||This article may be excessively focused toward the subject's advocacy or opinions. Wikipedia articles should concentrate on factual information. (October 2013)|
Schematic depiction of hydraulic fracturing for shale gas.
|Main technologies or sub-processes||Fluid pressure|
|Inventor||Floyd Farris; J.B. Clark (Stanolind Oil and Gas Corporation)|
|Year of invention||1947|
Hydraulic fracturing is the fracturing of rock by a pressurized liquid. Some hydraulic fractures form naturally—certain veins or dikes are examples. Induced hydraulic fracturing or hydrofracturing, commonly known as fracking, is a technique in which typically water is mixed with sand and chemicals, and the mixture is injected at high pressure into a wellbore to create small fractures (typically less than 1mm), along which fluids such as gas, petroleum, uranium-bearing solution, and brine water may migrate to the well. Hydraulic pressure is removed from the well, then small grains of proppant (sand or aluminium oxide) hold these fractures open once the rock achieves equilibrium. The technique is very common in wells for shale gas, tight gas, tight oil, and coal seam gas and hard rock wells. This well stimulation is usually conducted once in the life of the well and greatly enhances fluid removal and well productivity, but there has been an increasing trend towards multiple hydraulic fracturing as production declines. A different technique where only acid is injected is referred to as acidizing.
The first experimental use of hydraulic fracturing was in 1947, and the first commercially successful applications were in 1949. George P. Mitchell is considered by some the modern "father of fracking" because he successfully applied it to the Barnett Shale in the 1990s. As of 2010, it was estimated that 60% of all new oil and gas wells worldwide were being hydraulically fractured. As of 2012, 2.5 million hydraulic fracturing jobs have been performed on oil and gas wells worldwide, more than one million of them in the United States. Uranium Energy Corporation is planning to use hydraulic fracturing to mine uranium. Fracking for uranium involves injecting oxygenated water (to increase solubility) to dissolve the uranium, then pumping the solution back up to the surface.
Proponents of hydraulic fracturing point to the economic benefits from the vast amounts of formerly inaccessible hydrocarbons the process can extract. Opponents point to potential environmental effects, including contamination of ground water, depletion of fresh water, risks to air quality, noise pollution, the migration of gases and hydraulic fracturing chemicals to the surface, surface contamination from spills and flow-back, and the health effects of these. For these reasons hydraulic fracturing has come under international scrutiny, with some countries suspending or banning it. However, some of those countries, including most notably the United Kingdom, have recently lifted their bans, choosing to focus on regulations instead of outright prohibition. The 2013 draft EU-Canada trade treaty includes language outlawing any "breach of legitimate expectations of investors" which may occur if revoking drilling licences of Canada-registered companies in the territory of the European Union after the treaty comes into force. Under Chapter 11 of the existing North American Free Trade Agreement, private companies can sue governments when new laws reduce expected profits from existing contracts.
- 1 Geology
- 2 Induced hydraulic fracturing
- 3 Economic Effects
- 4 Environmental impact
- 5 Health Effects
- 6 Public debate
- 7 See also
- 8 References
- 9 External links
Fracturing in rocks at depth tends to be suppressed by the confining pressure, due to the immense load caused by the overlying rock strata and the cementation of the formation. This is particularly so in the case of "tensile" (Mode 1) fractures, which require the walls of the fracture to move apart, working against this confining pressure. Hydraulic fracturing occurs when the effective stress is overcome sufficiently by an increase in the pressure of fluids within the rock, such that the minimum principal stress becomes tensile and exceeds the tensile strength of the material. Fractures formed in this way will in the main be oriented in the plane perpendicular to the minimum principal stress and for this reason induced hydraulic fractures in well bores are sometimes 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 hydraulic fracturing of the rock during periods of relatively high pore fluid pressure. This is particularly noticeable in the case of "crack-seal" veins, where the vein material can be seen to have been added in a series of discrete fracturing events, with extra vein material deposited on each occasion. One mechanism to demonstrate such examples of long-lasting repeated fracturing is the effect of seismic activity, in which the stress levels rise and fall episodically and large volumes of connate water may be expelled from fluid-filled fractures during earthquakes. This process is referred to as "seismic pumping".
Low-level minor intrusions such as dikes propagate through the crust in the form of fluid-filled cracks, although in this case the fluid is magma. In sedimentary rocks with a significant water content the fluid at the propagating fracture tip will be steam.
Fracturing as a method to stimulate shallow, hard rock oil wells dates back to the 1860s. It was applied by oil producers in the US states of Pennsylvania, New York, Kentucky, and West Virginia by using liquid and later also solidified nitroglycerin. Later, the same method was applied to water and gas wells. The idea to use acid as a nonexplosive fluid for well stimulation was introduced in the 1930s. Due to acid etching, fractures would not close completely and therefore productivity was enhanced.
Hydraulic fracturing in oil and gas wells
The relationship between well performance and treatment pressures was studied by Floyd Farris of Stanolind Oil and Gas Corporation. This study became a basis of the first hydraulic fracturing experiment, which was conducted in 1947 at the Hugoton gas field in Grant County of southwestern Kansas by Stanolind. For the well treatment 1,000 US gallons (3,800 l; 830 imp gal) of gelled gasoline (essentially napalm) and sand from the Arkansas River was injected into the gas-producing limestone formation at 2,400 feet (730 m). The experiment was not very successful as deliverability of the well did not change appreciably. The process was further described by J.B. Clark of Stanolind in his paper published in 1948. A patent on this process was issued in 1949 and an exclusive license was granted to the Halliburton Oil Well Cementing Company. On March 17, 1949, Halliburton performed the first two commercial hydraulic fracturing treatments in Stephens County, Oklahoma, and Archer County, Texas. Since then, hydraulic fracturing has been used to stimulate approximately a million oil and gas wells in various geologic regimes with good success.
In contrast with the large-scale hydraulic fracturing used in low-permeability formations, small hydraulic fracturing treatments are commonly used in high-permeability formations to remedy skin damage at the rock-borehole interface. In such cases the fracturing may extend only a few feet from the borehole.
In the Soviet Union, the first hydraulic proppant fracturing was carried out in 1952. Other countries in Europe and Northern Africa to use hydraulic fracturing included Norway, Poland, Czechoslovakia, Yugoslavia, Hungary, Austria, France, Italy, Bulgaria, Romania, Turkey, Tunisia, and Algeria.
Massive hydraulic fracturing
Pan American Petroleum applied the first massive hydraulic fracturing (also known as high-volume hydraulic fracturing) treatment in Stephens County, Oklahoma, USA in 1968. The definition of massive hydraulic fracturing varies somewhat, but is generally used for treatments injecting greater than about 150 short tons, or approximately 330,000 pounds (136 metric tonnes), of proppant.
American geologists became increasingly aware that there were huge volumes of gas-saturated sandstones with permeability too low (generally less than 0.1 millidarcy) to recover the gas economically. Starting in 1973, massive hydraulic fracturing was used in thousands of gas wells in the San Juan Basin, Denver Basin, the Piceance Basin, and the Green River Basin, and in other hard rock formations of the western US. Other tight sandstones in the US made economic by massive hydraulic fracturing were the Clinton-Medina Sandstone, and Cotton Valley Sandstone.
Massive hydraulic fracturing quickly spread in the late 1970s to western Canada, Rotliegend and Carboniferous gas-bearing sandstones in Germany, Netherlands onshore and offshore gas fields, and the United Kingdom sector of the North Sea.
Horizontal oil or gas wells were unusual until the 1980s. Then in the late 1980s, operators in Texas began completing thousands of oil wells by drilling horizontally in the Austin Chalk, and giving massive slickwater hydraulic fracturing treatments to the wellbores. Horizontal wells proved much more effective than vertical wells in producing oil from the tight chalk; the shale runs horizontally so a horizontal well reached much more of the resource. In 1991, the first horizontal well was drilled in the Barnett Shale and in 1996 slickwater fluids were introduced.
Massive hydraulic fracturing in shales
Due to shale's low porosity and low permeability, technological research, development and demonstration were necessary before hydraulic fracturing could be commercially applied to shale gas deposits. In 1976 the United States government started the Eastern Gas Shales Project, a set of dozens of public-private hydraulic fracturing pilot demonstration projects. During the same period, the Gas Research Institute, a gas industry research consortium, received approval for research and funding from the Federal Energy Regulatory Commission.
In 1997, based on earlier techniques used by Union Pacific Resources, now part of Anadarko Petroleum Corporation, Mitchell Energy, now part of Devon Energy, developed the hydraulic fracturing technique known as "slickwater fracturing" which involves adding chemicals to water to increase the fluid flow, that made the shale gas extraction economical.
As of 2013, in addition to the United States several countries are planning to use hydraulic fracturing for unconventional oil and gas production.
Induced hydraulic fracturing
According to the United States Environmental Protection Agency (EPA) hydraulic fracturing is a process to stimulate a natural gas, oil, or geothermal energy well to maximize the extraction. The broader process, however, is defined by EPA as including the acquisition of source water, well construction, well stimulation, and waste disposal.
The technique of 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 production of natural gas and oil from rock formations deep below the earth's surface (generally 5,000–20,000 feet (1,500–6,100 m)), which is typically greatly below groundwater reservoirs of basins if present. At such depth, there may not be sufficient permeability or reservoir pressure to allow natural gas and oil to flow from the rock into the wellbore at economic rates. Thus, creating conductive fractures in the rock is pivotal to extract gas from shale reservoirs because of the extremely low natural permeability of shale, which is measured in the microdarcy to nanodarcy range. Fractures provide a conductive path connecting a larger volume of the reservoir to the well. So-called "super fracking," which creates cracks deeper in the rock formation to release more oil and gas, will increase efficiency of hydraulic fracturing. The yield for a typical shale gas well generally falls off after the first year or two, although the full producing life of a well can last several decades.
- To stimulate groundwater wells
- To precondition or induce rock to cave in mining
- As a means of enhancing waste remediation processes, usually hydrocarbon waste or spills
- To dispose of waste by injection into deep rock formations
- As a method to measure the stress in the Earth
- For heat extraction to produce electricity in enhanced geothermal systems
- To increase injection rates for geologic sequestration of CO2
Hydraulic fracturing of water-supply wells
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.
A hydraulic fracture is formed by pumping the fracturing fluid into the wellbore at a rate sufficient to increase pressure downhole at the target zone (determined by the location of the well casing perforations) to exceed that of the fracture gradient (pressure gradient) of the rock. The fracture gradient is defined as the pressure increase per unit of the depth due to its density and it is usually measured in pounds per square inch per foot or bars per meter. The rock cracks and the fracture fluid continues further into the rock, extending the crack still further, and so on. Fractures are localized because of pressure drop off with frictional loss, which is attributed to the distance from the well. Operators typically try to maintain "fracture width", or slow its decline, following treatment by introducing into the injected fluid a proppant – a material such as grains of sand, ceramic, or other particulates, that prevent the fractures from closing when the injection is stopped and the pressure of the fluid is removed. Consideration of proppant strengths and prevention of proppant failure becomes more important at greater depths where pressure and stresses on fractures are higher. The propped fracture is permeable enough to allow the flow of formation fluids to the well. Formation fluids include gas, oil, salt water and fluids introduced to the formation during completion of the well during fracturing.
During the process, fracturing fluid leakoff (loss of fracturing fluid from the fracture channel into the surrounding permeable rock) occurs. If not controlled properly, it can exceed 70% of the injected volume. This may result in formation matrix damage, adverse formation fluid interactions, or altered fracture geometry and thereby decreased production efficiency.
The location of one or more fractures along the length of the borehole is strictly controlled by various methods that create or seal off holes in the side of the wellbore. Hydraulic fracturing is performed in cased wellbores and the zones to be fractured are accessed by perforating the casing at those locations.
Hydraulic-fracturing equipment used in oil and natural gas fields usually consists of a slurry blender, one or more high-pressure, high-volume fracturing pumps (typically powerful triplex or quintuplex pumps) and a monitoring unit. Associated equipment includes fracturing tanks, one or more units for storage and handling of proppant, high-pressure treating iron, a chemical additive unit (used to accurately monitor chemical addition), low-pressure flexible hoses, and many gauges and meters for flow rate, fluid density, and treating pressure. Chemical additives are typically 0.5% percent of the total fluid volume. Fracturing equipment operates over a range of pressures and injection rates, and can reach up to 100 megapascals (15,000 psi) and 265 litres per second (9.4 cu ft/s) (100 barrels per minute).
A distinction can be made between conventional or low-volume hydraulic fracturing used to stimulate high-permeability reservoirs to frac a single well, and unconventional or high-volume hydraulic fracturing, used in the completion of tight gas and shale gas wells as unconventional wells are deeper and require higher pressures than conventional vertical wells. In addition to hydraulic fracturing of vertical wells, it is also performed in horizontal wells. When done in already highly permeable reservoirs such as sandstone-based wells, the technique is known as "well stimulation".
Horizontal drilling involves wellbores where the terminal drillhole is completed as a "lateral" that extends parallel with the rock layer containing the substance to be extracted. For example, laterals extend 1,500 to 5,000 feet (460 to 1,500 m) in the Barnett Shale basin in Texas, and up to 10,000 feet (3,000 m) in the Bakken formation in North Dakota. In contrast, a vertical well only accesses the thickness of the rock layer, typically 50–300 feet (15–91 m). Horizontal drilling also reduces surface disruptions as fewer wells are required to access a given volume of reservoir rock. Drilling usually induces damage to the pore space at the wellbore wall, reducing the permeability at and near the wellbore. This reduces flow into the borehole from the surrounding rock formation, and partially seals off the borehole from the surrounding rock. Hydraulic fracturing can be used to restore permeability, but is not typically administered in this way.
High-pressure fracture fluid is injected into the wellbore, with the pressure above the fracture gradient of the rock. The two main purposes of fracturing fluid is to extend fractures, add lubrication, change gel strength and to carry proppant into the formation, the purpose of which is to stay there without damaging the formation or production of the well. Two methods of transporting the proppant in the fluid are used – high-rate and high-viscosity. High-viscosity fracturing tends to cause large dominant fractures, while high-rate (slickwater) fracturing causes small spread-out micro-fractures.
This fracture fluid contains water-soluble gelling agents (such as guar gum) which increase viscosity and efficiently deliver the proppant into the formation.
The fluid injected into the rock is typically a slurry of water, proppants, and chemical additives. Additionally, gels, foams, and compressed gases, including nitrogen, carbon dioxide and air can be injected. Typically, of the fracturing fluid 90% is water and 9.5% is sand with the chemical additives accounting to about 0.5%. However, fracturing fluids have been developed in which the use of water has been made unnecessary, using liquefied petroleum gas (LPG) and propane.
A proppant is a material that will keep an induced hydraulic fracture open, during or following a fracturing treatment, and can be gel, foam, or slickwater-based. Fluids make tradeoffs in such material properties as viscosity, where more viscous fluids can carry more concentrated proppant; the energy or pressure demands to maintain a certain flux pump rate (flow velocity) that will conduct the proppant appropriately; pH, various rheological factors, among others. Types of proppant include silica sand, resin-coated sand, and man-made ceramics. These vary depending on the type of permeability or grain strength needed. The most commonly used proppant is silica sand, though proppants of uniform size and shape, such as a ceramic proppant, is believed to be more effective. Due to a higher porosity within the fracture, a greater amount of oil and natural gas is liberated.
The fracturing fluid varies in composition depending on the type of fracturing used, the conditions of the specific well being fractured, and the water characteristics. A typical fracture treatment uses between 3 and 12 additive chemicals. Although there may be unconventional fracturing fluids, the more typically used chemical additives can include one or more of the following:
- Acids—hydrochloric acid or acetic acid is used in the pre-fracturing stage for cleaning the perforations and initiating fissure in the near-wellbore rock.
- Sodium chloride (salt)—delays breakdown of the gel polymer chains.
- Polyacrylamide and other friction reducers—minimizes the friction between fluid and pipe, thus allowing the pumps to pump at a higher rate without having greater pressure on the surface.
- Ethylene glycol—prevents formation of scale deposits in the pipe.
- Borate salts—used for maintaining fluid viscosity during the temperature increase.
- Sodium and potassium carbonates—used for maintaining effectiveness of crosslinkers.
- Glutaraldehyde—used as disinfectant of the water (bacteria elimination).
- Guar gum and other water-soluble gelling agents—increases viscosity of the fracturing fluid to deliver more efficiently the proppant into the formation.
- Citric acid—used for corrosion prevention.
- Isopropanol—increases the viscosity of the fracture fluid.
The most common chemical used for hydraulic fracturing in the United States in 2005–2009 was methanol, while some other most widely used chemicals were isopropyl alcohol, 2-butoxyethanol, and ethylene glycol.
Typical fluid types are:
- Conventional linear gels. These gels are cellulose derivatives (carboxymethyl cellulose, hydroxyethyl cellulose, carboxymethyl hydroxyethyl cellulose, hydroxypropyl cellulose, methyl hydroxyl ethyl cellulose), guar or its derivatives (hydroxypropyl guar, carboxymethyl hydroxypropyl guar) based, with other chemicals providing the necessary chemistry for the desired results.
- Borate-crosslinked fluids. These are guar-based fluids cross-linked with boron ions (from aqueous borax/boric acid solution). These gels have higher viscosity at pH 9 onwards and are used to carry proppants. After the fracturing job the pH is reduced to 3–4 so that the cross-links are broken and the gel is less viscous and can be pumped out.
- Organometallic-crosslinked fluids zirconium, chromium, antimony, titanium salts are known to crosslink the guar based gels. The crosslinking mechanism is not reversible. So once the proppant is pumped down along with the cross-linked gel, the fracturing part is done. The gels are broken down with appropriate breakers.
- Aluminium phosphate-ester oil gels. Aluminium phosphate and ester oils are slurried to form cross-linked gel. These are one of the first known gelling systems.
For slickwater it is common to include sweeps or a reduction in the proppant concentration temporarily to ensure the well is not overwhelmed with proppant causing a screen-off. As the fracturing process proceeds, viscosity reducing agents such as oxidizers and enzyme breakers are sometimes then added to the fracturing fluid to deactivate the gelling agents and encourage flowback. The oxidizer reacts with the gel to break it down, reducing the fluid's viscosity and ensuring that no proppant is pulled from the formation. An enzyme acts as a catalyst for the breaking down of the gel. Sometimes pH modifiers are used to break down the crosslink at the end of a hydraulic fracturing job, since many require a pH buffer system to stay viscous. At the end of the job the well is commonly flushed with water (sometimes blended with a friction reducing chemical) under pressure. Injected fluid is to some degree recovered and is managed by several methods, such as underground injection control, treatment and discharge, recycling, or temporary storage in pits or containers while new technology is continually being developed and improved to better handle waste water and improve re-usability.
Measurements of the pressure and rate during the growth of a hydraulic fracture, as well as knowing the properties of the fluid and proppant being injected into the well provides the most common and simplest method of monitoring a hydraulic fracture treatment. This data, along with knowledge of the underground geology can be used to model information such as length, width and conductivity of a propped fracture.
Injection of radioactive tracers, along with the other substances in hydraulic-fracturing fluid, is sometimes used to determine the injection profile and location of fractures created by hydraulic fracturing. The radiotracer is chosen to have the readily detectable radiation, appropriate chemical properties, and a half life and toxicity level that will minimize initial and residual contamination. Radioactive isotopes chemically bonded to glass (sand) and/or resin beads may also be injected to track fractures. For example, plastic pellets coated with 10 GBq of Ag-110mm may be added to the proppant or sand may be labelled with Ir-192 so that the proppant's progress can be monitored. Radiotracers such as Tc-99m and I-131 are also used to measure flow rates. The Nuclear Regulatory Commission publishes guidelines which list a wide range of radioactive materials in solid, liquid and gaseous forms that may be used as tracers and limit the amount that may be used per injection and per well of each radionuclide.
For more advanced applications, microseismic monitoring is sometimes used to estimate the size and orientation of hydraulically induced fractures. Microseismic activity is measured by placing an array of geophones in a nearby wellbore. By mapping the location of any small seismic events associated with the growing hydraulic fracture, the approximate geometry of the fracture is inferred. Tiltmeter arrays, deployed on the surface or down a well, provide another technology for monitoring the strains produced by hydraulic fracturing.
Microseismic mapping is very similar geophysically to seismology. In earthquake seismology seismometers scattered on or near the surface of the earth record S-waves and P-waves that are released during an earthquake event. This allows for the motion along the fault plane to be estimated and its location in the earth’s subsurface mapped. During formation stimulation by hydraulic fracturing an increase in the formation stress proportional to the net fracturing pressure as well as an increase in pore pressure due to leakoff takes place. Tensile stresses are generated ahead of the fracture/cracks’ tip which generates large amounts of shear stress. The increase in pore water pressure and formation stress combine and affect the weakness (natural fractures, joints, and bedding planes) near the hydraulic fracture. Dilatational and compressive reactions occur and emit seismic energy detectable by highly sensitive geophones placed in nearby wells or on the surface.
Different methods have different location errors and advantages. Accuracy of microseismic event locations is dependent on the signal to noise ratio and the distribution of the receiving sensors. For a surface array location accuracy of events located by seismic inversion is improved by sensors placed in multiple azimuths from the monitored borehole. In a downhole array location accuracy of events is improved by being close to the monitored borehole (high signal to noise ratio).
Monitoring of microseismic events induced by reservoir stimulation has become a key aspect in evaluation of hydraulic fractures and their optimization. The main goal of hydraulic fracture monitoring is to completely characterize the induced fracture structure and distribution of conductivity within a formation. This is done by first understanding the fracture structure. Geomechanical analysis, such as understanding the material properties, in-situ conditions and geometries involved will help with this by providing a better definition of the environment in which the hydraulic fracture network propagates. The next task is to know the location of proppant within the induced fracture and the distribution of fracture conductivity. This can be done using multiple types of techniques and finally, further develop a reservoir model than can accurately predict well performance.
Since the early 2000s, advances in drilling and completion technology have made drilling horizontal wellbores much more economical. Horizontal wellbores allow for far greater exposure to a formation than a conventional vertical wellbore. This is particularly useful in shale formations which do not have sufficient permeability to produce economically with a vertical well. Such wells when drilled onshore are now usually hydraulically fractured in a number of stages, especially in North America. The type of wellbore completion used will affect how many times the formation is fractured, and at what locations along the horizontal section of the wellbore.
In North America, shale reservoirs such as the Bakken, Barnett, Montney, Haynesville, Marcellus, and most recently the Eagle Ford, Niobrara and Utica shales are drilled, completed and fractured using this method. The method by which the fractures are placed along the wellbore is most commonly achieved by one of two methods, known as "plug and perf" and "sliding sleeve".
The wellbore for a plug and perf job is generally composed of standard joints of steel casing, either cemented or uncemented, which is set in place at the conclusion of the drilling process. Once the drilling rig has been removed, a wireline truck is used to perforate near the end of the well, following which a fracturing job is pumped (commonly called a stage). Once the stage is finished, the wireline truck will set a plug in the well to temporarily seal off that section, and then perforate the next section of the wellbore. Another stage is then pumped, and the process is repeated as necessary along the entire length of the horizontal part of the wellbore.
The wellbore for the sliding sleeve technique is different in that the sliding sleeves are included at set spacings in the steel casing at the time it is set in place. The sliding sleeves are usually all closed at this time. When the well is ready to be fractured, using one of several activation techniques, the bottom sliding sleeve is opened and the first stage gets pumped. Once finished, the next sleeve is opened which concurrently isolates the first stage, and the process repeats. For the sliding sleeve method, wireline is usually not required.
These completion techniques may allow for more than 30 stages to be pumped into the horizontal section of a single well if required, which is far more than would typically be pumped into a vertical well.
Hydraulic fracturing has been seen as one of the key methods of extracting unconventional oil and 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.
A number of studies related to the economy and fracking, demonstrates a direct benefit to economies from fracking activities in the form of personnel, support, ancillary businesses, analysis and monitoring. Typically the funding source of the study is a focal point of controversy. Most studies are either funded by mining companies or funded by environmental groups, which can at times lead to at least the appearance of unreliable studies. A study was performed by Deller & Schreiber in 2012, looking at the relationship between non-oil and gas mining and community economic growth. The study concluded that there is an effect on income growth; however, researchers found that mining does not lead to an increase in population or employment. The actual financial effect of non-oil and gas mining on the economy is dependent on many variables and is difficult to identify definitively.
Hydraulic fracturing has raised environmental concerns and is challenging the adequacy of existing regulatory regimes. These concerns have included ground water contamination, risks to air quality, migration of gases and hydraulic fracturing chemicals to the surface, mishandling of waste, and the health effects of all these, as well as its contribution to raised atmospheric CO2 levels by enabling the extraction of previously-sequestered hydrocarbons. Because hydraulic fracturing originated in the United States, its history is more extensive there than in other regions. Most environmental impact studies have therefore taken place there.
Concerns have been raised about research financed by foundations and corporations  that some have argued is designed to inflate or minimize the risks of development, as well as lobbying by the gas industry to promote its activities. Several organizations, researchers, and media outlets have reported difficulty in conducting and reporting the results of studies on hydraulic fracturing due to industry and governmental pressure, and expressed concern over possible censoring of environmental reports. A New York Times report claimed that an early draft of a 2004 EPA study discussed "possible evidence" of aquifer contamination but the final report omitted that mention. Some have also criticized the narrowing of EPA studies, including the EPA study on hydraulic fracturing's effect on drinking water to be released in late 2014. In addition, after court cases concerning contamination from hydraulic fracturing are settled, the documents are sealed, reducing the information available about contamination. The American Petroleum Institute denies that this practice has hidden problems with gas drilling. Researchers have recommended requiring disclosure of all hydraulic fracturing fluids, testing animals raised near fracturing sites, and closer monitoring of environmental samples. Many believe there is a need for more research into the environmental and health effects of the technique.
When petroleum crude oil is extracted and produced from onshore or offshore oil wells, raw natural gas associated with the oil is produced to the surface as well. One gas which is commonly flared is hydrogen sulfide, which is an irritant and a chemical asphyxiant that can alter both oxygen utilization and the central nervous system, according to the U.S. OSHA. Excessive H2S production in previously nonsour environments are "primarily anthropogenic and caused by certain operational practices". In areas of the world lacking pipelines and other gas transportation infrastructure, vast amounts of such associated gas are commonly flared as waste or unusable gas. In June 2013, the Enbridge corporation obtained an order to reject from its system crude that had high levels of sour gas. Enbridge had found in one instance concentration levels of 1,200ppm. The US FERC regulator sets 10ppm as a maximum for this noxious gas. A concentration 120 times as high "could cause death, or serious injuries".
A Pennsylvania family was forced to abandon because of pollution of their 10-acre farm. The family was paid 750,000USD by Range Resources Corporation to depart from a more recently installed petroleum well plant, though the family was required to sign an agreement which stated that they haven't suffered nor ever will suffer any adverse medical effects from the toxic exposure.
The air emissions from hydraulic fracturing are also related to methane leaks originating from wells, and emissions from the diesel or natural gas powered equipment such as compressors, drilling rigs, pumps etc. Also transportation of necessary water volume for hydraulic fracturing, if done by trucks, can cause high volumes of air emissions, especially particulate matter emissions. There are also reports of health problems around compressors stations or drilling sites, although a causal relationship was not established for the limited number of wells studied and another Texas government analysis found no evidence of effects.
Whether natural gas produced by hydraulic fracturing causes higher well-to-burner emissions than gas produced from conventional wells is a matter of contention. A 2012 report coauthored by researchers at the U.S. Department of Energy’s National Renewable Energy Laboratory found emissions from shale gas, when burned for electricity, were “very similar” to those from so-called “conventional well” natural gas, and less than half the emissions of coal. In April 2013 the EPA lowered its estimate of how much methane gas is released to the atmosphere during the fracking process by 20 percent. Some studies have found that hydraulic fracturing has higher emissions due to gas released during completing wells as some gas returns to the surface, together with the fracturing fluids. Depending on their treatment, the well-to-burner emissions are 3.5%–12% higher than for conventional gas. Studies that estimate the amount of methane leakage from shale gas development and production find that leakage could be as low as less than 1% of total gas production, or as high as several percent, with most recent studies on the low end of that range. A debate has arisen particularly around a study by professor Robert W. Howarth finding shale gas significantly worse for global warming than oil or coal. Other researchers have criticized Howarth's analysis. Howarth has responded that "The latest EPA estimate for methane emissions from shale gas falls within the range of our estimates but not those of Cathles et al., which are substantially lower." The U.S. EPA has estimated the methane leakage rate to be about 2.4% – well below Howarth’s estimate. The American Gas Association, and industry trade group, calculated a 1.2% leakage rate  based on the EPA's latest greenhouse gas inventory, although the EPA has not publicly stated a change to its prior estimate.
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Hydraulic fracturing uses between 1.2 and 3.5 million US gallons (4.5 and 13 Ml) of water per well, with large projects using up to 5 million US gallons (19 Ml). Additional water is used when wells are refractured. An average well requires 3 to 8 million US gallons (11,000 to 30,000 m3) of water over its lifetime. Back in 2008 at the beginning of the shale boom in Pennsylvania, hydraulic fracturing accounted for 650 million US gallons per year (2,500,000 m3/a) (less than 0.8%) of annual water use in the area overlying the Marcellus Shale. The annual number of well permits, however, increased by a factor of five and the number of well starts increased by a factor of over 17 from 2008 to 2011. According to the Oxford Institute for Energy Studies, greater volumes of fracturing fluids are required in Europe, where the shale depths average 1.5 times greater than in the U.S.
In proportion, the volume of H2O allocated from a surface water budget for hydraulic fracturing activities is relatively small. Still, concern has been raised over appropriating large quantities of water for hydraulic fracturing. This can divert water from stream flow, water supplies for municipalities and industries such as power generation, as well as recreation and aquatic life. The large volumes of water required for most common hydraulic fracturing methods have raised concerns for arid regions, such as Karoo in South Africa and drought prone areas of North America. It may also require water overland piping from distant sources. A report by Ceres questions whether the growth of hydraulic fracturing is sustainable in Texas and Colorado. The report integrated well location and water use data from FracFocus.org with World Resources Institute's (WRI) water risk maps. Ninety-two percent of Colorado wells were in extremely high water stress regions and 51% percent of the Texas wells evaluated were in high or extremely high water stress regions. "Extremely high water stress" means that more than 80% of the available water is already allocated for agricultural, industrial and municipal water use.
In Barnhart, Texas the aquifer ran dry because of industrial fracking: one landowner had 104 water wells (designed to supply fracking) dug into his land by his fracker tenants, and the population is left with little recourse for their dry taps. In the Spring of 2013, new hydraulic fracturing water recycling rules were adopted in the state of Texas by the Railroad Commission of Texas. The Water Recycling Rules are intended to encourage Texas hydraulic fracturing operators to conserve water used in the hydraulic fracturing process for oil and gas wells.
Recycling and using carbon dioxide instead of water have been proposed to reduce water consumption. While recycled flowback water cannot yet be made safe enough for drinking or growing crops, it can reused in hydraulic fracturing, though it can shorten the life of some types of equipment.
There are concerns about possible contamination by hydraulic fracturing fluid both as it is injected under high pressure into the ground and as it returns to the surface. To mitigate the effect of hydraulic fracturing on groundwater, the well and ideally the shale formation itself should remain hydraulically isolated from other geological formations, especially freshwater aquifers. In 2009 state regulators from at least a dozen states have also stated that they have seen no evidence of the hydraulic fracturing process polluting drinking water. In May 2011, former U.S. EPA administrator Lisa Jackson (appointed by President Barack Obama) has said on at least two occasions that there is either no proven case of direct contamination by the hydraulic fracturing process, or that the EPA has never made a definitive determination of such contamination. By August 2011 there were at least 36 cases of suspected groundwater contamination due to hydraulic fracturing in the United States. In more recent congressional testimony in April 2013, Dr. Robin Ikeda, Deputy Director of Noncommunicable Diseases, Injury and Environmental Health at the CDC listed several sites where EPA had documented contamination. In several cases EPA has determined that hydraulic fracturing was likely the source of the contamination.
While some of the chemicals used in hydraulic fracturing are common and generally harmless, some are known carcinogens. A report prepared for House Democratic members Henry Waxman, Edward Markey and Diana DeGette stated that out of 2,500 hydraulic fracturing products, "more than 650 of these products contained chemicals that are known or possible human carcinogens, regulated under the Safe Drinking Water Act, or listed as hazardous air pollutants". The report also shows that between 2005 and 2009, 279 products had at least one component listed as "proprietary" or "trade secret" on their Occupational Safety and Health Administration (OSHA) required material safety data sheet (MSDS). The MSDS is a list of chemical components in the products of chemical manufacturers, and according to OSHA, a manufacturer may withhold information designated as "proprietary" from this sheet. When asked to reveal the proprietary components, most companies participating in the investigation were unable to do so, leading the committee to surmise these "companies are injecting fluids containing unknown chemicals about which they may have limited understanding of the potential risks posed to human health and the environment". Without knowing the identity of the proprietary components, regulators cannot test for their presence. This prevents government regulators from establishing baseline levels of the substances prior to hydraulic fracturing and documenting changes in these levels, thereby making it more difficult to prove that hydraulic fracturing is contaminating the environment with these substances.
Another 2011 study identified 632 chemicals used in natural gas operations. Only 353 of these are well-described in the scientific literature. The study indicated possible long-term health effects that might not appear immediately. The study recommended full disclosure of all products used, along with extensive air and water monitoring near natural gas operations; it also recommended that hydraulic fracturing's exemption from regulation under the US Safe Drinking Water Act be rescinded. Industry group Energy In Depth, a research arm of the Independent Petroleum Association of America, contends that fracking "was never granted an 'exemption' from it... How can something earn an exemption from a law that never covered or even conceived of it in the first place?”
Governments are responding to questions about the contents of hydraulic fracturing fluid by requiring disclosure via government agencies and public web site. The Irish regulatory regime requires full disclosure of all additives to Ireland's Environmental Protection Agency (Ireland). The European Union also requires such disclosure. In the US, the Ground Water Protection Council launched FracFocus.org, an online voluntary disclosure database for hydraulic fracturing fluids funded by oil and gas trade groups and the U.S. Department of Energy. The site has been met with some skepticism relating to proprietary information that is not included. Some states have mandated fluid disclosure and incorporated FracFocus as the tool for disclosure. Also in the US, FracTracker Alliance provides oil and gas-related data storage, analyses, and online and customized maps related to hydraulic fracturing on FracTracker.org.
Estimates of the amount of injected fluid returning to the surface vary. Estimates of the fluid that returns to the surface with the gas range from 15-20% to 30–70%. the fluid is often mixed with formation water. Additional fluid may return to the surface through abandoned wells or other pathways. After the flowback is recovered, formation water, usually brine, may continue to flow to the surface, requiring treatment or disposal. These fluids, commonly known as flowback, produced water, or wastewater, are managed by underground injection, wastewater treatment and discharge, or recycling to fracture future wells.
Hydraulic fracturing can concentrate uranium, radium, radon and thorium in flowback. One Duke University study reported that "Marcellus [Shale] wells produce significantly less wastewater per unit gas recovered (~35%) compared to conventional natural gas wells.” Treatment of produced waters may be feasible through either self-contained systems at well sites or fields or through municipal waste water treatment plants or commercial treatment facilities.
In Colorado the volume of wastewater discharged to surface streams increased from 2008 to 2011.
In 2013 the vacuum multi-effect membrane distillation system was introduced to treat flowback. It is a hybrid system that uses both distillation and reverse osmosis to process the water. The water is repeatedly distilled through a membrane onto a collector. The system is operated in a partial vacuum to reduce the water's boiling point to 50–80 °C (122–176 °F). The purified result is appropriate for use in irrigation and may be made potable according to the company offering the service. The residual is highly concentrated brine, which can be reinjected or recycled using other technology.
The quantity of wastewater and the unpreparedness of sewage plants to treat wastewater, became an issue in Pennsylvania. When waste brine is discharged to surface waters through conventional wastewater treatment plants, the bromide in the brine usually is not captured. Although not a health hazard by itself, in western Pennsylvania some downstream drinking water treatment plants using the surface water experienced increases in brominated trihalomethanes in 2009 and 2010. Trihalomethanes, undesirable byproducts of the chlorination process, form when the chlorine combines with dissolved organic matter in the source water, to form the trihalomethane chloroform. Bromine can substitute for some of the chlorine, forming brominated trihalomethanes. Because bromine has a higher atomic weight than chlorine, the partial conversion to brominated trihalomethanes increases the concentration by weight of total trihalomethanes.
Before 2011, flowback in Pennsylvania was processed by public wastewater plants, which were not equipped to remove radioactive material and were not required to test for it. In 2010 the Pennsylvania Department of Environmental Protection (DEP) limited surface water discharges from new treatment plants to 250 mg/l chloride. This limitation was designed to also limit other contaminants such as radium. Existing water treatment plants were allowed higher discharge concentrations. In April 2011, the DEP asked unconventional gas operators to voluntarily stop sending wastewater to the grandfathered treatment plants. The PADEP reported that the operators had complied.
A 2012 study by researchers from the National Renewable Energy Laboratory, University of Colorado, and Colorado State University reported a reduction in the percentage of flowback treated through surface water discharge in Pennsylvania from 2008 through 2011. By late 2012, bromine concentrations had declined to previous levels in the Monongahela River, but remained high in the Allegheny.
A 2013 Duke University study sampled water downstream from a Pennsylvania wastewater treatment facility from 2010 through 2012 and found that creek sediment contained levels of radium 200 times background levels. The surface water had the same chemical signature as rocks in the Marcellus Shale formation along with high levels of chloride. The facility denied processing Marcellus waste after 2011. In May 2013 the facility signed another agreement to not accept or discharge Marcellus wastewater until it installed technology to remove the radioactive materials, metals and salts.
The co-author of the Duke University study advised the UK to exceed US environmental regulation if it pursues shale gas extraction.
Groundwater methane contamination is also a concern as it has adverse effect on water quality and in extreme cases may lead to potential explosion. In 2006, over 7 million cubic feet (200,000 m3) of methane were released from a blown gas well in Clark, Wyoming and shallow groundwater was found to be contaminated. A scientific study reported in the PNAS investigated concerns over fracking and well water. The study found high correlations of drilling activity and methane pollution of the drinking water. Methane contamination is not always caused by hydraulic fracturing. Drilling for ordinary drinking water wells can also cause methane release. Most recent studies make use of tests that can distinguish between the deep thermogenic methane released during gas/oil drilling, and the shallower biogenic methane that can be released during water-well drilling. While both forms of methane result from decomposition, thermogenic methane results from geothermal assistance deeper underground.
According to the 2011 study of the MIT Energy Initiative, "there is evidence of natural gas (methane) migration into freshwater zones in some areas, most likely as a result of substandard well completion practices i.e. poor quality cementing job or bad casing, by a few operators." 2011 studies by the Colorado School of Public Health and Duke University also pointed to methane contamination stemming from hydraulic fracturing or its surrounding process. A study by Cabot Oil and Gas examined the Duke study using a larger sample size, found that methane concentrations were related to topography, with the highest readings found in low-lying areas, rather than related to distance from gas production areas. Using a more precise isotopic analysis, they showed that the methane found in the water wells came from both the Marcellus Shale (Middle Devonian) where hydraulic fracturing occurred, and from the shallower Upper Devonian formations. A 2013 Duke study suggested that both defective cement seals in the upper part of wells and faulty steel linings within deeper layers may be allowing methane and injected fluid to seep into surface waters. Abandoned gas and oil wells also provide conduits to the surface. A recent Duke University study found methane concentrations six times higher and ethane concentrations were 23 times higher at residences within a kilometer of a shale gas well. Propane was also detected in 10 homes within a kilometer of drilling. The researchers reported that the methane, ethane and propane data, and new evidence from hydrocarbon and helium content, all suggested that drilling has affected the drinking water. They noted that the ethane and propane data were notable because there was no biological source of ethane and propane in the region and Marcellus gas is higher in both than are Upper Devonian gases.
Hydrogen sulfide (H2S, sour gas), a gas which is toxic to humans and flammable, has been detected in some fracked crude by the Enbridge corporation. A paper published by the Society of Petroleum Engineers stated in 2011 that increased concentration of H2S in crude oil presents challenges such as "health and environmental risks, corrosion of wellbore, added expense with regard to materials handling and pipeline equipment, and additional refinement requirements". Holubnyak et al. further state in their paper on the Bakken formation that "the causes of excessive H2S production in previously nonsour environments are primarily anthropogenic and caused by certain operational practices."
There are concerns about the levels of radioactivity in wastewater from hydraulic fracturing and its potential impact on public health. Tests conducted in Pennsylvania in 2009 found “no evidence of elevated radiation levels” in waterways. At the time radiation concerns were not seen as a pressing issue. The EPA called for more testing. In 2011 The New York Times reported radium in wastewater from natural gas wells is released into Pennsylvania rivers, and compiled a map of these wells and their wastewater contamination levels, and stated that some EPA reports were never made public. The Times' reporting on the issue has come under some criticism. A 2012 study examining a number of hydraulic fracturing sites in Pennsylvania and Virginia by Pennsylvania State University, found that water that flows back from gas wells after hydraulic fracturing contains high levels of radium. A recent Duke University study sampled water downstream from a Pennsylvania wastewater treatment facility from 2010 through Fall 2012 and found the creek sediment contained levels of radium 200 times background levels. The surface water had the same chemical signature as rocks in the Marcellus Shale formation. The facility denied processing Marcellus waste since 2011. In May 2013 the facility signed another agreement to not accept or discharge wastewater Marcellus Shale formations until it has installed technology to remove the radiation compounds, metals and salts. Recycling this wastewater has been proposed as a partial solution, but this approach has limitations.
Solid waste such as Drill cuttings can also contain radioactive materials. In 2012 there were 1325 radiation alerts from all sources at dumps in Pennsylvania, up from 423 alerts in 2008. At least 1,000 of the 2012 alerts were set off by waste from gas and oil drilling hydraulic fracturing operations.
Hydraulic fracturing routinely produces microseismic events much too small to be detected except by sensitive instruments. These microseismic events are often used to map the horizontal and vertical extent of the fracturing. However, as of late 2012, there have been three instances of hydraulic fracturing, through induced seismicity, triggering quakes large enough to be felt by people: one each in the United States, Canada, and England.
A 2012 US Geological Survey study reported that a "remarkable" increase in the rate of M ≥ 3 earthquakes in the US midcontinent "is currently in progress", having started in 2001 and culminating in a 6-fold increase over 20th century levels in 2011. The overall increase was tied to earthquake increases in a few specific areas: the Raton Basin of southern Colorado (site of coalbed methane activity), and gas-producing areas in central and southern Oklahoma, and central Arkansas. While analysis suggested that the increase is "almost certainly man-made", the USGS noted: "USGS’s studies suggest that the actual hydraulic fracturing process is only very rarely the direct cause of felt earthquakes." The increased earthquakes were said to be most likely caused by increased injection of gas-well wastewater into disposal wells. The injection of waste water from oil and gas operations, including from hydraulic fracturing, into saltwater disposal wells may cause bigger low-magnitude tremors, being registered up to 3.3 (Mw).
Induced seismicity from hydraulic fracturing
The United States Geological Survey (USGS) has reported earthquakes induced by hydraulic fracturing, and by disposal of hydraulic fracturing flowback into waste disposal wells, in several locations. Bill Ellsworth, a geoscientist with the U.S. Geological Survey, has said, however: “We don’t see any connection between fracking and earthquakes of any concern to society.”  The National Research Council (part of the National Academy of Sciences) has also observed that hydraulic fracturing, when used in shale gas recovery, does not pose a serious risk of causing earthquakes that can be felt.In 2013, Researchers from Columbia University and the University of Oklahoma demonstrated that in the midwestern United States, some areas with increased human-induced seismicity are susceptible to additional earthquakes triggered by the seismic waves from remote earthquakes. They recommended increased seismic monitoring near fluid injection sites to determine which areas are vulnerable to remote triggering and when injection activity should be ceased.
A British Columbia Oil and Gas Commission investigation concluded that a series of 38 earthquakes (magnitudes ranging from 2.2 to 3.8 on the Richter scale) occurring in the Horn River Basin area between 2009 and 2011 were caused by fluid injection during hydraulic fracturing in proximity to pre-existing faults. The tremors were small enough that only one of them was reported felt by people; there were no reports of injury or property damage.
A report in the UK concluded that hydraulic fracturing was the likely cause of two small tremors (magnitudes 2.3 and 1.4 on the Richter scale) that occurred during hydraulic fracturing of shale.
Induced seismicity from water disposal wells
According to the USGS only a small fraction of roughly 40,000 waste fluid disposal wells for oil and gas operations in the United States have induced earthquakes that are large enough to be of concern to the public. Although the magnitudes of these quakes has been small, the USGS says that there is no guarantee that larger quakes will not occur. In addition, the frequency of the quakes has been increasing. In 2009, there were 50 earthquakes greater than magnitude 3.0 in the area spanning Alabama and Montana, and there were 87 quakes in 2010. In 2011 there were 134 earthquakes in the same area, a sixfold increase over 20th century levels. There are also concerns that quakes may damage underground gas, oil, and water lines and wells that were not designed to withstand earthquakes.
Several earthquakes in 2011, including a 4.0 magnitude quake on New Year's Eve that hit Youngstown, Ohio, are likely linked to a disposal of hydraulic fracturing wastewater, according to seismologists at Columbia University. A similar series of small earthquakes occurred in 2012 in Texas. Earthquakes are not common occurrences in either area. Disposal and injection wells are regulated under the Safe Drinking Water Act and UIC laws.
Concern has been expressed over the possible long and short term health effects of air and water contamination and radiation exposure by gas production. A study on the effect of gas drilling, including hydraulic fracturing, published by the Cornell University College of Veterinary Medicine, concluded that exposure to gas drilling operations was strongly implicated in serious health effects on humans and animals  although scientists have raised concerns about that particular report. As of May 2012, the United States Institute of Medicine and United States National Research Council were preparing to review the potential human and environmental risks of hydraulic fracturing.
The U.S. Environmental Protection Agency considers radioactive material in flowback a hazard to workers at hydraulic fracturing sites. Workers may inhale radon gas released by the process, raising their risk of lung cancer. They are also exposed to alpha and gamma radiation released during the decay of radium-226 and to gamma radiation and beta particles released by the decay of radium-228, according to EPA. EPA reports that gamma radiation can also penetrate the skin and raise the risk of cancer.
A 2012 study concluded that risk prevention efforts should be directed towards reducing air emission exposures for persons living and working near wells during well completions. In the United States the Occupational Safety and Health Administration (OSHA) and the National Institute for Occupational Safety and Health (NIOSH) released a hazard alert based on data collected by NIOSH that "workers may be exposed to dust with high levels of respirable crystalline silica (silicon dioxide) during hydraulic fracturing." NIOSH notified company representatives of these findings and provided reports with recommendations to control exposure to crystalline silica and recommend that all hydraulic fracturing sites evaluate their operations to determine the potential for worker exposure to crystalline silica and implement controls as necessary to protect workers.
According to the United States Department of Energy, hydraulic fracturing fluid is composed of approximately 95% water, 4.5% sand and 0.5% different chemicals. These percentages are by weight, so hydraulically fracturing a well uses 4-7 million gallons of water (15000-27000 tons) and 80-140 tons of chemicals. There can be up to 65 chemicals and often include benzyne, glycol-ethers, toluene, ethanol and nonphenols. Some[who?] have argued that although many of these chemicals are harmful, some of them are either non toxic or are non toxic at lower dosages. However, their concentration in hydraulic fracturing fluid have proven toxic to animals and humans. Many chemicals used in fracking, such as 2-BE ethylene glycol, are carcinogenic. This chemical is listed under chronic oral RFD assessment, chronic inhalation RFC assessment, and carcinogenicity assessment records of the US environmental protection agency’s website.
In a study done by Colborn and colleagues, they examined 353 out of 994 fracking chemicals identified by TEDX in hydraulic fracking operation. They found over 75% of the 353 chemicals affected the skin, eyes, and other sensory organs,52% affected the nervous system, 40% affected the immune system and kidney system, and 46% affected the cardiocascular system and blood.
In a second study done by Colborn and colleagues, they examined the airborne chemicals due to the fracking process. The group categorized the human tissue types into 12 categories and found 35 chemicals affected the brain/nervous system, 33 the liver/ metabolism, and 30 the endocrine system, which includes reproductive and developmental effects. The categories with the next highest numbers of effects were the immune system (28), cardiovascular/blood (27), and the sensory and respiratory systems (25 each). Eight chemicals had health effects in all 12 categories.
Airborne chemicals during the fracking process, such as benzene and benzene derivatives, naphthalene, methylene chloride, are either carcinogenic or suspected as a human carcinogen to the human body.
Public-health benefits of hydraulic fracturing
Noted physicist Richard A. Muller of Berkeley Earth argues that the public health benefits from shale gas made available by fracking, by displacing harmful air pollution from coal, far outweigh their combined environmental costs. In a 2013 report for the Centre for Policy Studies, Muller writes that air pollution, mostly from coal burning, kills over three million people each year, primarily in the developing world. The report states that "Environmentalists who oppose the development of shale gas and fracking are making a tragic mistake."
Politics and public policy
To control the hydraulic fracturing industry, some governments are developing legislation and some municipalities are developing local zoning limitations. In 2011, France became the first nation to ban hydraulic fracturing. Some other countries have placed a temporary moratorium on the practice. The US has the longest history with hydraulic fracturing, so its approach to hydraulic fracturing may be modeled by other countries. In August 2013 the Church of England, in an official statement, criticized those who advocate “blanket opposition” to fracking.
The considerable opposition against hydraulic fracturing activities in local townships has led companies to adopt a variety of public relations measures to assuage fears about hydraulic fracturing, including the admitted use of "military tactics to counter drilling opponents". At a conference where public relations measures were discussed, a senior executive at Anadarko Petroleum was recorded on tape saying, "Download the US Army / Marine Corps Counterinsurgency Manual, because we are dealing with an insurgency", while referring to hydraulic fracturing opponents. Matt Pitzarella, spokesman for Range Resources also told other conference attendees that Range employed psychological warfare operations veterans. According to Pitzarella, the experience learned in the Middle East has been valuable to Range Resources in Pennsylvania, when dealing with emotionally charged township meetings and advising townships on zoning and local ordinances dealing with hydraulic fracturing.
Police officers have recently been forced, however, to deal with intentionally disruptive and even potentially violent opposition to oil and gas development. In March 2013, ten people were arrested  during an "anti-fracking protest" near New Matamoras, Ohio, after they illegally entered a development zone and latched themselves to drilling equipment. In northwest Pennsylvania, there was a drive-by shooting at a well site, in which an individual shot two rounds of a small-caliber rifle in the direction of a drilling rig, just before shouting profanities at the site and fleeing the scene. And in Washington County, Pa., a contractor working on a gas pipeline found a pipe bomb that had been placed where a pipeline was to be constructed, which local authorities said would have caused a “catastrophe” had they not discovered and detonated it.
Josh Fox's 2010 Academy Award nominated film Gasland became a center of opposition to hydraulic fracturing of shale. The movie presented problems with ground water contamination near well sites in Pennsylvania, Wyoming, and Colorado. Energy in Depth, an oil and gas industry lobbying group, called the film's facts into question. In response, a rebuttal of Energy in Depth's claims of inaccuracy was posted on Gasland's website. The Director of the Colorado Oil and Gas Conservation Commission (COGCC) offered to be interviewed as part of the film if he could review what was included from the interview in the final film but Fox declined the offer. Exxon Mobil, Chevron Corporation and ConocoPhillips aired advertisements during 2011 and 2012 that claim to describe the economic and environmental benefits of natural gas and argue hydraulic fracturing is safe.
The film Promised Land, starring Matt Damon, takes on hydraulic fracturing. The gas industry has made plans to counter the film's criticisms of hydraulic fracturing with informational flyers, and Twitter and Facebook posts.
On January 22, 2013 Phelim McAleer, journalist and filmmaker, released a crowdfunded documentary called FrackNation as a response to the claims made by Fox in Gasland. FrackNation premiered on Mark Cuban's AXS TV. The premiere corresponded with the release of Promised Land.
- Hydraulic fracturing by country
- Hydraulic fracturing in the United States
- In-situ leach
- Directional drilling
- Environmental concerns with electricity generation
- Environmental impact of petroleum
- Environmental impact of the oil shale industry
- ExxonMobil Electrofrac
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- DiCosmo, Bridget (15 May 2012). "SAB Pushes To Advise EPA To Conduct Toxicity Tests In Fracking Study". InsideEPA. Inside Washington Publishers. (subscription required). Retrieved 2012-05-19. "But some members of the chartered SAB are suggesting that the fracking panel revise its recommendation that the agency scale back its planned toxicity testing of chemicals used in the hydraulic fracturing, or fracking, process, because of the limited resources and time frame ... Chesapeake Energy supported the draft recommendation, saying that "an in-depth study of toxicity, the development of new analytical methods and tracers are not practical given the budget and schedule limitation of the study.""
- "The Debate Over the Hydrofracking Study's Scope". The New York Times. 3 March 2011. Retrieved 1 May 2012. "While environmentalists have aggressively lobbied the agency to broaden the scope of the study, industry has lobbied the agency to narrow this focus"
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- (PDF) Evaluation of Impacts to Underground Sources of Drinking Water by Hydraulic Fracturing of Coalbed Methane Reservoirs; National Study Final Report (Report). EPA. June 2004. http://www.epa.gov/ogwdw/uic/pdfs/cbmstudy_attach_uic_final_fact_sheet.pdf. Retrieved 23 February 2011.
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- "Fracking gas leak estimates lowered". 3 News (NZ). April 29, 2013.
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- Arthur, J. Daniel; Uretsky, Mike; Wilson, Preston (May 5–6, 2010). "Water Resources and Use for Hydraulic Fracturing in the Marcellus Shale Region" (PDF). Meeting of the American Institute of Professional Geologists. Pittsburgh: ALL Consulting. p. 3. Retrieved 2012-05-09.
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- "A Texan tragedy: ample oil, no water" 11 Aug Guardian
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- "Drilling Down: Documents: Natural Gas's Toxic Waste". The New York Times. 26 February 2011. Retrieved 23 February 2012.
- Ehrenburg, Rachel (25 June 2013). "News in Brief: High methane in drinking water near fracking sites. Well construction and geology may both play a role". Science News. Retrieved 26 June 2013.
- "Regulatory Statements on Hydraulic Fracturing Submitted by the States, June 2009". Insterstate Oil and Gas Compact Commission. Retrieved 27 March 2013.
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- Fetzer, Richard M. (19 January 2012). Action Memorandum — Request for funding for a Removal Action at the Dimock Residential Groundwater Site (Report). http://www.epaosc.org/sites/7555/files/dimock-action-memo-01-19-12%5B1%5D.pdf. Retrieved 27 May 2012.
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- Kris Fitz Patrick (November 17, 2011). "Ensuring Safe Drinking Water in the Age of Hydraulic Fracturing". "The most fundamental recommendation is for states to rigorously test their ground water before and after hydraulic fracturing takes place. A major difficulty in proving or disproving contamination in previous cases has been the lack of a baseline sample for the water supply in question. The group also raises a federal policy issue, namely whether fracturing fluids should continue to be exempt from Safe Drinking Water Act regulations. This exemption was an informal one until 2005, when it was codified as part of the Energy Policy Act. A consequence of this exemption is that drilling companies are not required to disclose the chemicals that make up the fracturing fluids, making testing for these chemicals in ground water more difficult."
- Colborn, Theo; Kwiatkowski, Carol; Schultz, Kim; Bachran, Mary (2011). "Natural Gas Operations from a Public Health Perspective" (PDF). Human and Ecological Risk Assessment: an International Journal (Taylor & Francis) 17 (5): 1039–1056. doi:10.1080/10807039.2011.605662.
- "FAQ: Hydraulic Fracturing, SDWA, Fluids, and DeGette/Casey". Energy In Depth. Retrieved 27 March 2013.
- Dave Healy (July 2012) (PDF). /sss/UniAberdeen_FrackingReport.pdf Hydraulic Fracturing or ‘Fracking’: A Short Summary of Current Knowledge and Potential Environmental Impacts A Small Scale Study for the Environmental Protection Agency (Ireland) under the Science, Technology, Research & Innovation for the Environment. (STRIVE) Programme 2007 (Report). Environmental Protection Agency, Ireland. http://www.epa.ie/pubs/reports/research /sss/UniAberdeen_FrackingReport.pdf. Retrieved 28 July 2013.
- Hass, Benjamin (14 August 2012). "Fracking Hazards Obscured in Failure to Disclose Wells". Bloomberg News. Retrieved 27 March 2013.
- Soraghan, Mike (13 December 2013). "White House official backs FracFocus as preferred disclosure method". E&E News. Retrieved 27 March 2013.
- "Colorado Sets The Bar on Hydraulic Fracturing Chemical Disclosure". Environmental Defense Fund. Retrieved 27 March 2013.
- Maykuth, Andrew (22 January 2012). "More states ordering disclosure of fracking chemicals.". Philadelphia Inquirer. Retrieved 27 March 2013.
- Grant, Alison (4 April 2013). "FracTracker monitors shale development in Ohio". The Plain Dealer. Retrieved 28 July 2013.
- Staff. "FracTracker. Exploring data, sharing perspectives, and mapping impacts of the gas industry". FracTracker. Retrieved 28 July 2013.
- Staff (PDF). Waste water (Flowback)from Hydraulic Fracturing (Report). Ohio Department of Natural Resources. http://www.ohiodnr.com/Portals/11/pdf/wastewater-fact-sheet.pdf. Retrieved 29 June 2013. "Most of the water used in fracturing remains thousands of feet underground, however, about 15-20 percent returns to the surface through a steel-cased well bore and is temporarily stored in steel tanks or lined pits. The wastewater which returns to the surface after hydraulic fracturing is called flowback"
- Sandy McSurdy & Radisav Vidic (25 June 2013) (PDF). Sustainable Management of Flowback Water during Hydraulic Fracturing of Marcellus Shale for Natural Gas Production (Report). National Energy Technology Laboratory, US Department of Energy. http://www.netl.doe.gov/technologies/oil-gas/Petroleum/projects/Environmental/Produced_Water/00975_MarcellusFlowback.html. Retrieved 29 June 2013.
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- Detrow, Scott (9 October 2012). "Perilous Pathways: How Drilling Near An Abandoned Well Produced a Methane Geyser". StateImpact Pennsylvania. NPR. Retrieved 29 June 2013. "As Shell was drilling and then hydraulically fracturing its nearby well, the activity displaced shallow pockets of natural gas — possibly some of the same pockets the Morris Run Coal company ran into in 1932. The gas disturbed by Shell’s drilling moved underground until it found its way to the Butters well, and then shot up to the surface. Companies have been extracting oil and gas from Pennsylvania’s subsurface since 1859, when Edwin Drake drilled the world’s first commercial oil well. Over that 150-year timespan, as many as 300,000 wells have been drilled, an unknown number of them left behind as hidden holes in the ground. Nobody knows how many because most of those wells were drilled long before Pennsylvania required permits, record-keeping or any kind of regulation. It’s rare for a modern drilling operation to intersect — the technical term is “communicate” — with an abandoned well. But incidents like Shell’s Tioga County geyser are a reminder of the dangers these many unplotted holes in the ground can cause when Marcellus or Utica Shale wells are drilled nearby. And while state regulators are considering requiring energy companies to survey abandoned wells within a 1,000-foot radius of new drilling operations, the location of nearby wells is currently missing from the permitting process. That’s the case in nearly every state where natural gas drillers are setting up hydraulic fracturing operations in regions with long drilling histories. Regulators don’t require drillers to search for abandoned wells and plug them because, the thinking goes, this is something drillers are doing anyway."
- Hopey, Don (1 March 2011). "Gas drillers recycling more water, using fewer chemicals". Pittsburgh Post-Gazette. Retrieved 27 March 2013.
- Litvak, Anya (21 August 2012). "Marcellus flowback recycling reaches 90 percent in SWPA.". Pittsburgh Business Times. Retrieved 27 March 2013.
- Weinhold, Bob (19 September 2012). "Unknown Quantity: Regulating Radionuclides in Tap Water". Environmental Health Perspectives. NIEHS, NIH. Retrieved 11 February 2012. "Examples of human activities that may lead to radionuclide exposure include mining, milling, and processing of radioactive substances; wastewater releases from the hydraulic fracturing of oil and natural gas wells... Mining and hydraulic fracturing, or "fracking", can concentrate levels of uranium (as well as radium, radon, and thorium) in wastewater..."
- Lutz, Brian; Lewis, Aurana; Doyle, Martin (8 February 2013). "Generation, transport, and disposal of wastewater associated with Marcellus Shale gas development". Environmental Health Perspectives (Water Resources Research) 49 (2): 647–1197. doi:10.1002/wrcr.20096. Retrieved 2013-06-30.
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- Sun, M.; Lowry, G.V.; Gregory, K.B. Selective oxidation of bromide in wastewater brines from hydraulic fracturing. 47 (11). Water Res. pp. 3723–31. doi:10.1016/j.watres.2013.04.041. PMC 1817691. PMID 23726709. Retrieved 2013-06-30.
- Paul Handke, Trihalomethane speciation and the relationship to elevated total dissolved solid concentrations, Pennsylvania Department of Environmental Protection.
- Caruso, David B. (2011-01-03). "44,000 Barrels of Tainted Water Dumped Into Neshaminy Creek. We're the only state allowing tainted water into our rivers". NBC Philadelphia. Associated Press. Retrieved 2012-04-28. "...the more than 300,000 residents of the 17 municipalities that get water from the creek or use it for recreation were never informed that numerous public pronouncements that the watershed was free of gas waste had been wrong."
- Urbina, Ian (26 February 2011). "Regulation Lax as Gas Wells' Tainted Water Hits Rivers". The New York Times. Retrieved 22 February 2012.
- University of Pittsburgh, Shales Gas Roundtable, p.56, Aug, 2013.
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- Natural Gas Extraction—Hydraulic Fracturing (EPA website)
- EPA's Draft Hydraulic Fracturing Study Plan
- The British Columbia (Canada) Oil and Gas Commission mandatory disclosure of hydraulic fracturing fluids
- Hydraulic Fracturing: Selected Legal Issues Congressional Research Service
- FracFocus Searchable database with chemical composition of fracking fluid of individual wells
- FracTracker.org: Maps, data, and articles from news, government, industry, and academic sources.
- 60 Minutes Report on Hydraulic Fracturing]
- Shale gas and fracking collected news and commentary at The Guardian