and subdivisions.

Figure 3

Environmental issues generally fall into four main categories—air, land, water, and community (Figure 3)—and shale gas development may affect them all. We address three issues about which there has been widespread concern: potential contamination of groundwater by drilling and hydraulic fracturing operations, earthquakes triggered by injection of flowback water, and methane emissions.

Groundwater Contamination

Most of the wastewater associated with shale gas development is flowback from the shale formation after hydraulic fracturing operations.1 It may contain salt, elements such as selenium, arsenic, and iron, and small amounts of naturally occurring radioactive materials, all of which come from the gas-producing shale formations.

Practices related to water usage and treatment are rapidly evolving and improving. In some areas, for example, nearly all of the flowback water is reused for the hydraulic fracturing of subsequent wells, thus returning the contaminants to the shale formations from which they originated. This reduces both the need for new sources of water and concerns associated with truck traffic and wastewater disposal. In other areas, brackish or saline water is used for drilling and hydraulic fracturing, thus minimizing the use of fresh water.

There is also concern that hydraulic fracturing could facilitate methane migration from the depth of the shale to that of near-surface aquifers. This is not occurring for two reasons. First, the shale gas formations produced to date in North America are quite deep (typically 2,000–3,000 meters deep) and well separated from the much shallower depth of aquifers (typically less than a few hundred meters). The vertical distribution of microseismic events that occur during hydraulic fracturing (Fisher and Warpinski 2011) clearly shows more than 1,000 meters of separation between the shallowest events and the deepest aquifers. Second, once the shale gas wells go into production, the pressure in the shale decreases markedly and the direction of water flow in the rocks above the formation is downward (i.e., into the shale below).

In apparent support of these arguments, detailed studies of groundwater contamination in areas of shale gas development have consistently shown that hydraulic fracturing itself is not the source of the contamination; rather, the contamination appears to result from poor well construction or poor drilling practice (see, for example, Jackson et al. 2012, 2013).

Regarding well construction, King (2012) and King and King (2013) discuss the importance of preventing contamination of aquifers and/or methane leakage and identify many operational issues that require close attention to achieve proper construction. Krupnick and colleagues (2013) surveyed experts from industry, academia, NGOs, and the government about their opinions of the most likely source of accidents leading to environmental impacts. The view of all four groups is that the greatest potential for groundwater contamination is associated with poor well construction (see Figure 5 and Table 16 in Krupnick et al. 2013) and, in particular, failure of the casing and/or cement. To minimize environmental impacts of shale gas development, the Secretary of Energy Advisory Board (SEAB 2011, p. 16) recommended that industry “adopt best practices in well development and construction, especially casing, cementing, and pressure management. Pressure testing of cemented casing and state-of-the-art cement bond logs should be used to confirm formation isolation.”


Although hydraulic fracturing operations very rarely trigger earthquakes, a number of small to moderate earthquakes in recent years appear to be associated with an increase in the rates and volumes of injected flowback water (NRC 2012 and accompanying video at http://youtube/Uuh9lHavdvc). It has been known since the 1960s that the increase in pore pressure that results from injection may trigger seismicity by decreasing the normal stress on potentially active preexisting faults and thus triggering the release of stored elastic strain energy. In effect, the pore pressure increase from fluid injection advances the timing of an earthquake that would eventually have occurred as a natural geologic process.

The permeability and overall capacity of a formation determine the rates and volumes of wastewater that can be injected. There are approximately 150,000 EPA Class II injection wells in the United States that are used for wastewater disposal. In regions without suitable geologic formations for such injection (i.e., regions without laterally extensive porous and permeable saline aquifers at depth), flowback water can be injected back into the shale during subsequent hydraulic fracturing operations (as mentioned above).

When injection wells are used for disposal, some straightforward steps can reduce the probability of triggering seismicity (Zoback 2012), such as avoiding injection into potentially active faults. This seems obvious, but characterization studies are generally not required before siting injection wells. Other steps include managing injection rates to minimize pore pressure increases at depth (i.e., injecting at lower rates in a single well or using multiple injection wells), monitoring pore pressure changes at depth, and installing local seismic monitoring arrays if there are reasons to be concerned about triggering seismicity. In addition, it would be helpful to establish protocols in advance that define how operations should be modified in the event of seismicity. Operators need to be prepared to alter injection operations and, if necessary, abandon an injection well.

Methane Emissions and Greenhouse Gases

The final issue of public concern that we address briefly is air pollution and greenhouse gas (GHG) emissions, specifically emissions from vehicles and engines at drill sites; methane emissions that occur during drilling, hydraulic fracturing, and well production; and emissions associated with transmission and distribution (which are not unique to shale formations and are the subject of considerable study, as detailed below).

Air pollution results from the concentration of diesel engines that run generators and heavy equipment at a drill site and the truck traffic associated with drilling activities. For example, when hydraulic fracturing operations are under way, large diesel engines run at near full capacity almost 24 hours a day. Options are being evaluated for the use of natural gas engines and hybrid natural gas–renewable systems (e.g., taking advantage of local solar or wind resources), particularly for relatively modest power needs such as those for control and monitoring systems and communications.

The accidental release of methane during shale gas development has garnered attention in the academic literature and general media and has become a subject of research. There are two principal approaches to measuring such emissions: bottom up and top down. Bottom-up studies focus on emissions related to the production and delivery of natural gas, normally following the process steps from drilling to well completion. Top-down studies focus on atmospheric measurements and infer emissions from well fields or other sources.

Most of the bottom-up studies have involved modeling or analysis (Logan et al. 2012 and references therein; Alvarez et al. 2012; O’Sullivan and Paltsev 2012; Weber and Clavin 2012); only one used a rigorous inventory (Logan et al. 2012). They typically take a life cycle approach and compare methane emissions on the basis of gCO2/unit energy equivalent to CO2, focusing on the use of natural gas for power generation and thus reporting gCO2eq/MWh (grams of CO2 equivalent per megawatt hour of generation).

A number of these studies were provoked by the claim of Howarth and colleagues (2011) that using shale gas for electrical power generation would cause more climate damage than coal per unit of energy produced. This study has been widely criticized because it did not do a life cycle assessment (for example, it did not include the significant CO2 emission reductions that result from the efficiency of natural gas combustion compared to coal) and it assumed much larger estimates of methane leakage than indicated by other studies (see Burnham et al. 2012; Hultman et al. 2011; Jiang et al. 2011; Laurenzi and Jersey 2013; Stephenson et al. 2011).

Figure 4

A standardized comparison (Figure 4) shows that life cycle assessment (LCA) studies are in general agreement that the GHG intensity of natural gas–derived power is about 50 percent of that of coal-derived power—much lower than suggested by Howarth and colleagues (2011). However, robust, verified data are incomplete, and it is of paramount importance for the scientific community to pursue detailed data collection, verification, and analysis. The best information available, which shows moderate ranges across the LCA studies, should be viewed with caution because of common underlying assumptions and EPA inventories that do not reflect the heterogeneity of shale production across the nation.

Furthermore, nearly all LCA comparisons have used a 100-year global warming potential (introduced by the IPCC [2007]) as a benchmark. Others have proposed alternative indicators (e.g., Alvarez et al. 2012; IPCC 2013), pointing to the utility of metrics for net benefits and emission rates, particularly for the use of natural gas for transportation.

Naturally, it is also important to eliminate leakage in the pipeline and distribution system, as methane leakage to the atmosphere has a significant deleterious effect on global warming. Full climate modeling to assess the long-term (e.g., up to the year 2100) radiative forcing from methane leakage would provide valuable information to help resolve questions and determine appropriate steps.

Top-down studies of potential methane emissions from shale operations typically use atmospheric measurements and a range of techniques to span a wide spatial scale (city to continent) and temporal scale (months to decades). They systematically find larger emissions than predicted by inventory-based LCAs (Petron et al. 2012; Townsend-Small et al. 2012; Wennberg et al. 2012). Although these methods can distinguish biogenic emissions from fossil sources, they cannot identify the source of the fossil methane emissions.

A Path Forward

The development of shale gas resources in an environmentally responsible manner presents a critical opportunity to take a major step toward decarbonizing the global energy system. There is much concern about inexpensive natural gas crowding out renewable energy sources such as wind and solar, but fast startup and efficient combined-cycle natural gas plants will complement such renewable energy resources by providing reliable backup power regardless of the time of day or weather conditions. It is therefore important for countries around the world to implement energy policies that allow for the effective development and use of natural gas while continuing to deploy renewable energy sources.


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1 Numerous publications have addressed water issues related to the availability, quantity, transport, and treatment of produced water (or other aboveground operations) as well as contamination of local aquifers via underground methane contamination (Heilweil et al. 2013; Jackson et al. 2012, 2013; Molofsky et al. 2013; Olmstead et al. 2013; Rahm and Riha 2012; Rahm et al. 2013; Vengosh et al. 2013; Warner et al. 2012).

About the Author:Mark D. Zoback (NAE) is a professor of geophysics at Stanford University. Douglas J. Arent is executive director of the Joint Institute for Strategic Energy Analysis at the National Renewable Energy Laboratory.