What is Hydraulic Fracturing?
Oil and natural gas, which are hydrocarbons, reside in the pore spaces between grains of rock (called reservoir rock) in the subsurface. If geologic conditions are favorable, hydrocarbons flow freely from reservoir rocks to oil and gas wells. Production from these rocks is traditionally referred to as “conventional” hydrocarbon reservoirs. However, in some rocks, hydrocarbons are trapped within microscopic pore space in the rock. This is especially true in fine-grained rocks, such as shales, that have very small and poorly connected pore spaces not conducive to the free flow of liquid or gas (called low- permeability rocks). Natural gas that occurs in the pore spaces of shale is called shale gas. Some sandstones and carbonate rocks (such as limestone) with similarly low permeability are often referred to as “tight” formations. Geologists have long known that large quantities of oil and natural gas occur in formations like these (often referred to as tight oil or gas). Hydraulic fracturing can enhance the permeability of these rocks to a point where oil and gas can economically be extracted.
Hydraulic fracturing (also known colloquially as “fracing,” or “fracking,”) is a technique used to stimulate production of oil and gas after a well has been drilled . It consists of injecting a mixture of water, sand, and chemical additives through a well drilled into an oil- or gas-bearing rock formation, under high but controlled pressure. The process is designed to create small cracks within (and thus fracture) the formation, and propagate those fractures to a desired distance from the well bore by controlling the rate, pressure, and timing of fluid injection. Engineers use pressure and fluid characteristics to restrict those fractures to the target reservoir rock, typically limited to a distance of a few hundred feet from the well. Proppant (sand or sometimes other inert material such as ceramic beads) is carried into the newly formed fractures to keep them open after the pressure is released and allow fluids (generally hydrocarbons) that were trapped in the rock to flow through the fractures more efficiently. Some of the water/chemical/proppant fracturing fluids remain in the subsurface. Some of this fluid mixture (called “flowback water”) returns to the surface, often along with oil, natural gas, and water that was already naturally present in the producing formation. This natural formation water is known as “produced water” and much of it is highly saline . The hydrocarbons are separated from the returned fluid at the surface, and the flowback and produced water is collected in tanks or lined pits. Handling and disposal of returned fluids has historically been part of all oil and gas drilling operations, and is not exclusive to wells that have been hydraulically fractured. Similarly, proper well construction is an essential component of all well-completion operations, not only wells that involve hydraulic fracturing. Well completion and construction, along with fluid disposal, are inherent to oil and gas development, and are specifically addressed in this paper because of concern about them and their relationship to hydraulic fracturing.
Hydraulic fracturing of shales and other tight rocks typically is through horizontal or directional (non-vertical) drilled wells which typically involve longer boreholes and much greater volumes of water than conventional oil and gas wells.
Hydraulic Fracturing’s History and Role in Energy Development
Hydraulic fracturing has been commercially applied since the 1940s. Over a million wells in the U.S. have been subjected to hydraulic fracturing, most of them conventional vertical oil and gas wells . Hydraulic fracturing became even more important in the 1990s, when improved technology allowed its application to horizontal wells in developing tight gas and oil reservoirs, particularly for shales. The technological combination of hydraulic fracturing, the chemistry of the fracturing fluid, and the use of horizontal wells is rapidly evolving. Traditional wells are drilled vertically (usually several thousand feet) and penetrate only a few tens or hundreds of feet of the reservoir rock. Horizontal wells start vertically, but then at a kickoff point are directed laterally (or horizontally) within the reservoir rock. The horizontal legs of these wells may extend as much as 10,000 feet through a reservoir rock, thus accessing a far greater volume of the reservoir than a traditional vertical well that only taps one vertical thickness of the reservoir rock. This replaces the need for multiple, vertical wells spaced closely on the land surface to tap the same reservoir volume. Because multiple wells can be drilled from one horizontal well pad, this further decreases the total amount of land needed for the drilling platform (called the “footprint”) and subsequent surface production equipment, although a horizontal well pad is typically much larger than a traditional vertical well pad. Because horizontal wells have both a vertical and a horizontal leg, and more contact with the reservoir rock than a traditional vertical well, horizontal wells typically require a larger volume of water than traditional vertical wells. This may be due to larger volumes of oil produced and not just the hydraulic fracturing requirements; one study compared the ratio of water use to oil produced for two different shale plays and found it was within the typical range for vertical, conventional oil wells over their lifespans. In a horizontal well, hydraulic fracturing usually occurs sequentially in several stages along the horizontal well bore (these are sometimes referred to as “staged treatments”), generally 10 to 15 pumping intervals, and sometimes as many as 50. Hydraulic fracturing of each stage may last from 20 minutes to four hours to complete .
In the past three decades, hydraulic fracturing has been increasingly used in formations that were known to be rich in natural gas that was locked so tightly in the rock that it was technologically and economically difficult to produce. The application of hydraulic fracturing to tight sands revitalized old fields and allowed establishment of new fields. Subsequently, the application of hydraulic fracturing to shale opened up huge new areas to development, including the Marcellus Shale in the eastern U.S, the Barnett Shale in Texas, and the Fayetteville Shale in Arkansas. The rise in production of natural gas from these and other shale plays was dramatic, to the point that natural gas prices have dropped and become more stable. Natural gas has become a major source of electrical power, and the U.S. may become a net natural gas exporter, if markets and regulations are favorable.
While hydraulic fracturing has had a huge impact on natural gas production, the same techniques have been applied to oil fields, leading to increased production from formations such as the Bakken and Three Forks Formations in North Dakota and Montana, and the Eagle Ford Formation in Texas. U.S. oil production from tight formations grew rapidly over the past several years. Future growth projections are uncertain, as the industry is influenced by global demand, prices, a social license to operate, regulations, well production life spans, and technological improvements that increase the percentage of recoverable hydrocarbons.
Fluids used in hydraulic fracturing are a mixture of water, proppant, and chemical additives. Additives typically include gels to carry the proppant into the fractures, surfactants to reduce friction, hydrochloric acid to help dissolve minerals and initiate cracks, inhibitors against pipe corrosion and scale development, and biocides to limit bacterial growth. The exact mix of additives depends on the formation to be fractured. Chemical additives typically make up about 0.5% by volume of well fracturing fluids, but may be up to 2%. Some potential additives are harmful to human health, even at very low concentrations. Unless diesel is used, the fracturing fluids are not regulated by the Safe Drinking Water Act (SDWA). Underground disposal of oil and gas wastes, however, is regulated by the SDWA.
Potential pathways for the fracturing fluids to contaminate water include surface spills prior to injection, fluid migration once injected, and surface spills of flowback and produced water. Because the fracturing fluids are injected into the subsurface under high pressure, and because some of the fluids remain underground, there is concern that this mixture could move through the well bore or fractures created in the reservoir rock by hydraulic pressure, and ultimately migrate up and enter shallow formations that are sources of freshwater (aquifers). There is also concern that geologic faults, previously existing fractures, and poorly plugged, abandoned wells could provide conduits for fluids to migrate into aquifers.
The potential to contaminate groundwater due to hydraulic fracturing is an environmental risk being studied. At present, there have been possibly two confirmed cases of groundwater contamination caused directly by the hydraulic fracturing process; in one location the fractured rock is within 420 feet of the aquifer. One challenge is to distinguish natural contaminants that seep into groundwater unrelated to oil and gas development, from contamination due to oil and gas development. There often are no water quality samples prior to hydraulic fracturing to provide a baseline comparison.
For example, methane has been detected in some water wells in areas with oil and gas development. Some researchers suggested hydraulic fracturing may be responsible for methane in water wells in northeastern Pennsylvania and upstate New York, although leaky well casings is a more likely possibility. In some geologic settings, methane can naturally originate from gas-producing rock layers below and close to the aquifer and be unrelated to the deeper fractured zone. Analysis of the gas can be used to identify the origin of gas occurring in groundwater. In one study of drinking water wells near shale gas well sites in Pennsylvania and Texas, wells were sampled for hydrocarbon gas to determine if contamination had occurred.. The researchers concluded that contamination has locally occurred, and, for those wells with elevated gas levels, the fugitive gas appeared to have migrated from shallower rocks through cracks in the cement around the well (annulus), leaks in the well casing, or from other well failures, rather than from the artificial hydraulic fractures in the reservoir rock. An analysis of a large database on dissolved methane in domestic wells and proximity to pre-existing oil and gas wells in Pennsylvania indicated no statistically significant relationship, although the study had criticism for its industry support for the study.
There have been confirmed cases of groundwater contamination from improperly constructed, oil and gas wells. To protect groundwater, proper well design, construction, and monitoring are essential. During well construction, multiple layers of telescoping pipe (or casing) are installed and cemented in place, with the intent to create impermeable barriers between the inside of the well and the surrounding rock. It is also common practice to pressure test the cement seal between the casing and rock or otherwise examine the integrity of wells. Wells that extend through a rock formation that contains high-pressure gas require special care in stabilizing the well bore and stabilizing the cement or its integrity can be damaged. As with any mechanical device or barrier, failures can occur. There is significant variability in the estimated failure rates of the integrity of oil and gas wells. Local regulations, the technology, the geologic setting and the prevailing operational culture influence the well completion, abandonment and monitoring, and these evolve over time. Differences in the type and sizes of well integrity datasets adds to the challenge of generalizing well integrity failure rates.
The physical separation between the relatively shallow freshwater aquifer and the typically much deeper oil- and gas-producing rock layer provides protection to shallow aquifers. Typically there are thousands of feet of mostly low- to very low-permeability rock layers between an aquifer and oil or gas reservoir rocks that prevent fracturing fluids and naturally migrated hydrocarbons from reaching the aquifer. In areas where there is concern about faults, fractures, or plugged wells, various geophysical methods can be used to locate and avoid faults, although such surveys are time consuming and expensive. There is also renewed interest in the need to locate and plug abandoned or “orphaned” oil and gas wells, and unused water wells, as a further measure to protect near-surface aquifers. It will also be prudent to develop technologies to monitor deep groundwater. In some regions, identifying and properly plugging all the abandoned wells is a significant undertaking.
Proper storage and disposal of fracturing fluids and produced water is important to ensure that both surface water and groundwater are protected. Most fracturing fluids and produced water are re-injected into Class II wells drilled specifically for deep disposal, treated in wastewater treatment facilities, or recycled. Wastewater treatment facilities, designed primarily for municipal waste, can be overwhelmed with the volume and treatment of fracturing fluids and produced water; a number will not accept such waste. Disposal wells inject waste water deep into formations that originally produced the oil and gas, or into different formations that generally contain highly saline and otherwise unusable water. Water is generally co-produced in equal or larger volumes than petroleum throughout the life of a well. Fluid handling and disposal are important issues for all oil and gas activity. Appropriate management practices and regulatory oversight help assure that accidental leaks and spills are minimized.
Baseline water-quality testing, carried out prior to oil and gas drilling, helps to document the quality of local natural groundwater and may identify natural or pre-existing contamination, or lack thereof, before oil and gas activity begins. Without such baseline testing, it is difficult to know if contamination existed before drilling, occurred naturally, or was the result of oil and gas activity. Many natural constituents, including methane, elevated chlorides, and trace elements occur naturally in shallow groundwater in oil- and gas-producing areas and are unrelated to drilling activities. The quality of water in private wells is not regulated at the state or federal level, and many owners do not have their well water tested for contaminants. States handle contamination issues differently. For instance, Colorado and Ohio require baseline sampling of wells in oil- and gas-producing regions as part of its regulatory process. Pennsylvania places the presumptive burden of proof on oil and gas companies if groundwater contamination of drinking-water sources is found. In most states, however, such baseline sampling is not required.
Although there is little evidence of groundwater contamination due to hydraulic fracturing itself, there are still many questions about the risks to aquifers with the rapidly expanding industry developing tight oil and gas reservoirs using modern hydraulic fracturing techniques. There are few long term, peer-reviewed scientific studies. The U.S. Environmental Protection Agency’s (EPA) Scientific Advisory Board study Potential Impacts of Hydraulic Fracturing on Drinking Water Resources (projected to be finalized in 2016) will be an important contribution. Local baseline testing of groundwater quality prior to hydraulic fracturing operations can provide valuable data for later assessing claims of contamination.
Contamination risks to surface water during development of tight oil and gas plays has led to increased regulations in some U.S. states. Potential pathways for contamination include surface spills, waste disposal, and surface spreading of well cuttings. A study of the gas shale development in Pennsylvania documented increased chlorides downstream of the waste treatment plant and elevated total suspended solids downstream of shale gas wells. The elevated suspended solids appear related to the land clearing for the well pad, roads, and related infrastructure.
Hydraulic fracturing, particularly when applied to horizontal wells, can use 13 million gallons or more water per well, though two to five million gallons is typical. However, the ratio of “water used” to “oil produced” in hydraulically fractured wells in the Eagle Ford Shale, Texas, and Bakken Shale, North Dakota, is on the low end of what is typically used in a conventional, vertical oil well over the life of the well. The study concluded that the higher water use reflects an increase in oil production, and not that hydraulic fracturing uses more water per unit of oil produced than conventional wells. Water used in oil and gas development is relatively small in comparison to other recurring uses. However, where drilling rates are high, and particularly in water-poor areas, water use for oil and gas development is significant. The U.S. EPA is studying the current and future potential competition between hydraulic fracturing and drinking water supplies in two basins, one humid (Susquehanna River Basin, Pennsylvania) and one semi-arid (Upper Colorado River Basin, Colorado). Water needs 30 years out are based on drilling trends, natural gas production, and population growth.
Drilling companies are working on improved methods to recycle water used in hydraulic fracturing, or to use saline water that is unsuitable for drinking. Many energy companies are treating and reusing produced and flowback water; the feasibility depends on economics, and the quantity, quality, and duration of water generated. Some companies are trying water-free, nonflammable propane fracking fluid. However, because of chemical mixing considerations and costs, freshwater continues to be the preferred and primary source of water for hydraulic fracturing in most areas. In December 2015, the Governor of Oklahoma formed a task force to find economic treatment and uses for the produced water.
Fracturing rocks at great depth frequently becomes suppressed by pressure due to the weight of the overlying rock strata and the cementation of the formation. This suppression process is particularly significant in “tensile” (Mode 1) fractures which require the walls of the fracture to move against this pressure. Fracturing occurs when effective stress is overcome by the pressure of fluids within the rock. The minimum principal stress becomes tensile and exceeds the tensile strength of the material. Fractures formed in this way are generally oriented in a plane perpendicular to the minimum principal stress, and for this reason, hydraulic fractures in well bores can be used to determine the orientation of stresses. In natural examples, such as dikes or vein-filled fractures, the orientations can be used to infer past states of stress.
Most mineral vein systems are a result of repeated natural fracturing during periods of relatively high pore fluid pressure. The impact of high pore fluid pressure on the formation process of mineral vein systems is particularly evident in “crack-seal” veins, where the vein material is part of a series of discrete fracturing events, and extra vein material is deposited on each occasion. One example of long-term repeated natural fracturing is in the effects of seismic activity. Stress levels rise and fall episodically, and earthquakes can cause large volumes of connate water to be expelled from fluid-filled fractures. This process is referred to as “seismic pumping”.
Minor intrusions in the upper part of the crust, such as dikes, propagate in the form of fluid-filled cracks. In such cases, the fluid is magma. In sedimentary rocks with a significant water content, fluid at fracture tip will be steam.
Induced seismicity is an earthquake caused by human activities. One way this can occur is from iInjection of fluids deep into the earth. The increase in underground disposal of produced and flowback water from oil and gas wells are associated with a large increase in triggered small and moderate earthquakes in some regions, such as central and northern Oklahoma . Oil and gas operations are responsible for two types of fluid injection: 1) injection of hydraulic fracturing fluids into the reservoir rock; and 2) disposal of waste fluids through deep well injection.
Hydraulic fracturing imparts pressures of several thousand pounds per square inch on reservoir rocks. The resulting fractures may extend several hundred feet away from the borehole, but generally no more than that due to physical and technological limitations on the hydraulic fracturing process. The hydraulic fracturing process creates very small seismic events or earthquakes. Such microseismicity is generally too small for humans to feel or to cause surface damage, although it can be detected by monitoring instruments that are designed to precisely determine where the fractures have propagated. A number of studies, including one by the National Academy of Sciences, have determined that hydraulic fracturing does not create a significant earthquake risk. Alberta and British Columbia, Canada, have had moderate earthquakes that appear related to the hydraulic fracturing process itself.
Disposal of large volumes of waste fluids produced from hydraulically fractured rocks through deep-well injection has been documented to produce small earthquakes, generally less than magnitude 2.0. However, in areas with high volumes and rates of injection into disposal wells, there have been dramatic increases in earthquakes magnitude 3.0 and greater. Horizontal wells that have been hydraulically fractured typically produce large volumes of waste fluids (produced and flowback water). Deep disposal of any fluids can trigger earthquakes. Most, although not all, of such earthquakes have occurred in areas of long-term or continuous injection of wastewater. Fluids injected near a subsurface fault may reduce the frictional resistance that keeps faults from slipping. These small movements allow energy already stored in brittle rock to be released in earthquakes. In some locations, sites of slowly accumulating forces in the earth resulting from natural geologic processes are already susceptible to seismic events (which is why it is referred to as “triggered seismicity”). The increase in pore pressure on stressed fault surfaces appears to be the main physical reason for injection-induced earthquakes in the central and eastern United States . Deep well injection of fluids has likely caused earthquakes in excess of magnitude 2.0 over the past several decades, including a magnitude 5.7 earthquake in 2011 in Oklahom and a sharp increase of earthquake frequency from 2012 to 2015 in Oklahoma. Kansas has also experienced a marked increase in seismic activity in the last two years, including the state’s largest earthquake recorded at magnitude 4.9 in November 2014. The potential for triggered seismicity with the increasing volume of wastewater disposal is unknown. States are implementing strategies to mitigate risks of induced seismicity associated with disposal injection wells. This includes a screening protocol to determine what response strategies may be appropriate. Mitigation actions can include changing the allowable rates and pressures of injection, partial plugback of the injection well, and stopping all injections and shutting the well.
Hydraulic fracturing is used to increase the rate at which fluids, such as petroleum, water, or natural gas can be recovered from subterranean natural reservoirs. Reservoirs are typically porous sandstones, limestones or dolomite rocks, but also include “unconventional reservoirs” such as shale rock or coal beds. Hydraulic fracturing enables the extraction of natural gas and oil from rock formations deep below the earth’s surface (generally 2,000–6,000 m (5,000–20,000 ft)), which is greatly below typical groundwater reservoir levels. At such depth, there may be insufficient permeability or reservoir pressure to allow natural gas and oil to flow from the rock into the wellbore at high economic return. Thus, creating conductive fractures in the rock is instrumental in extraction from naturally impermeable shale reservoirs. Permeability is measured in the microdarcy to nanodarcy range. Fractures are a conductive path connecting a larger volume of reservoir to the well. So-called “super fracking,” creates cracks deeper in the rock formation to release more oil and gas, and increases efficiency. The yield for typical shale bores generally falls off after the first year or two, but the peak producing life of a well can be extended to several decades.
While the main industrial use of hydraulic fracturing is in stimulating production from oil and gas wells, hydraulic fracturing is also applied:
- To stimulate groundwater wells
- To precondition or induce rock cave-ins mining
- As a means of enhancing waste remediation, usually hydrocarbon waste or spills
- To dispose waste by injection deep into rock
- To measure stress in the Earth
- For electricity generation in enhanced geothermal systems
- To increase injection rates for geologic sequestration of CO2
Since the late 1970s, hydraulic fracturing has been used, in some cases, to increase the yield of drinking water from wells in a number of countries, including the US, Australia, and South Africa.
Hydraulic fracturing has been seen as one of the key methods of extracting unconventional oil and unconventional gas resources. According to the International Energy Agency, the remaining technically recoverable resources of shale gas are estimated to amount to 208 trillion cubic metres (208,000 km3), tight gas to 76 trillion cubic metres (76,000 km3), and coalbed methane to 47 trillion cubic metres (47,000 km3). As a rule, formations of these resources have lower permeability than conventional gas formations. Therefore, depending on the geological characteristics of the formation, specific technologies (such as hydraulic fracturing) are required. Although there are also other methods to extract these resources, such as conventional drilling or horizontal drilling, hydraulic fracturing is one of the key methods making their extraction economically viable. The multi-stage fracturing technique has facilitated the development of shale gas and light tight oil production in the United States and is believed to do so in the other countries with unconventional hydrocarbon resources.
The National Petroleum Council estimates that hydraulic fracturing will eventually account for nearly 70% of natural gas development in North America. Hydraulic fracturing and horizontal drilling apply the latest technologies and make it commercially viable to recover shale gas and oil. In the United States, 45% of domestic natural gas production and 17% of oil production would be lost within 5 years without usage of hydraulic fracturing.
U.S.-based refineries have gained a competitive edge with their access to relatively inexpensive shale oil and Canadian crude. The U.S. is exporting more refined petroleum products, and also more liquified petroleum gas (LP gas). LP gas is produced from hydrocarbons called natural gas liquids, released by the hydraulic fracturing of petroliferous shale, in a variety of shale gas that’s relatively easy to export. Propane, for example, costs around $620 a ton in the U.S. compared with more than $1,000 a ton in China, as of early 2014. Japan, for instance, is importing extra LP gas to fuel power plants, replacing idled nuclear plants. Trafigura Beheer BV, the third-largest independent trader of crude oil and refined products, said at the start of 2014 that “growth in U.S. shale production has turned the distillates market on its head.”
Some studies call into question the claim that what has been called the “shale gas revolution” has a significant macro-economic impact. A study released in the beginning of 2014 by the IDDRI concluded the contrary. It states that, on the long-term as well as on the short-run, the “shale gas revolution” due to hydraulic fracturing in the United States has had very little impact on economic growth and competitiveness. The same report concludes that in Europe, using hydraulic fracturing would have very little advantage in terms of competitiveness and energy security. Indeed, for the period 2030-2035, shale gas is estimated to cover 3 to 10% of EU projected energy demand, which is not enough to have a significant impact on energetic independence and competitiveness.
Hydrofracked shale oil and gas has the potential to alter the geography of energy production in the US. In the short run, in counties with hydrofracturing employment in the oil and gas sector more than doubled in the last 10 years, with spill-overs in local transport-, construction but also manufacturing sectors. The manufacturing sector benefits from lower energy prices, giving the US manufacturing sector a competitive edge. On average, natural gas prices have decreased by more than 30% in counties above shale deposits compared to the rest of the US. Some research has highlighted the negative effects on house prices for properties in the direct vicinity of fracturing wells. Local house prices in Pennsylvania decrease if the property is close to a hydrofracking gas well and is not connected to city water, suggesting that the concerns of ground water pollution are priced by markets.