hydraulic fracturing in the United States

Fracking in the United States began in 1949. According to the Department of Energy (DOE), by 2013 at least two million oil and gas wells in the US had been hydraulically fractured, and that of new wells being drilled, up to 95% are hydraulically fractured. The output from these wells makes up 43% of the oil production and 67% of the natural gas production in the United States.US Dept. of Energy
How is shale gas produced?
Apr. 2013. Environmental safety and health concerns about hydraulic fracturing emerged in the 1980s, and are still being debated at the state and federal levels.

New York banned massive hydraulic fracturing by executive order in 2010, so all natural gas production in the state is from wells drilled prior to the ban. Vermont, which has no known frackable gas reserves, banned fracking preventatively in May 2012. In March 2017, Maryland became the second state in the US with proven gas reserves to pass a law banning fracking. On May 8, 2019, Washington became the fourth state to ban fracking when Governor Jay Inslee signed SB 5145 into law after it passed the State Senate by a vote of 29-18 and the House 61–37. Washington is a non-oil and gas state that had no fracking operations when the bill was passed.

An imbalance in the supply-demand dynamics for the oil and gas produced by hydraulic fracturing in the Permian Basin of west Texas is an increasing challenge for the local industry, as well as a growing impact to the environment. In 2018, so much excess natural gas was produced with oil that prices turned negative and wasteful flaring increased to a record 400 million cubic feet per day. By Q3 of 2019, the wasted gas from this region alone almost doubled to 750 million cubic feet per day, an amount more than capable of supplying the entire residential needs of the state.

History

Non-hydraulic fracturing

Fracturing as a method to stimulate shallow, hard rock oil wells dates back to the 1860s. Oil producers in Pennsylvania, New York, Kentucky, and West Virginia used nitroglycerin (liquid at first, and later solid) to break up the oil-bearing formation. The method was later applied to water and natural gas wells. The idea of using acid as a nonexplosive fluid for well stimulation was introduced in the 1930s. Acid etching kept fractures open and enhanced productivity. Water injection and squeeze cementing (injection of cement slurry) had a similar effect.

Quarrying

The first industrial use of hydraulic fracturing was as early as 1903, according to T.L. Watson of the U.S. Geological Survey. Before that date, hydraulic fracturing was used at Mt. Airy Quarry, near Mt Airy, North Carolina where it was (and still is) used to separate granite blocks from bedrock.

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 of gelled gasoline and sand from the Arkansas River was injected into the gas-producing limestone formation at . 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. The practice caught on quickly, and in June 1950, ''Newsweek'' reported that 300 oil wells had been treated with the new technique. In 1965, a US Bureau of Mines publication wrote of hydraulic fracturing: "Many fields are in existence today because of these fracturing techniques for, without them, many producing horizons would have been bypassed in the past 15 years as either barren or commercially nonproductive."

Massive hydraulic fracturing

In the 1960s, American geologists became increasingly aware of huge volumes of gas-saturated rocks with permeability too low (generally less than 0.1 milli darcy) to recover the gas economically. The US government experimented with using underground nuclear explosions to fracture the rock and enable gas recovery from the rock. Such explosions were tried in the San Juan Basin of New Mexico (Project Gasbuggy, 1967), and the Piceance Basin of Western Colorado (Project Rulison, 1969, and Project Rio Blanco, 1973) but the results were disappointing, and the tests were halted. The petroleum industry turned to the new massive hydraulic fracturing technique as the way to recover tight gas.

The definition of a massive hydraulic fracturing varies somewhat, but is generally used for treatments injecting greater than about 300,000 pounds of proppant (136 tonnes).Ben E. Law and Charles W. Spencer, 1993, "Gas in tight reservoirs-an emerging major source of energy," ''in'' David G. Howell (ed.),
The Future of Energy Gases
', US Geological Survey, Professional Paper 1570, p.233–252. Pan American Petroleum applied the first massive hydraulic fracturing (also known as high-volume hydraulic fracturing) treatment in the world to a well in Stephens County, Oklahoma in 1968. The treatment injected half a million pounds of proppant into the rock formation.

In 1973, Amoco introduced massive hydraulic fracturing to the Wattenberg Gas Field of the Denver Basin of Colorado, to recover gas from the low-permeability J Sandstone. Before massive hydraulic fracturing, the Wattenberg field was uneconomic. Injected volumes of 132,000 or more gallons, and 200,000 or more pounds of sand proppant, succeeded in recovering much greater volumes of gas than had been previously possible. In 1974, Amoco performed the first million-pound frac job, injecting more than a million pounds of proppant into the J Sand of a well in Wattenberg Field.

The success of massive hydraulic fracturing in the Wattenberg Field of Colorado was followed in the late 1970s by its use in gas wells drilled to tight sandstones of the Mesaverde Group of the Piceance Basin of western Colorado.

Starting in the 1970s. thousands of tight-sandstone gas wells in the US were stimulated by massive hydraulic fracturing. Examples of areas made economic by the technology include the Clinton-Medina Sandstone play in Ohio, Pennsylvania, and New York; the San Juan Basin in New Mexico and Colorado; numerous fields in the Green River Basin of Wyoming; and the Cotton Valley Sandstone trend of Louisiana and Texas.

Coalbed methane wells

Coalbed methane wells, which first began to be drilled in the 1980s, are commonly hydraulically fractured to increase the flow rates to the well. Hydraulic fracturing is commonly used in some coalbed methane areas, such as the Black Warrior Basin and the Raton Basin, but not in others, such as the Powder River Basin, depending on the local geology. Injected volumes tend to be much smaller than those of either tight gas wells or shale gas wells; a 2004 EPA study found a median injected volume of for coalbed methane wells.

Horizontal wells

The combination of horizontal drilling and multistage hydraulic fracturing was pioneered in Texas’ Austin Chalk play in the 1980s. Stephen Holdich, head of the Department of Petroleum Engineering at Texas A&M University, commented: “In fact, the Austin Chalk is the model for modern shale development methods.” The Austin Chalk play started in 1981 with vertical wells, but died with the decline in the oil price in 1982. In 1983, Maurer Engineering designed the equipment to drill the first medium-range horizontal well in the Austin Chalk. Horizontal drilling revived the play by increasing production, and lengths of the horizontal parts of the wellbores grew with greater experience and improvements in drilling technology. Union Pacific Resources, later acquired by Anadarko Petroleum, entered the Austin Chalk play in a major way in 1987, and drilled more than a thousand horizontal wells in the Austin Chalk, with multistage massive slickwater hydraulic fracture treatments, making major improvements in drilling and fracturing techniques.

Shales

Hydraulic 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.

From 1976 to 1992 the United States government funded the Eastern Gas Shales Project, a set of dozens of public-private hydro-fracturing pilot demonstration projects. The program made a number of advances in hydraulic fracturing of shales. 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, 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 by Union Pacific Resources, in the Barnett Shale of north Texas. 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. This new completion technique made gas extraction widely economical in the Barnett Shale, and was later applied to other shales. George P. Mitchell has been called the "father of fracking" because of his role in applying it in shales. 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.

Between 2005 and 2010 the shale-gas industry in the United States grew by 45% a year. As a proportion of the country's overall gas production, shale gas increased from 4% in 2005 to 24% in 2012.

According to oilfield services company Halliburton, as of 2013 more than 1.1 million hydraulic fracturing jobs have been done in the United States (some wells are hydraulically fractured more than once), and almost 90% of new US onshore oil and gas wells are hydraulically fractured.

Typical extraction process

The process of extracting shale oil or gas typically has several stages, including some legal preliminaries. First, a company must negotiate the mineral rights with the owners.

After a company has leased the mineral rights, it must obtain a permit to drill a well. Permits are regulated by state agencies and the requirements vary. Once it has obtained the permit, the company clears an area of 4–5 acres for a stage bed; it may also construct roads, a waste water site, and a temporary gas storage facility. Next is the drilling and casing of the well. In a process similar to that for constructing water wells, a bore machine drills vertically in the ground, and two or more steel casings are set in the well in a reverse telescope manner. The casing helps keep the well open by providing structural support and preventing fluid and gas flow into the surrounding ground. Once the casing is in place, cement is pumped down inside the casing and back up on the outside of the casing. This is done to cement the casing in the formation and to prevent any leakage or flow of the gas and fluids behind the casing.

The next step is the fracturing itself. A mixture of water and chemical additives are pumped down the well at high pressure. This creates fractures in the rock, and a proppant such as sand is injected to keep the fracture open. This allows the natural gas to flow to the well and up to the surface. The fracturing phase takes a few days, and the recovery enhancement success of the fracturing job depends on a number of in-situ and operational parameters.

After all this preparation, the well has a few years of production where natural gas is brought to the surface, treated, and carried off. This may be punctuated by workovers during which the well is cleaned and maintained to increase production. When the well has been exhausted, it is plugged. The area around it is restored to the level required by state standards and the agreement with the owner.

Economic impact

Hydraulic fracturing of tight oil and shale gas deposits has the potential to alter the geography of energy production in the US.Fracking Growth – Estimating the Economic Impact of Shale Oil and Gas Development in the US
Fetzer, Thiemo (2014)Dutch Disease or Agglomeration? The Local Economic Effects of Natural Resource Booms in Modern America
Alcott and Kenniston (2013) In the short run, in counties with hydrofracturing employment in the oil and gas sector more than doubled in the last 10 years, with spill-overs in local transportation, construction, and manufacturing sectors. The manufacturing sector benefits from lower energy prices, giving the US manufacturing sector a competitive edge. On average, natural gas prices have decreased by more than 30% in counties above shale deposits compared to the rest of the US. Some research has highlighted the negative effects on house prices for properties in the direct vicinity of fracturing wells."The housing market impacts of shale gas development", by Lucija Muehlenbachs, Elisheba Spiller and Christopher Timmins. NBER Working Paper 19796, January 2014. Local house prices in Pennsylvania decrease if the property is close to a hydrofracking gas well and is not connected to city water, suggesting that the concerns of ground water pollution are priced by markets.

Oil and gas supply

The National Petroleum Council estimates that hydraulic fracturing will eventually account for nearly 70% of natural gas development in North America. In 2009, the American Petroleum Institute estimated that 45% of the United States natural gas production and 17% of oil production would be lost within 5 years without usage of hydraulic fracturing.

Of US gas production in 2010, 26% came from tight sandstone reservoirs and 23% from shales, for a total of 49%. As production increased, there was less need for imports: in 2012, the US imported 32% less natural gas than it had in 2007. In 2013, the US Energy Information Administration projected that imports will continue to shrink and the US will become a net exporter of natural gas some time around 2020.

Increased US oil production from hydraulically fractured tight oil wells was mostly responsible for the decrease in US oil imports since 2005 (decreased oil consumption was also an important component). The US imported 52% of its oil in 2011, down from 65% in 2005. Hydraulically fractured wells in the Bakken, Eagle Ford, and other tight oil targets, enabled US crude oil production to rise in September 2013 to the highest output since 1989.

Proponents of hydraulic fracturing touted its potential to make the United States the world's largest oil producer and make it an energy leader, a feat it achieved in November 2012 having already surpassed Russia as the world's leading gas producer. Proponents say that hydraulic fracturing would give the United States energy independence. In 2012, the International Energy Agency (IEA) projected that the United States, now the world's third-largest oil producer behind Saudi Arabia and Russia, will see such an increase in oil from shales that the US will become the world's top oil producer by 2020. In 2011 the US became the world's leading producer of natural gas when it outproduced Russia. In October 2013, the US Energy Information Administration projected that the US had surpassed Russia and Saudi Arabia to become the world's leading producer of combined oil and natural gas hydrocarbons.

Globally, gas use is expected to rise by more than 50% compared to 2010 levels, and account for over 25% of world energy demand in 2035. Anticipated demand and higher prices abroad have motivated non-US companies to buy shares and invest in US gas and oil companies, and in the case of the Norwegian company Statoil, to buy an American company with hydraulic fracturing expertise and US shale oil production.

Some geologists say that the well productivity estimates are inflated and minimize the impact of the reduced productivity of wells after the first year or two. A June 2011 ''New York Times'' investigation of industrial emails and internal documents found that the profitability of unconventional shale gas extraction may be less than previously thought, due to companies intentionally overstating the productivity of their wells and the size of their reserves. The same article said, "Many people within the industry remain confident." Financier T. Boone Pickens said that he was not worried about shale companies and that he believed they would make good money if prices rise. Pickens also said that technological advances, such as the repeated hydraulic fracturing of wells, was making production cheaper. Some companies that specialize in shale gas have shifted to areas where the gas in natural gas liquids such as propane and butane. The article was criticized by, among others, ''The New York Times'' own public editor for lack of balance in omitting facts and viewpoints favorable to shale gas production and economics.

Gas price

According to the World Bank, as of November 2012, the increased gas production due to horizontal drilling and hydraulic fracturing in the US had driven US gas prices down to 29% of natural gas prices in Europe, and to one-fifth of natural gas prices in Japan. Lower natural gas prices in the US have encouraged the replacement of coal- with gas-fired power plants, but have also discouraged the switch to renewable sources of energy. Facing a supply glut and consequent further price drops in 2012, some large US gas producers announced plans to cut natural gas production; however, production rates rose to all-time highs, and natural gas prices remained near ten-year lows. The high price of gas overseas has provided a strong incentive for producers to export it.

Exports

U.S.-based refineries have gained a competitive edge with their access to relatively inexpensive shale oil and Canadian crude. The U.S. is exporting more refined petroleum products, and also more liquified petroleum gas (LP gas). LP gas is produced from hydrocarbons called natural gas liquids, released by the hydraulic fracturing of petroliferous shale, in a variety of shale gas that's relatively easy to export. Propane, for example, costs around $620 a ton in the U.S. compared with more than $1,000 a ton in China, as of early 2014. Japan, for instance, is importing extra LP gas to fuel power plants, replacing idled nuclear plants. Trafigura Beheer BV, the third-largest independent trader of crude oil and refined products, said at the start of 2014 that "growth in U.S. shale production has turned the distillates market on its head".

In 2012, the U.S. imported of natural gas and exported . Of the exports, was sent by pipeline to Canada and Mexico; was re-exports of foreign shipments (bought at low prices and then held until the price went up); and the remaining was exported as liquefied natural gas (LNG) – natural gas that has been liquefied by cooling to about −161 degrees Celsius, reducing the volume by a factor of 600.

The US has two export terminals: one owned by Cheniere Energy in Sabine Pass, Louisiana, and a ConocoPhillips terminal in North Cook Inlet, Alaska. Companies that wish to export LNG must pass a two-step regulatory process required by the Natural Gas Act of 1938. First, the United States Department of Energy (DOE) must certify that the project is consistent with the public interest. This approval is automatic for export to the twenty countries that have a free trade agreement with the United States. Applications for export to non-FTA countries are published in the Federal Register and public comment is invited; but the burden of proof for any public harm rests with opponents of the application, so opposition by groups such as the Sierra Club has so far not blocked any approvals. In addition, the Federal Energy Regulatory Commission (FERC) must conduct an environmental review and approve the export facility. As of 2013, only one facility – the Sabine Pass terminal in Cameron Parish, Louisiana, run by Cheniere Energy – had both DOE and FERC approval and was under construction. Three others – Trunkline LNG in Lake Charles, Louisiana; Dominion Cove Point LNG in Lusby, Maryland; and a terminal in Freeport, Texas – have DOE approval and await FERC approval. On January 30, 2014, Cheniere Energy signed an agreement to supply 3.5 million tons to Korean Gas Corporation.

A partnership of three companies (UGI Corporation, Inergy Midstream L.P. and Capitol Energy Ventures) has proposed building a new pipeline connecting the Marcellus Shale formation with markets in Pennsylvania and Maryland. The pipeline would also supply LNG export terminals in Maryland.

Critics have charged that exporting LNG could threaten the national energy security provided by gas from hydraulically fractured shale gas wells.

Because of its carbon intensity, taking into account its lifecycle emissions, the IEA's Net Zero Emissions road map, projects a rapid collapse in the trade of liquified natural gas, if the world implements the Paris Agreement.

Jobs

Economic effects of hydraulic fracturing include increases in jobs and by extension and increases in business. The Environmental Protection Agency (EPA) states that it is unclear on a local level how and for how long hydraulic fracturing affects a community economically. It is hypothesized that hydraulic fracturing may not provide jobs to local communities due to the specialized nature of hydraulic fracturing tasks. Also, communities’ local resources could potentially be taxed due to the increase in industry traffic or if an accident occurs. According to Benson (2016), siting a study completed by The U.S. Chamber of Commerce's Institute for 21st Century Energy, a fracking ban in the United States would result in 14.8 million jobs being cut by the year 2022. A potential ban would lead to a $4000 increase in the cost of living for a family, gas and electricity prices would rise by 400 percent, household income would drop by $873 billion and the gross domestic product would fall by $1.6 trillion.

Property owners

In most countries mineral rights belong to the government, but in the United States the default ownership is '' fee simple'', meaning that a land owner also has the rights to the subsurface and the air above the property. However, the Stock-Raising Homestead Act of 1916 split the ownership, reserving mineral rights for the federal government in large parts of western states. The owners of the rights can also choose to split the rights. Since the hydraulic fracturing boom started, home builders and developers – including D. R. Horton, the nation's biggest home builder; Ryland Homes; Pulte Homes; and Beazer Homes USA – have retained the subsurface rights to tens of thousands of homes in states where shale plays exist or are possible. In most states, they are not legally required to disclose this, and many of the home buyers are unaware they do not own the mineral rights. Under split estate law, the surface owner must allow the mineral rights owner reasonable access. Protections for the surface owner vary; in some states an agreement is required that compensates them for the use of the land and reclaims the land after extraction is complete.

Since the presence of oil or gas is uncertain, the company usually signs a lease with a signing bonus and a percentage of the value at the wellhead as a royalty. Concerns have been raised regarding the terms and clarity of the leases energy companies are signing with landowners, as well as the manner in which they are sold and the tactics used by companies in implementing them.

A well on one property can drain oil or gas from neighboring properties, and horizontal drilling can facilitate this. In some parts of the U.S., the ''rule of capture'' gives the landowner rights to any resources they extract from their well. Other states have ''unitization'' rules for sharing royalties based on the geometries of the reservoir and the property lines above it.

A lease of oil and gas rights violates the terms of many mortgage agreements, including those used by Fannie Mae and Freddie Mac

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