Fracking
Fracking (also known as hydraulic fracturing, fracing, hydrofracturing, or hydrofracking) is a well stimulation technique involving the fracturing of formations in bedrock by a pressurized liquid. The process involves the high-pressure injection of "fracking fluid" (primarily water, containing sand or other proppants suspended with the aid of thickening agents) into a wellbore to create cracks in the deep-rock formations through which natural gas, petroleum, and brine will flow more freely. When the hydraulic pressure is removed from the well, small grains of hydraulic fracturing proppants (either sand or aluminium oxide) hold the fractures open.[1] Fracking, using either hydraulic pressure or acid, is the most common method for well stimulation. Well stimulation techniques help create pathways for oil, gas or water to flow more easily, ultimately increasing the overall production of the well.[2] Both methods of fracking are classed as unconventional, because they aim to permanently enhance (increase) the permeability of the formation. So the traditional division of hydrocarbon-bearing rocks into source and reservoir no longer holds; the source rock becomes the reservoir after the treatment. Hydraulic fracking is more familiar to the general public, and is the predominant method used in hydrocarbon exploitation, but acid fracking has a much longer history.[3][4][5][6] Although the hydrocarbon industry tends to use fracturing rather than the word fracking, which now dominates in popular media, an industry patent application[7] dating from 2014 explicitly uses the term acid fracking in its title. Definition Hydraulic fracturing (fracking) and acidising (acid fracking) are two of the most common methods for well stimulation. The flow chart shows that hydraulic fracking and acid fracking, highlighted in yellow, are two categories of unconventional hydraulic methods. But acidising is complicated by the fact that matrix acidising is considered conventional. Note that it takes place below the fracture gradient of the rock. In the UK legislative and hydrocarbon permitting context (see Fracking in the United Kingdom), Adriana Zalucka et al. have reviewed the various definitions,[8] as well as the role of key regulators and authorities, in a peer-reviewed article published in 2021. They have proposed a new robust definition for unconventional well treatments:
The above definition focuses on increasing permeability, rather than on any particular extraction process. It is quantitative, using the generally agreed 0.1 md cut-off value, below which rocks are considered impermeable. It exempts borehole cleaning processes like acid squeeze or acid wash from being classed as unconventional, by using the 1 m radius criterion. It avoids a definition based on, for example, the quantity of water injected, which is controversial,[9] or the injection pressure applied (whether the treatment is above or below the fracture gradient, as shown in the flow chart above). It also exempts non-hydrocarbon wells from being classed as unconventional. The definition takes into account the views of the hydrocarbon industry and the US Geological Survey, in particular. A low permeability (by consensus defined as less than 0.1 millidarcies) implies that the resource is unconventional, meaning that it requires special methods to extract the resource. Above that value, conventional methods suffice. Unconventional resources are also characterised by being widely distributed, with low energy density (i.e. in a low concentration) and ill-defined in volume. There are no discrete boundaries, in contrast to those bounding a conventional hydrocarbon reservoir. Although the definition above was developed within the UK context, it is universally applicable.
Hydraulic frackingHydraulic fracking[a] is the most commonly used well stimulation technique. It involves the fracturing of formations in bedrock by a pressurized liquid. The process involves the high-pressure injection of "fracking fluid" (primarily water, containing sand or other proppants suspended with the aid of thickening agents) into a wellbore to create cracks in the deep rock formations through which natural gas, petroleum, and brine will flow more freely. When the hydraulic pressure is removed from the well, small grains of hydraulic fracturing proppants (either sand or aluminium oxide) hold the fractures open.[1] Hydraulic fracking began as an experiment in 1947,[10] and the first commercially successful application followed in 1949. As of 2012, 2.5 million "frac jobs" had been performed worldwide on oil and gas wells, over one million of those within the U.S.[11][12] Such treatment is generally necessary to achieve adequate flow rates in shale gas, tight gas, tight oil, and coal seam gas wells.[13] Some hydraulic fractures can form naturally in certain veins or dikes.[14] Drilling and hydraulic fracking have made the United States a major crude oil exporter as of 2019,[15] but leakage of methane, a potent greenhouse gas, has dramatically increased.[16][17] Increased oil and gas production from the decade-long fracking boom has led to lower prices for consumers, with near-record lows of the share of household income going to energy expenditures.[18][19] Fracking is highly controversial.[20] Its proponents highlight the economic benefits of more extensively accessible hydrocarbons (such as petroleum and natural gas),[21][22] the benefits of replacing coal with natural gas, which burns more cleanly and emits less carbon dioxide (CO2),[23][24] and the benefits of energy independence.[25] Opponents of fracking argue that these are outweighed by the environmental impacts, which include groundwater and surface water contamination,[26] noise and air pollution, the triggering of earthquakes, and the resulting hazards to public health and the environment.[27][28] Research has found adverse health effects in populations living near hydraulic fracturing sites,[29][30] including confirmation of chemical, physical, and psychosocial hazards such as pregnancy and birth outcomes, migraine headaches, chronic rhinosinusitis, severe fatigue, asthma exacerbations and psychological stress.[31] Adherence to regulation and safety procedures are required to avoid further negative impacts.[32] The scale of methane leakage associated with hydraulic fracking is uncertain, and there is some evidence that leakage may cancel out any greenhouse gas emissions benefit of natural gas relative to other fossil fuels.[33][34]  Increases in seismic activity following hydraulic fracking along dormant or previously unknown faults are sometimes caused by the deep-injection disposal of fracking flowback fluid (a byproduct of hydraulically fracked wells),[35] and produced formation brine (a byproduct of both fractured and non-fractured oil and gas wells).[36] For these reasons, hydraulic fracturing is under international scrutiny, restricted in some countries, and banned altogether in others.[37][38][39] The European Union is drafting regulations that would permit the controlled application of hydraulic fracturing.[40] GeologyMechanicsFracturing rocks at great depth frequently become 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.[41][42] Fractures formed in this way are generally oriented in a plane perpendicular to the minimum principal stress, and for this reason, hydraulic fractures in wellbores can be used to determine the orientation of stresses.[43] In natural examples, such as dikes or vein-filled fractures, the orientations can be used to infer past states of stress.[44] VeinsMost mineral vein systems are a result of repeated natural fracturing during periods of relatively high pore fluid pressure. The effect 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.[45] 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".[46] DikesMinor 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.[47] HistoryPrecursors  Fracking as a method to stimulate shallow, hard rock oil wells dates back to the 1860s, though the general concept of using water pressure to destroy rock was known as early as ancient Rome, in the form of ruina montium. Dynamite or nitroglycerin detonations were used to increase oil and natural gas production from petroleum bearing formations. On 24 April 1865, US Civil War veteran Col. Edward A. L. Roberts received a patent for an "exploding torpedo".[48] It was employed in Pennsylvania, New York, Kentucky, Oklahoma, Texas, and West Virginia using liquid and also, later, solidified nitroglycerin. Companies like Lightning Torpedo Company used this process in Oklahoma and Texas. Later still the same method was applied to water and gas wells. Stimulation of wells with acid, instead of explosive fluids, was introduced in the 1930s. Due to acid etching, fractures would not close completely, resulting in further productivity increase.[49] 20th century applicationsHarold Hamm, Aubrey McClendon, Tom Ward and George P. Mitchell are each considered to have pioneered hydraulic fracking innovations toward practical applications.[50][51] Oil and gas wellsThe relationship between well performance and treatment pressures was studied by Floyd Farris of Stanolind Oil and Gas Corporation. This study was the basis of the first hydraulic fracturing experiment, conducted in 1947 at the Hugoton gas field in Grant County of southwestern Kansas by Stanolind.[13][52] 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 the 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 17 March 1949, Halliburton performed the first two commercial hydraulic fracking treatments in Stephens County, Oklahoma, and Archer County, Texas.[52] Since then, hydraulic fracking has been used to stimulate approximately one million oil and gas wells[53] in various geologic regimes with good success. In contrast with large-scale hydraulic fracturing used in low-permeability formations, small hydraulic fracturing treatments are commonly used in high-permeability formations to remedy "skin damage", a low-permeability zone that sometimes forms at the rock-borehole interface. In such cases the fracturing may extend only a few feet from the borehole.[54] In the Soviet Union, the first hydraulic proppant fracturing was carried out in 1952. Other countries in Europe and Northern Africa subsequently employed hydraulic fracturing techniques including Norway, Poland, Czechoslovakia (before 1989), Yugoslavia (before 1991), Hungary, Austria, France, Italy, Bulgaria, Romania, Turkey, Tunisia, and Algeria.[55] Massive fracturing  Massive hydraulic fracturing (also known as high-volume hydraulic fracturing) is a technique first applied by Pan American Petroleum in Stephens County, Oklahoma, US in 1968. The definition of massive hydraulic fracturing varies, but generally refers to treatments injecting over 150 short tons, or approximately 300,000 pounds (136 metric tonnes), of proppant.[56] American geologists gradually became 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.[56] Starting in 1973, massive hydraulic fracturing was used in thousands of gas wells in the San Juan Basin, Denver Basin,[57] the Piceance Basin,[58] and the Green River Basin, and in other hard rock formations of the western US. Other tight sandstone wells in the US made economically viable by massive hydraulic fracturing were in the Clinton-Medina Sandstone (Ohio, Pennsylvania, and New York), and Cotton Valley Sandstone (Texas and Louisiana).[56] 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 in the North Sea.[55] Horizontal oil or gas wells were unusual until the late 1980s. Then, 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 tight chalk;[59] sedimentary beds are usually nearly horizontal, so horizontal wells have much larger contact areas with the target formation.[60] Hydraulic fracturing operations have grown exponentially since the mid-1990s, when technologic advances and increases in the price of natural gas made this technique economically viable.[61] ShalesHydraulic fracturing of shales goes back at least to 1965, when some operators in the Big Sandy gas field of eastern Kentucky and southern West Virginia started hydraulically fracturing the Ohio Shale and Cleveland Shale, using relatively small fracs. The frac jobs generally increased production, especially from lower-yielding wells.[62] In 1976, the United States government started the Eastern Gas Shales Project, which included numerous public-private hydraulic fracturing demonstration projects.[63] 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.[64] In 1997, Nick Steinsberger, an engineer of Mitchell Energy (now part of Devon Energy), applied the slickwater fracturing technique, using more water and higher pump pressure than previous fracturing techniques, which was used in East Texas in the Barnett Shale of north Texas.[60] In 1998, the new technique proved to be successful when the first 90 days gas production from the well called S.H. Griffin No. 3 exceeded production of any of the company's previous wells.[65][66] This new completion technique made gas extraction widely economical in the Barnett Shale, and was later applied to other shales, including the Eagle Ford and Bakken Shale.[67][68][69] George P. Mitchell has been called the "father of fracking" because of his role in applying it in shales.[70] The first horizontal well in the Barnett Shale was drilled in 1991, but was not widely done in the Barnett until it was demonstrated that gas could be economically extracted from vertical wells in the Barnett.[60] As of 2013, massive hydraulic fracturing is being applied on a commercial scale to shales in the United States, Canada, and China. Several additional countries are planning to use hydraulic fracturing.[71][72][73] ProcessAccording to the United States Environmental Protection Agency (EPA), hydraulic fracturing is a process to stimulate a natural gas, oil, or geothermal well to maximize extraction. The EPA defines the broader process to include acquisition of source water, well construction, well stimulation, and waste disposal.[74] MethodA hydraulic fracture is formed by pumping fracturing fluid into a wellbore at a rate sufficient to increase pressure at the target depth (determined by the location of the well casing perforations), to exceed that of the fracture gradient (pressure gradient) of the rock.[75] The fracture gradient is defined as pressure increase per unit of depth relative to density, and is usually measured in pounds per square inch, per foot (psi/ft). The rock cracks, and the fracture fluid permeates the rock extending the crack further, and further, and so on. Fractures are localized as pressure drops off with the rate of frictional loss, which is relative to the distance from the well. Operators typically try to maintain "fracture width", or slow its decline following treatment, by introducing a proppant into the injected fluid – a material such as grains of sand, ceramic, or other particulate, thus preventing the fractures from closing when injection is stopped and pressure removed. Consideration of proppant strength 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 gas, oil, salt water and hydraulic fracturing fluids to the well.[75] During the process, fracturing fluid leakoff (loss of fracturing fluid from the fracture channel into the surrounding permeable rock) occurs. If not controlled, it can exceed 70% of the injected volume. This may result in formation matrix damage, adverse formation fluid interaction, and altered fracture geometry, thereby decreasing efficiency.[76] The location of one or more fractures along the length of the borehole is strictly controlled by various methods that create or seal 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.[77] 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[clarification needed], a chemical additive unit (used to accurately monitor chemical addition), fracking hose (low-pressure flexible hoses), and many gauges and meters for flow rate, fluid density, and treating pressure.[78] Chemical additives are typically 0.5% 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; 133 US bbl/min).[79] Well typesA distinction can be made between conventional, low-volume hydraulic fracturing, used to stimulate high-permeability reservoirs for a single well, and unconventional, high-volume hydraulic fracturing, used in the completion of tight gas and shale gas wells. High-volume hydraulic fracturing usually requires higher pressures than low-volume fracturing; the higher pressures are needed to push out larger volumes of fluid and proppant that extend farther from the borehole.[80] Horizontal drilling involves wellbores with a terminal drillhole 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 1,520 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 reduces surface disruptions as fewer wells are required to access the same volume of rock. Drilling often plugs up the pore spaces at the wellbore wall, reducing 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. Low-volume hydraulic fracturing can be used to restore permeability.[81] Fracturing fluids The main purposes of fracturing fluid are to extend fractures, add lubrication, change gel strength, and to carry proppant into the formation. There are two methods of transporting proppant in the fluid – 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.[82] Water-soluble gelling agents (such as guar gum) increase viscosity and efficiently deliver proppant into the formation.[83]  Fluid is typically a slurry of water, proppant, and chemical additives.[84] Additionally, gels, foams, and compressed gases, including nitrogen, carbon dioxide and air can be injected. Typically, 90% of the fluid is water and 9.5% is sand with chemical additives accounting to about 0.5%.[75][85][86] However, fracturing fluids have been developed using liquefied petroleum gas (LPG) and propane. This process is called waterless fracturing.[87] When propane is used it is turned into vapor by the high pressure and high temperature. The propane vapor and natural gas both return to the surface and can be collected, making it[clarification needed] easier to reuse and/or resale. None of the chemicals used will return to the surface. Only the propane used will return from what was used in the process.[88] The proppant is a granular material that prevents the created fractures from closing after the fracturing treatment. Types of proppant include silica sand, resin-coated sand, bauxite, and man-made ceramics. The choice of proppant depends on the type of permeability or grain strength needed. In some formations, where the pressure is great enough to crush grains of natural silica sand, higher-strength proppants such as bauxite or ceramics may be used. The most commonly used proppant is silica sand, though proppants of uniform size and shape, such as a ceramic proppant, are believed to be more effective.[89]  The fracturing fluid varies depending on fracturing type desired, and the conditions of specific wells being fractured, and water characteristics. The fluid can be gel, foam, or slickwater-based. Fluid choices are tradeoffs: more viscous fluids, such as gels, are better at keeping proppant in suspension; while less-viscous and lower-friction fluids, such as slickwater, allow fluid to be pumped at higher rates, to create fractures farther out from the wellbore. Important material properties of the fluid include viscosity, pH, various rheological factors, and others. Water is mixed with sand and chemicals to create hydraulic fracturing fluid. Approximately 40,000 gallons of chemicals are used per fracturing.[92] A typical fracture treatment uses between 3 and 12 additive chemicals.[75] Although there may be unconventional fracturing fluids, typical chemical additives can include one or more of the following:
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.[94] Typical fluid types are:
For slickwater fluids the use of sweeps is common. Sweeps are temporary reductions in the proppant concentration, which help ensure that the well is not overwhelmed with proppant.[95] As the fracturing process proceeds, viscosity-reducing agents such as oxidizers and enzyme breakers are sometimes added to the fracturing fluid to deactivate the gelling agents and encourage flowback.[83] Such oxidizers react with and break down the gel, reducing the fluid's viscosity and ensuring that no proppant is pulled from the formation. An enzyme acts as a catalyst for breaking down 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.[95] At the end of the job, the well is commonly flushed with water under pressure (sometimes blended with a friction reducing chemical.) Some (but not all) injected fluid is recovered. This fluid is managed by several methods, including underground injection control, treatment, discharge, recycling, and temporary storage in pits or containers. New technology is continually developing to better handle waste water and improve re-usability.[75] Fracture monitoringMeasurements of the pressure and rate during the growth of a hydraulic fracture, with knowledge of fluid properties 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.[75] Radionuclide monitoringInjection of radioactive tracers along with the fracturing fluid is sometimes used to determine the injection profile and location of created fractures.[96] Radiotracers are s | |||||||||||||||||||||||||||
