The International Energy Agency says yes, but it will take tougher regulations that force producers to apply the latest technologies.
Fracking, aka hydraulic fracturing, a process for freeing natural gas locked in shale deposits, has caused a boom in natural-gas production in the United States. But some experts worry that the practice results in contaminated drinking water and the release of methane, prompting some localities to limit shale-gas production.
A new analysis by the International Energy Agency says technologies exist—or are in development—that could largely address these concerns. If they’re adopted, fracking could be more widely accepted by governments around the world, leading to lower greenhouse-gas emissions and lower energy prices. It they’re not, governments could balk, and coal would maintain its dominant place in electricity generation.
The most well-known issue associated with fracking is concern over water use and contamination. Fracking consumes large amounts of water; roughly 20 million liters under high pressure are sent down each well to create the fractures in the rock that free the natural gas. That water use is a huge concern in places such as Texas and some areas of China that have large shale-gas resources and are prone to droughts.
Disposal of that wastewater is another concern. Fracking also has the potential to contaminate drinking water supplies and increase air pollution. And there are concerns that it could actually increase greenhouse-gas emissions due to methane leaks.
But the IEA report concludes that fracking, like many other practices in industries that involve hazardous chemicals, can be made relatively safe with regulation. The IEA estimates that the measures needed to make fracking safer would add about 7 percent to the cost of an average well.
Significant levels of methane, the main component of natural gas, have been found in drinking-water supplies near some fracking sites. Some environmentalists have suggested that the fracking process, which creates fractures in shale, could create a path for natural gas and other chemicals to reach aquifers and mix with drinking water.
But according to the IEA report, that doesn’t seem to be the problem in most cases. Fracking usually takes place hundreds of meters below aquifers, and it’s easy to stop the propagation of fractures. Cracking the rock requires high pressures. Stop applying the pressure, and the rock fracturing stops. However, some fracking sites are relatively near to the level of drinking water, and the IEA suggests it might make sense to ban the procedure at such locations.
The IEA says the contaminated water is most likely the result of producers building substandard natural-gas wells, which are lined with metal casings and cement to keep the natural gas from contaminating aquifers. But in some cases, producers have done a poor job of cementing, allowing channels for natural gas to form. “Whenever there was a gas leakage, it came out because the cement was not well done,” says Franz-Josef Ulm, a civil and environmental engineering professor at MIT. That problem could be solved by cementing properly and then carefully monitoring the well’s integrity. “When it comes to cementing, the solutions are out there. The question is whether they are being applied,” Ulm says.
New technology could greatly reduce the amount of pressure needed for fracking, making it far easier to build safe wells, Ulm says. Researchers are learning that shale is particularly fracture-resistant because of the presence of a small amount of organic material that binds together inorganic particles. Targeting these materials by applying a special solvent could weaken the shale and make it far easier to free the natural gas.
There are also opportunities to reduce water use by using fluids other than water—such as propane (which brings its own environmental challenges)—or mixing carbon dioxide or nitrogen with water to create foams. Eventually it may be possible to mix small amounts of water with solid particles designed to easily flow, Ulm says.
Another contamination fear involves the chemicals that fracking companies add to the water. The biggest concern isn’t the chemicals once they’re mixed with the water, since they’re so dilute, but rather the handling of the chemicals in concentrated form. Spills on the surface could soak into the ground and contaminate drinking water. The solution is to line the area where chemicals are handled with plastic and monitor any leaks. Researchers are also developing less-toxic chemicals, or techniques to eliminate the need for them.
Yet even if these chemicals can be dealt with, wastewater remains a challenge. The water that flows back to the surface is contaminated not only with the chemicals originally mixed in at the surface, but also with chemicals, heavy metals, and, in some cases, naturally occurring radioactive materials from deep underground.
As the water returns to the surface, natural gas and other hydrocarbons that were released by the fracking come with it. In many cases, that gas is allowed to escape into the atmosphere until the water stops flowing. The main component of natural gas—methane—is a greenhouse gas many times more powerful than carbon dioxide, so this practice could offset any greenhouse-gas emissions reductions that would come from burning natural gas rather than coal. However, simple technology exists to capture the natural gas at this stage.
Implementing these technologies will likely require regulation. “It can’t just be counting on companies to adopt best practices, because you’ll only have a certain percentage of the well operators doing it,” says Mark Boling, president of V+ Development Solutions, which is part of Southwestern Energy, a natural-gas producer. “You have to go the rest of the way and get regulations in place so that you have a level playing field and everyone is required to do the same thing.”
If done right, those regulations could drive innovation by creating a market for new technologies. Ulm recommends caps on emissions that give companies flexibility to choose the best technology. The IEA calls for a combination of such caps, and in some cases specific technology requirements. “With such regulations, you could force innovation to be implemented at a high pace. Technology is what it will take to make shale gas a sustainable resource,” Ulm says.
Definitions From Wikipedia
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From Wikipedia, the free encyclopedia
Hydraulic fracturing is the propagation of fractures in a rock layer caused by the presence of a pressurized fluid. Some hydraulic fractures form naturally, as in the case of veins or dikes, and are a means by which gas and petroleum from source rocks may migrate to reservoir rocks. Induced hydraulic fracturing or hydrofracking, commonly known as fracking, is a technique used to release petroleum, natural gas (including shale gas, tight gas and coal seam gas), or other substances for extraction.[a] This type of fracturing creates fractures from a wellbore drilled into reservoir rock formations.
The first use of hydraulic fracturing was in 1947, though the fracking technique which made the shale gas extraction economical was first used in 1997 in the Barnett Shale in Texas. The energy from the injection of a highly-pressurized fracking fluid creates new channels in the rock which can increase the extraction rates and ultimate recovery of fossil fuels.
Proponents of fracking point to the vast amounts of formerly inaccessible hydrocarbons the process can extract. Detractors point to potential environmental impacts, including contamination of ground water, risks to air quality, the migration of gases and hydraulic fracturing chemicals to the surface, surface contamination from spills and flowback and the health effects of these. For these reasons hydraulic fracturing has come under scrutiny internationally, with some countries suspending or even banning it.
Fracturing in rocks at depth is suppressed by the confining pressure, due to the load caused by the overlying rock strata. 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 reduced 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 typically be oriented perpendicularly to the minimum principal stress and for this reason, induced hydraulic fractures in wellbores are sometimes used to determine stress orientations. In natural examples, such as dikes or vein-filled fractures, their orientations can be used to infer past stress states.
Most vein systems are a result of repeated hydraulic fracturing during periods of relatively high pore fluid pressure. This is particularly clear 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 explain such examples of long-lasting repeated fracturing is the effects of seismic activity, in which the stress levels rise and fall episodically and large volumes of fluid may be expelled from fluid-filled fractures during earthquakes. This process is referred to as ‘seismic pumping’.
High-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 industries in 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 a well stimulation was introduced in the 1930s. Due to acid etching, created fractures would not close completely and therefore enhanced productivity. The same phenomenon was discovered with water injection and squeeze cementing operations.
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 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 the Soviet Union, the first hydraulic proppant fracturing was carried out in 1952. In Western Europe, in 1977–1985 hydraulic fracturing was conducted at Rotliegend and Carboniferous gas-bearing sandstones in Germany, Netherlands onshore and offshore gas fields, and the United Kingdoms sector of the North Sea. Other countries in Europe and Northern Africa included Norway, the Soviet Union, Poland, Czechoslovakia, Yugoslavia, Hungary, Austria, France, Italy, Bulgaria, Romania, Turkey, Tunisia, and Algeria. 
Due to shale’s high porosity and low permeability, technology research, development and demonstration were necessary before hydraulic fracturing could be commercially applied to shale gas deposits. In the 1970s the federal government initiated both the Eastern Gas Shales Project, a set of dozens of public-private hydro-fracturing pilot demonstration projects, and the Gas Research Institute, a gas industry research consortium that received approval for research and funding from the Federal Energy Regulatory Commission. In 1977, the Department of Energy pioneered massive hydraulic fracturing in tight sandstone formations. 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’ that made the shale gas extraction economical.
In 2011, France became the first nation to ban the hydraulic fracturing.