Chronic solvent-induced encephalopathy (CSE) is a condition induced by long-term exposure to organic solvents, often—but not always—in the workplace, that lead to a wide variety of persisting sensorimotor polyneuropathies and neurobehavioral deficits even after solvent exposure has been removed. This syndrome can also be referred to as psycho-organic syndrome, organic solvent syndrome, chronic painter's syndrome, occupational solvent encephalopathy, solvent intoxication, toxic solvent syndrome, painters disease, chronic toxic encephalopathy, or neurasthenic syndrome.
The multiple names of solvent-induced syndromes combined with
inconsistency in research methods makes referencing this disease
difficult and its catalog of symptoms vague.
Symptoms and signs
Two characteristic symptoms of CSE are deterioration of memory (particularly short-term memory), and attention
impairments. There are, however, numerous other symptoms that accompany
to varying degrees. Variability in the research methods studying CSE
makes characterizing these symptoms difficult, and some may be
questionable regarding whether they are actual symptoms of
solvent-induced syndromes, simply because of how infrequently they
appear.
Characterizing of CSE symptoms is more difficult because CSE is
currently poorly defined, and the mechanism behind it is not understood
yet.
Neurological
Reported neurological symptoms include difficulty sleeping, decrease in intellectual capacity, dizziness, altered visual perceptive abilities, affected psychomotor skills, forgetfulness, and disorientation.The mechanism behind these symptoms beyond solvent molecules crossing
the blood–brain barrier is currently unknown. Neurological signs include
impaired vibratory sensation at extremities and an inability to maintain steady motion, a possible effect from psychomotor damage in the brain. Other symptoms that have been seen include fatigue, decreased strength, and unusual gait.
One study found that there was a correlation between decreased red
blood cell count and level of solvent exposure, but not enough data has
been found to support any blood tests to screen for CSE.
Sensory alterations
A 1988 study indicated that some solvent-exposed workers developed loss of smell or damage to color vision; however this may or may not have been actually caused by exposure to organic solvents. There is other evidence for subtle impairment of color vision (especially impairment of Tritan color or "blue-yellow" color discernment), synergistic exacerbation of hearing loss, and loss of the sense of smell (anosmia).
Psychological symptoms of CSE that have been reported include mood swings, increased irritability, depression, a lack of initiative, uncontrollable and intense displays of emotion such as spontaneous laughing or crying, and a severe lack of interest in sex.
Some psychological symptoms are believed to be linked to frustration
with other symptoms, neurological, or pathophysiological symptoms of
CSE. A case study of a painter diagnosed with CSE reported that the
patient frequently felt defensive, irritable, and depressed because of
his memory deficiencies.
Causes
Organic solvents that cause CSE are characterized as volatile, blood soluble, lipophilic compounds that are typically liquids at normal temperature.
These can be compounds or mixtures used to extract, dissolve, or
suspend non-water-soluble materials such as fats, oils, lipids,
cellulose derivatives, waxes, plastics, and polymers. These solvents are
often used industrially in the production of paints, glues, coatings,
degreasing agents, dyes, polymers, pharmaceuticals, and printing inks.
Some common organic solvents known to cause CSE include formaldehyde, acetates, and alcohols.
Exposure to solvents can occur by inhalation,
ingestion, or direct absorption through the skin. Of the three,
inhalation is the most common form of exposure, with the solvent able to
rapidly pass through lung membranes and then into fatty tissue or cell
membranes. Once in the bloodstream, organic solvents easily cross the blood–brain barrier, due to their lipophilic properties. However, the sequence of effects that these solvents have on the brain is not yet fully understood.
Diagnosis
Due to its non-specific nature, diagnosing CSE requires a multidisciplinary "Solvent Team" typically consisting of a neurologist, occupational physician, occupational hygienist, neuropsychologist, and sometimes a psychiatrist or toxicologist.
Together, the team of specialists assess the patient's history of
exposure, symptoms, and course of symptom development relative to the
amount and duration of exposure, presence of neurological signs, and any
existing neuropsychological impairment.
Furthermore, CSE must be diagnosed "by exclusion". This means
that all other possible causes of the patient's symptoms must first be
ruled out beforehand. Because screening and assessing for CSE is a
complex and time-consuming procedure requiring several specialists of
multiple fields, few cases of CSE are formally diagnosed in the medical
field. This may, in part, be a reason for the syndrome's lack of
widespread recognition. The solvents responsible for neurological
effects dissipate quickly after an exposure, leaving only indirect
evidence of their presence, in the form of temporary or permanent
impairments.
Brain imaging techniques which have been explored in research have shown little promise as alternative methods to diagnose CSE. Neuroradiology and functional imaging have shown mild cortical atrophy, and effects in dopamine-mediated frontostriatal circuits in some cases. Examinations of regional cerebral blood flow in some imaging techniques have also shown some cerebrovascular abnormalities in patients with CSE, but the data were not different enough from healthy patients to be considered significant. The most promising brain imaging technique being studied currently is functional magnetic resonance imaging (fMRI) but as of now, no specific brain imaging techniques are available to reliably diagnose CSE.
Classification
Introduced by a working group from the World Health Organization
(WHO) in 1985, WHO diagnostic criteria states that CSE can occur in
three stages, organic affective syndrome (type I), mild chronic toxic
encephalopathy (type II), and severe chronic toxic encephalopathy (type
III). Shortly after, a workshop in Raleigh-Durham, NC
(United States) released a second diagnostic criterion which recognizes
four stages as symptoms only (type 1), sustained personality or mood swings (type 2A), impairment of intellectual function (type 2B), and dementia
(type 3). Though not identical, the WHO and Raleigh criteria are
relatively comparable. WHO type I and Raleigh types 1 and 2A are
believed to encompass the same stages of CSE, and WHO type II and
Raleigh type 2B both involve deficiencies in memory and attention.
No other international classifications for CSE have been proposed, and
neither the WHO nor Raleigh criteria have been uniformly accepted for
epidemiological studies.
Treatment
Like
diagnosis, treating CSE is difficult because it is vaguely defined and
data on the mechanism of CSE effects on neural tissue are lacking. There
is no existing treatment that is effective at completely recovering any
neurological or physical function lost due to CSE. This is believed to
be because of the limited regeneration capabilities in the central nervous system.
Furthermore, existing symptoms of CSE can potentially worsen with age.
Some symptoms of CSE, such as depression and sleep issues, can be
treated separately, and therapy is available to help patients adjust to
any untreatable disabilities. Current management for CSE involves
treating accompanying psychopathology, symptoms, and preventing further deterioration.
History
Cases
of CSE have been studied predominantly in northern Europe, though
documented cases have been found in other countries such as the United
States, France, and China. The first documented evidence for CSE was in
the early 1960s from a paper published by Helena Hanninen, a Finnish
neuropsychologist. Her paper described a case of workers who developed carbon disulfide intoxication at a rubber manufacturing company and coined the term "psycho-organic syndrome".Studies of solvent effects on intellectual functioning, memory, and
concentration were carried out in the Nordic countries, with Denmark
spearheading the research. Growing awareness of the syndrome in the
Nordic countries occurred in the 1970s.
To reduce cases of CSE in the workforce, a diagnostic criterion
for CSE appeared on information notices in occupational disease records
in the European Commission.
Following, from 1998 to 2004, was a health surveillance program for CSE
cases among construction painters in the Netherlands. By 2000, a ban
was put into action against using solvent-based paints
indoors, which resulted in a considerable reduction of solvent exposure
to painters. As a result, the number of CSE cases dropped substantially
after 2002. In 2005–2007, no new CSE cases were diagnosed among
construction painters in the Netherlands, and no occupational CSE has
been encountered in workers under thirty years of age in Finland since
1995.
Though movements to reduce CSE have been successful, CSE still
poses an issue to many workers that are at occupational risk. Statistics
published in 2012 by Nicole Cherry et al. claim that at least 20% of
employees in Finland still encounter organic solvents at the workplace,
and 10% of them experience some form of disadvantage from the exposure.
In Norway, 11% of the male population of workers and 7% of female
workers are still exposed to solvents daily and as of 2006, the country
has the highest rate of diagnosed CSE in Europe. Furthermore, due to the complexity of screening for CSE, there is still a high likelihood of a population of undiagnosed cases.
Occupations that have been found to have higher risk of causing
CSE are painter, printer, industrial cleaner, and paint or glue
manufacturer.
Of them, painters have been found to have the highest recorded
incidence of CSE. Spray painters in particular have higher exposure
intensities than other painters. Studies of instances of CSE have specifically been carried out in naval dockyards, mineral fiber manufacturing companies, and rayon viscose plants.
The world's 932 giant oil and gas fields are considered those with 500 million barrels (79,000,000 m3) of ultimately recoverable oil or gas equivalent. Geoscientists believe these giants account for 40 percent of the world's petroleum reserves. They are clustered in 27 regions of the world, with the largest clusters in the Persian Gulf and Western Siberian basin. The past three decades reflect declines in discoveries of giant fields.
The years 2000–11 reflect an upturn in discoveries and appears on track
to be the third best decade for discovery of giant oil and gas fields
in the 150-year history of modern oil and gas exploration.
Recent work in tracking giant oil and gas fields follows the earlier efforts of the late exploration geologist Michel T. Halbouty, who tracked trends in giant discoveries from the 1960s to 2004.
Tectonic settings
Geophysicists and exploration geologists
who look for oil and gas fields classify the subsurface
characteristics, or tectonic setting, of geological structures that
contain hydrocarbons. Any one oil and gas field may reflect influences
from multiple geological periods and events, but geoscientists often
attempt to characterize a field based on the dominant geological event
that influenced the structure's ability to trap and contain oil and gas
in recoverable quantities.
A majority of the world's giant oil and gas fields exist in two characteristic tectonic settings—passive margin
and rift environments. Passive margins are found along the edges of
major ocean basins, such as the Atlantic coast of Brazil where oil and
gas has been located in large quantities in the Campos basin. Rifts are
oceanic ridges formed when tectonic plates separate and a new crust is
created. The North Sea is an example of a rift setting associated with
prodigious hydrocarbon reserves.
Geoscientists theorize that both zones are especially conducive to
forming giant oil and gas fields when they are distant from active
tectonic areas. Stability appears to be conducive to trapping and
retaining hydrocarbons under the subsurface.
Four other common tectonic settings, including collisional
margins, strike-slip margins, and subduction margins, are associated
with the formation of giant oil and gas fields, though not to the
dominant extent of passive margin and rift settings.
Recent and future giants
Based
on the locations of past giants, Mann et al. predicted new discoveries
of giant oil and gas fields would mainly be made in passive margin and
rift environments, especially in deepwater basins. They also predicted
that existing areas that have produced giant fields would be likely
targets for new discoveries of "elephants", as the fields are sometimes
known in the oil and gas industry.
Data from 2000–07 reflect the accuracy of their predictions. The
79 new giant oil and gas fields discovered from 2000–07 tended to be
located in similar tectonic settings as the previously documented giants
from 1868–2000, with 36 percent along passive margins, 30 percent in
rift zones or overlying sags (structures associated with rifts), and 20
percent in collisional zones.
Despite a recent uptick in the number of giant oil and gas
fields, discovery of giants appears to have peaked in the 1960s and
1970s. Looking to the future, geoscientists foresee a continuation of
the recent trend of discovering more giant gas fields than oil fields.
Two major continental regions—Antarctica and the Arctic—remain
largely unexplored. Beyond them, however, trends suggest that remaining
giant fields will be discovered in "in-fill" areas where past giants
have been clustered and in frontier, or new, areas that correspond to
the predominant tectonic settings of past giants.
Giant field production properties and behaviour
Comprehensive
analysis of the production from the majority of the world's giant oil
fields has shown their enormous importance for global oil production. For instance, the 20 largest oil fields in the world alone account for roughly 25% of the total oil production.
Further analysis shows that giant oil fields typically reach
their maximum production before 50% of the ultimate recoverable volume
has been extracted.
A strong correlation between depletion and the rate of decline was also
found in that study, indicating that much new technology has only been
able to temporarily decrease depletion at the expense of rapid future
decline. This is exactly the case in the Cantarell Field.
In the petroleum industry, the term "North Sea" often includes areas such as the Norwegian Sea
and the area known as "West of Shetland", "the Atlantic Frontier" or
"the Atlantic Margin" that is not geographically part of the North Sea.
Brent crude is still used today as a standard benchmark for pricing oil, although the contract now refers to a blend of oils from fields in the northern North Sea.
From the 1960s to 2014 it was reported that 42 billion barrels of
oil equivalent (BOE) had been extracted from the North Sea since when
production began. As there is still an estimated 24 billion BOE
potentially remaining in the reservoir (equivalent to about 35 years
worth of production), the North Sea will remain as an important
petroleum reservoir for years to come. However, this is the upper end of a range of estimates provided by Sir Ian Wood (commissioned by the UK government to carry out a review of the oil industry in the United Kingdom); the lower end was 12 billion barrels. Wood, upset with how his
figures were being used, said the most likely amount to be found would
be between 15 billion and 16 billion barrels.
History
1851–1963
Commercial extraction of oil on the shores of the North Sea dates back to 1851, when James Youngretorted oil from torbanite (boghead coal, or oil shale) mined in the Midland Valley of Scotland.
Across the sea in Germany, oil was found in the Wietze field near
Hanover in 1859, leading to the discovery of seventy more fields, mostly
in Lower Cretaceous and Jurassic reservoirs, producing a combined total of around 1340 m³ (8,400 barrels) per day.
Gas was found by chance in a water well near Hamburg in 1910, leading to minor gas discoveries in Zechstein dolomites elsewhere in Germany. In England, BP discovered gas in similar reservoirs in the Eskdale anticline in 1938, and in 1939 they found commercial oil in Carboniferous rocks at Eakring in Nottinghamshire. Discoveries elsewhere in the East Midlands lifted production to 400 m³ (2,500 barrels) per day, and a second wave of exploration from 1953 to 1961 found the Gainsborough field and ten smaller fields.
The Netherlands' first oil shows were seen in a drilling demonstration at De Mient during the 1938 World Petroleum Congress at The Hague. Subsequent exploration led to the 1943 discovery by Exploratie Nederland, part of the Royal Dutch/Shell company Bataafsche Petroleum Maatschappij, of oil under the Dutch village of Schoonebeek, near the German border. NAM found the Netherlands' first gas in Zechstein carbonates at Coevorden in 1948. 1952 saw the first exploration well in the province of Groningen, Haren-1, which was the first to penetrate the Lower Permian Rotliegendes sandstone that is the main reservoir for the gas fields of the southern North Sea, although in Haren-1 it contained only water.
The Ten Boer well failed to reach target depth for technical reasons,
but was completed as a minor gas producer from the Zechstein carbonates. The Slochteren-1 well found gas in the Rotliegendes in 1959, although the full extent of what became known as the Groningen gas field was not appreciated until 1963—it is currently estimated at ≈96×1012 cu ft (2,700 km3) recoverable gas reserves. Smaller discoveries to the west of Groningen followed.
1964–present
The
UK Continental Shelf Act came into force in May 1964. Seismic
exploration and the first well followed later that year. It and a second
well on the Mid North Sea High were dry, as the Rotliegendes was
absent, but BP's Sea Gem rig struck gas in the West Sole Field in September 1965. The celebrations were short-lived since the Sea Gem sank, with the loss of 13 lives, after part of the rig collapsed as it was moved away from the discovery well. The Viking Gas Field was discovered in December 1965 with the Conoco/National Coal Board well 49/17-1, finding the gas-bearing PermianRotliegendSandstone at a depth of 2,756 m subsea. Helicopters were first used to transport workers.
Larger gas finds followed in 1966 – Leman Bank, Indefatigable and
Hewett – but by 1968 companies had lost interest in further exploration
of the British sector, a result of a ban on gas exports and low prices
offered by the only buyer, British Gas. West Sole came onstream in May 1967. Licensing regulations for Dutch waters were not finalised until 1967.
The situation was transformed in December 1969, when Phillips Petroleum discovered oil in Chalk of Danian age at Ekofisk, in Norwegian waters in the central North Sea. The same month, Amoco discovered the Montrose Field about 217 km (135 mi) east of Aberdeen.
The original objective of the well had been to drill for gas to test
the idea that the southern North Sea gas province extended to the north.
Amoco were astonished when the well discovered oil.
BP had been awarded several licences in the area in the second
licensing round late in 1965, but had been reluctant to work on them.
The discovery of Ekofisk prompted them to drill what turned out to be a
dry hole in May 1970, followed by the discovery of the giant Forties Oil Field in October 1970. The following year, Shell Expro discovered the giant Brent oilfield in the northern North Sea east of Shetland in Scotland and the Petronord Group discovered the Frigg gas field. The Piper oilfield was discovered in 1973 and the Statfjord Field and the Ninian Field in 1974, with the Ninian reservoir consisting of Middle Jurassic sandstones at a depth of 3000 m subsea in a "westward tilted horst block".
Offshore production, like that of the North Sea, became more economical after the 1973 oil crisis caused the world oil price to quadruple, followed by the 1979 oil crisis,
which caused another tripling in the oil price. Oil production started
from the Argyll & Duncan Oilfields (now the Ardmore) in June 1975 followed by Forties Oil Field in November of that year. The inner Moray Firth Beatrice Field, a Jurassicsandstone/shale reservoir 1829 m deep in a "fault-boundedanticlinal
trap", was discovered in 1976 with well 11/30-1, drilled by the Mesa
Petroleum Group (named after T. Boone Pickens' wife Bea, "the only oil
field in the North Sea named for a woman") in 49 m of water.
A 'Statfjord' gravity-based structure under construction in Norway. Almost all of the structure was submerged.
Volatile weather conditions in Europe's North Sea have made drilling particularly hazardous, claiming many lives (see Oil platform).
The conditions also make extraction a costly process; by the 1980s,
costs for developing new methods and technologies to make the process
both efficient and safe far exceeded NASA's budget to land a man on the moon.
The exploration of the North Sea has continually pushed the edges of
the technology of exploitation (in terms of what can be produced) and
later the technologies of discovery and evaluation (2-D seismic,
followed by 3-D and 4-D seismic; sub-salt seismic; immersive display and analysis suites and supercomputing to handle the flood of computation required).
The Gullfaks oil field was discovered in 1978. The Snorre Field was discovered in 1979, producing from the Triassic Lunde Formation and the Triassic-Jurassic Statfjord Formation, both fluvialsandstones in a mudstone matrix. The Oseberg oil field and Troll gas field were also discovered in 1979. The Miller oilfield was discovered in 1983. The Alba Field produces from sandstones in the middle Eocene Alba Formation at 1860 m subsea and was discovered in 1984 in UKCS Block 16/26. The Smørbukk Field was discovered in 1984 in 250–300 m of water that produces from Lower to Middle Jurassic sandstone formations within a fault block. The Snøhvit Gas Field and the Draugen oil field were discovered in 1984. The Heidrun oil field was discovered in 1985.
The largest UK field discovered in the past twenty-five years is Buzzard, also located off Scotland, found in June 2001 with producible reserves of almost 64×106 m³ (400m bbl) and an average output of 28,600 m3 to 30,200 m3 (180,000–220,000 bbl) per day.
The largest field found in the past five years on the Norwegian part of the North Sea is the Johan Sverdrup oil field, which was discovered in 2010. It is one of the largest discoveries made in the Norwegian Continental Shelf.
Total reserves of the field are estimated at 1.7 to 3.3 billion barrels
of gross recoverable oil, and Johan Sverdrup is expected to produce
120,000 to 200,000 barrels of oil per day. Production started on 5
October 2019.
As of January 2015, the North Sea was the world's most active offshore drilling region, with 173 active rigs drilling. By May 2016, the North Sea oil and gas industry was financially stressed by the reduced oil prices, and called for government support.
The distances, number of workplaces, and fierce weather in the
750,000 square kilometre (290,000 square mile) North Sea area require
the world's largest fleet of heavy instrument flight rules
(IFR) helicopters, some specifically developed for the North Sea. They
carry about two million passengers per year from sixteen onshore bases,
of which Aberdeen Airport is the world's busiest, with 500,000 passengers per year.
Following the 1958 Convention on the Continental Shelf and after some disputes on the rights to natural resource exploitation the national limits of the exclusive economic zones were ratified.
Five countries are involved in oil production in the North Sea. All operate a tax and royalty licensing regime. The respective sectors are divided by median lines agreed in the late 1960s:
Norway – Oljedirektoratet (the Norwegian Petroleum Directorate
grants licences. The NCS is also divided into quads of 1 degree by 1
degree. Norwegian licence blocks are larger than British blocks, being
15 minutes of latitude by 20 minutes of longitude (12 blocks in a quad).
Like in Britain, there are numerous part blocks formed by re-licensing
relinquished areas.
United Kingdom – Exploration and production licences are regulated by the Oil and Gas Authority following the 2014 Wood Review on maximising UKCS (United Kingdom Continental Shelf) oil and gas recovery. Licences were formerly granted by the Department of Energy and Climate Change (DECC – formerly the Department of Trade and Industry).
The UKCS is divided into quadrants of 1 degree latitude and one degree
longitude. Each quadrant is divided into 30 blocks measuring 10 minutes
of latitude and 12 minutes of longitude. Some blocks are divided further
into part blocks where some areas are relinquished by previous
licensees. For example, block 13/24a is located in quad 13 and is the
24th block and is the 'a' part block. The UK government has
traditionally issued licences via periodic (now annual) licensing
rounds. Blocks are awarded on the basis of the work programme bid by the
participants. The UK government has actively solicited new entrants to
the UKCS via "promote" licensing rounds with less demanding terms and
the fallow acreage initiative, where non-active licences have to be
relinquished.
Denmark – Energistyrelsen (the Danish Energy Agency)
administers the Danish sector. The Danes also divide their sector of
the North Sea into 1 degree by 1 degree quadrants. Their blocks,
however, are 10 minutes latitude by 15 minutes longitude. Part blocks
exist where partial relinquishment has taken place.
Germany
– Germany and the Netherlands share a quadrant and block grid—quadrants
are given letters rather than numbers. The blocks are 10 minutes
latitude by 20 minutes longitude.
Netherlands – The Dutch sector is located in the Southern Gas Basin and shares a grid pattern with Germany.
Reserves and production
The
Norwegian and British sectors hold most of the large oil reserves. It
is estimated that the Norwegian sector alone contains 54% of the sea's
oil reserves and 45% of its gas reserves.
More than half of the North Sea oil reserves have been extracted,
according to official sources in both Norway and the UK. For Norway,
Oljedirektoratet
gives a figure of 4,601 million cubic metres of oil (corresponding to
29 billion barrels) for the Norwegian North Sea alone (excluding smaller
reserves in Norwegian Sea and Barents Sea) of which 2,778 million cubic
metres (60%) has already been produced prior to January 2007. UK
sources give a range of estimates of reserves, but even using the most
optimistic "maximum" estimate of ultimate recovery, 76% had been
recovered as of the end of 2010. Note the UK figure includes fields which are not in the North Sea (onshore, West of Shetland).
United Kingdom Continental Shelf production was 137 million tonnes of oil and 105 billion m³ of gas in 1999. (1 tonne of crude oil converts to 7.5 barrels).
The Danish explorations of Cenozoic stratigraphy, undertaken in the
1990s, showed petroleum-rich reserves in the northern Danish sector,
especially the Central Graben area. The Dutch area of the North Sea followed through with onshore and offshore gas exploration, and well creation.
Exact figures are debatable, because methods of estimating reserves vary
and it is often difficult to forecast future discoveries.
Peaking and decline
Official production data from 1995 to 2020 is published by the UK government. Table 3.10 lists annual production, import and exports over that period.
When it peaked in 1999, production of North Sea oil was 128 million tonnes per year, approx, 950,000 m³ (6 million barrels)
per day, having risen by ~ 5% from the early 1990s.
However, by 2010 this had halved to under 60 million tonnes/year, and
continued declining further, and between 2015 and 2020 has hovered
between 40 and 50 million tonnes/year, at around 35% of the 1999 peak.
From 2005 the UK became a net importer of crude oil, and as production
declined, the amount imported has slowly risen to ~ 20 million tonnes
per year by 2020.
Similar historical data is available for gas. Natural gas production peaked at nearly 10 trillion cubic feet (280×109 m³) in 2001 representing some 1.2GWhr of energy; by 2018 UK production had declined to 1.4 trillion cubic feet, (41×109 m³).
Over a similar period energy from gas imports have risen by a factor of
approximately 10, from 60GWh in 2001 to just over 500GWh in 2019.
UK oil production has seen two peaks, in the mid-1980s and the late 1990s, with a decline to around 300×103 m³ (1.9 million barrels) per day in the early 1990s. Monthly oil production peaked at 13.5×106 m³ (84.9 million barrels) in January 1985 although the highest annual production was seen in 1999, with offshore oil production in that year of 407×106 m³ (398 million barrels) and had declined to 231×106 m³ (220 million barrels) in 2007.
This was the largest decrease of any oil-exporting nation in the world,
and has led to Britain becoming a net importer of crude for the first
time in decades, as recognized by the energy policy of the United Kingdom. Norwegian crude oil production as of 2013 is 1.4 mbpd. This is a more than 50% decline since the peak in 2001 of 3.2 mbpd.
Geology
The geological disposition of the UK's oil and gas fields is outlined in the following table.
North Sea oil and gas fields – Geology
Geological Era
Geological Epoch
Age, million years
Fields
Tertiary
Pliocene
2–5
Miocene
5–23
Oligocene
23–34
Eocene
34–56
Frigg, Gannet, Alba
Palaeocene
56–66
Arbroath, Balmoral, Everest, Forties, Heimdal, Maureen, Montrose, Nelson
Dotty, Douglas, Esmond, Hamilton, J-Block, Morecambe Bay
Lower: Hewett
Palaeozoic
Permian
252–299
Upper Permian (Zechstein): Argyll, Auk
Lower Permian (Rotliegend): Camelot, Indefatigable, Leman, Viking, West Sole
Carboniferous
299–359
Caister, Murdoch
Devonian
359–419
Buchan
Silurian
419–444
Ordovician
444–485
Cambrian
485–541
Carbon dioxide sequestration
In the North Sea, Norway's Equinor natural-gas platform Sleipner
strips carbon dioxide out of the natural gas with amine solvents and
disposes of this carbon dioxide by geological sequestration ("carbon sequestration")
while keeping up gas production pressure. Sleipner reduces emissions of
carbon dioxide by approximately one million tonnes a year; that is
about 1⁄9000th of global emissions. The cost of geological sequestration is minor relative to the overall running costs.
A structure map, looking downward, generated by contour map software for an 8,500-ft-deep gas and oil reservoir in the Erath Field, Erath, Louisiana. The left-to-right gap near the top indicates a fault line
between the blue and green contour lines and the purple, red, and
yellow lines. The thin red circular line in the middle indicates the top
of the oil reservoir. Because gas rises above oil, this latter line
marks the gas-and-oil contact zone.
A petroleum reservoir or oil and gas reservoir is a subsurface accumulation of hydrocarbons contained in porous or fractured rock formations. Such reservoirs form when kerogen (ancient plant matter) is created in surrounding rock by the presence of high heat and pressure in the Earth's crust.
Reservoirs are broadly classified as conventional and unconventional reservoirs. In conventional reservoirs, the naturally occurring hydrocarbons, such as crude oil (petroleum) or natural gas, are trapped by overlying rock formations with lower permeability,
while in unconventional reservoirs the rocks have high porosity and low
permeability, which keeps the hydrocarbons trapped in place, therefore
not requiring a cap rock. Reservoirs are found using hydrocarbon exploration methods.
An oil field is an area of accumulated liquid petroleum
underground in multiple (potentially linked) reservoirs, trapped as it
rises to impermeable rock formations. In industrial terms, an oil field
implies that there is an economic benefit worthy of commercial
attention.
Oil fields may extend up to several hundred kilometers across the
surface, meaning that extraction efforts can be large and spread out
across the area. In addition to extraction equipment, there may be
exploratory wells probing the edges to find more reservoir area, pipelines to transport the oil elsewhere, and support facilities.
Oil fields can occur anywhere that the geology of the underlying
rock allows, meaning that certain fields can be far away from
civilization, including at sea. Creating an operation at an oil field
can be a logistically complex undertaking, as it involves the equipment
associated with extraction
and transportation, as well as infrastructure such as roads and housing
for workers. This infrastructure has to be designed with the lifespan
of the oil field in mind, as production can last many years. Several
companies, such as Hill International, Bechtel, Esso, Weatherford International, Schlumberger, Baker Hughes and Halliburton, have organizations that specialize in the large-scale construction of the infrastructure to support oil field exploitation.
The term "oilfield" can be used as a shorthand to refer to the entire petroleum industry. However, it is more accurate to divide the oil industry into three sectors: upstream (crude oil production from wells and separation of water from oil), midstream (pipeline and tanker transport of crude oil) and downstream (refining of crude oil to products, marketing of refined products, and transportation to oil stations).
More than 65,000 oil fields are scattered around the globe, on land and offshore. The largest are the Ghawar Field in Saudi Arabia and the Burgan Field in Kuwait, with more than 66 to 104 billion barrels(9.5×109 m3) estimated in each. In the modern age, the location of oil fields with proven oil reserves is a key underlying factor in many geopolitical conflicts.
Gas field
Location of the gas fields of IranVučkovec Gas Field facility, CroatiaThe drillship Discoverer Enterprise is shown in the background, at work during exploratory phase of a new offshore field. The Offshore Support Vessel Toisa Perseus is shown in the foreground, illustrating part of the complex logistics of offshore oil and gas exploration and production.
Natural gas originates by the same geological thermal cracking process that converts kerogen
to petroleum. As a consequence, oil and natural gas are often found
together. In common usage, deposits rich in oil are known as oil fields,
and deposits rich in natural gas are called natural gas fields.
In general, organic sediments buried in depths of 1,000 m to 6,000 m (at temperatures of 60 °C
to 150 °C) generate oil, while sediments buried deeper and at higher
temperatures generate natural gas. The deeper the source, the "drier"
the gas (that is, the smaller the proportion of condensates in the gas). Because both oil and natural gas are lighter than water, they tend to rise from their sources until they either seep to the surface or are trapped by a non-permeable stratigraphic trap. They can be extracted from the trap by drilling.
Like oil, natural gas is often found underwater in offshore gas fields such as the North Sea, Corrib Gas Field off Ireland, and near Sable Island. The technology to extract and transport offshore natural gas is different from land-based fields. It uses a few, very large offshore drilling rigs, due to the cost and logistical difficulties in working over water.
Rising gas prices in the early 21st century encouraged drillers
to revisit fields that previously were not considered economically
viable. For example, in 2008 McMoran Exploration
passed a drilling depth of over 32,000 feet (9754 m) (the deepest test
well in the history of gas production) at the Blackbeard site in the
Gulf of Mexico. ExxonMobil's drill rig there had reached 30,000 feet by 2006, without finding gas, before it abandoned the site.
Formation
Crude oil is found in all oil reservoirs formed in the Earth's crust
from the remains of once-living things. Evidence indicates that
millions of years of heat and pressure changed the remains of
microscopic plants and animals into oil and natural gas.
Roy Nurmi, an interpretation adviser for Schlumberger oil field services company, described the process as follows:
Plankton and algae, proteins and the life that's floating
in the sea, as it dies, falls to the bottom, and these organisms are
going to be the source of our oil and gas. When they're buried with the
accumulating sediment and reach an adequate temperature, something above
50 to 70 °C they start to cook. This transformation, this change,
changes them into the liquid hydrocarbons that move and migrate, will
become our oil and gas reservoir.
In addition to the aquatic ecosystem, which is usually a sea but might also be a river, lake, coral reef, or algal mat, the formation of an oil or gas reservoir also requires a sedimentary basin that passes through four steps:
Deep burial under sand and mud
Pressure cooking
Hydrocarbon migration from the source to the reservoir rock
Trapping by impermeable rock
Timing is also an important consideration; it is suggested that the Ohio River Valley could have had as much oil as the Middle East at one time, but that it escaped due to a lack of traps. The North Sea,
on the other hand, endured millions of years of sea level changes that
successfully resulted in the formation of more than 150 oil fields.
Although the process is generally the same, various environmental
factors lead to the creation of a wide variety of reservoirs.
Reservoirs exist anywhere from the land surface to 30,000 ft (9,000 m)
below the surface and are a variety of shapes, sizes, and ages. In recent years, igneous reservoirs have become an important new field of oil exploration, especially in trachyte and basalt formations. These two types of reservoirs differ in oil content and physical properties like fracture connectivity, pore connectivity, and rock porosity.
Geology
Traps
A trap forms when the buoyancy forces driving the upward migration of hydrocarbons through a permeable rock cannot overcome the capillary forces
of a sealing medium. The timing of trap formation relative to that of
petroleum generation and migration is crucial to ensuring a reservoir
can form.
Petroleum geologists
broadly classify traps into three categories that are based on their
geological characteristics: the structural trap, the stratigraphic trap,
and the far less common hydrodynamic trap.
The trapping mechanisms for many petroleum reservoirs have
characteristics from several categories and can be known as a
combination trap. Traps are described as structural traps (in deformed
strata such as folds and faults) or stratigraphic traps (in areas where
rock types change, such as unconformities, pinch-outs and reefs).
Structural traps
Structural traps are formed as a result of changes in the structure of the subsurface from processes such as folding and faulting, leading to the formation of domes, anticlines, and folds. Examples of this kind of trap are an anticline trap, a fault trap, and a salt dome
trap. They are more easily delineated and more prospective than their
stratigraphic counterparts, with the majority of the world's petroleum
reserves being found in structural traps.
Stratigraphic traps are formed as a result of lateral and vertical variations in the thickness, texture, porosity, or lithology of the reservoir rock. Examples of this type of trap are an unconformity trap, a lens trap and a reef trap.
Stratigraphic trap in a fossilized coral reef (yellow) sealed by mudstones (green)
Stratigraphic trap around an evaporite (pink) salt dome
Hydrodynamic traps
Hydrodynamic traps are a far less common type of trap.
They are caused by the differences in water pressure, that are
associated with water flow, creating a tilt of the hydrocarbon-water
contact.
Seal / cap rock
The
seal (also referred to as a cap rock) is a fundamental part of the trap
that prevents hydrocarbons from further upward migration. A capillary
seal is formed when the capillary pressure
across the pore throats is greater than or equal to the buoyancy
pressure of the migrating hydrocarbons. They do not allow fluids to
migrate across them until their integrity is disrupted, causing them to
leak. There are two types of capillary seal whose classifications are based on the preferential mechanism of leaking: the hydraulic seal and the membrane seal.
A membrane seal will leak whenever the pressure differential
across the seal exceeds the threshold displacement pressure, allowing
fluids to migrate through the pore spaces in the seal. It will leak just
enough to bring the pressure differential below that of the
displacement pressure and will reseal.
A hydraulic seal occurs in rocks that have a significantly higher
displacement pressure such that the pressure required for tension
fracturing is actually lower than the pressure required for fluid
displacement—for example, in evaporites
or very tight shales. The rock will fracture when the pore pressure is
greater than both its minimum stress and its tensile strength then
reseal when the pressure reduces and the fractures close.
Schematic
unconventional reservoir classification expressed as fluid energy vs
flow potential based on initials without stimulation
Unconventional (oil & gas) reservoirs are accumulations where oil and gas phases are tightly bound to the rock fabric by strong capillary forces, requiring specialised measures for evaluation and extraction.
Unconventional reservoirs form in completely different ways to
conventional reservoirs, the main difference being that they do not have
"traps". This type of reservoir can be driven in a unique way as well,
as buoyancy might not be the driving force for oil and gas accumulation
in such reservoirs. This is analogous to saying that the oil which can
be extracted forms within the source rock itself, as opposed to accumulating under a cap rock. Oil sands are an example of an unconventional oil reservoir.
Unconventional reservoirs and their associated unconventional oil
encompass a broad spectrum of petroleum extraction and refinement
techniques, as well as many different sources. Since the oil is contained within the source rock, unconventional reservoirs require that the extracting entity function as a mining operation rather than drilling and pumping
like a conventional reservoir. This has tradeoffs, with higher
post-production costs associated with complete and clean extraction of
oil being a factor of consideration for a company interested in pursuing
a reservoir. Tailings
are also left behind, increasing cleanup costs. Despite these
tradeoffs, unconventional oil is being pursued at a higher rate because
of the scarcity of conventional reservoirs around the world.
After the discovery of a reservoir, a petroleum engineer will seek to
build a better picture of the accumulation. In a simple textbook
example of a uniform reservoir, the first stage is to conduct a seismic
survey to determine the possible size of the trap. Appraisal wells can
be used to determine the location of oil-water contact and with it the
height of the oil bearing sands. Often coupled with seismic data, it is
possible to estimate the volume of an oil-bearing reservoir.
The next step is to use information from appraisal wells to
estimate the porosity of the rock. The porosity of an oil field, or the
percentage of the total volume that contains fluids rather than solid
rock, is 20–35% or less. It can give information on the actual capacity.
Laboratory testing can determine the characteristics of the reservoir
fluids, particularly the expansion factor of the oil, or how much the
oil expands when brought from the high pressure and high temperature of
the reservoir to a "stock tank" at the surface.
With such information, it is possible to estimate how many "stock tank" barrels of oil are located in the reservoir. Such oil is called the stock tank oil initially in place.
As a result of studying factors such as the permeability of the rock
(how easily fluids can flow through the rock) and possible drive
mechanisms, it is possible to estimate the recovery factor, or what
proportion of oil in place can be reasonably expected to be produced.
The recovery factor is commonly 30–35%, giving a value for the
recoverable resources.
The difficulty is that reservoirs are not uniform. They have
variable porosities and permeabilities and may be compartmentalized,
with fractures and faults breaking them up and complicating fluid flow.
For this reason, computer modeling of economically viable reservoirs is often carried out. Geologists, geophysicists, and reservoir engineers work together to build a model that allows simulation of the flow of fluids in the reservoir, leading to an improved estimate of the recoverable resources.
Reserves are only the part of those recoverable resources that
will be developed through identified and approved development projects.
Because the evaluation of reserves has a direct impact on the company or
the asset value, it usually follows a strict set of rules or
guidelines.
Production
To
obtain the contents of the oil reservoir, it is usually necessary to
drill into the Earth's crust, although surface oil seeps exist in some
parts of the world, such as the La Brea Tar Pits in California and numerous seeps in Trinidad.
Factors that affect the quantity of recoverable hydrocarbons in a
reservoir include the fluid distribution in the reservoir, initial
volumes of fluids in place, reservoir pressure, fluid and rock
properties, reservoir geometry, well type, well count, well placement,
development concept, and operating philosophy.
A
virgin reservoir may be under sufficient pressure to push hydrocarbons
to the surface. As the fluids are produced, the pressure will often
decline, and production will falter. The reservoir may respond to the
withdrawal of fluid in a way that tends to maintain the pressure.
Artificial drive methods may be necessary.
Solution-gas drive
This
mechanism (also known as depletion drive) depends on the associated gas
of the oil. The virgin reservoir may be entirely semi-liquid but will
be expected to have gaseous hydrocarbons in solution due to the
pressure. As the reservoir depletes, the pressure falls below the bubble point,
and the gas comes out of solution to form a gas cap at the top. This
gas cap pushes down on the liquid helping to maintain pressure.
This occurs when the natural gas is in a cap below the oil. When
the well is drilled the lowered pressure above means that the oil
expands. As the pressure is reduced it reaches bubble point, and
subsequently the gas bubbles drive the oil to the surface. The bubbles
then reach critical saturation and flow together as a single gas phase.
Beyond this point and below this pressure, the gas phase flows out more
rapidly than the oil because of its lowered viscosity. More free gas is
produced, and eventually the energy source is depleted. In some cases
depending on the geology the gas may migrate to the top of the oil and
form a secondary gas cap. Some energy may be supplied by water, gas in
water, or compressed rock. These are usually minor contributions with
respect to hydrocarbon expansion.
By properly managing the production rates, greater benefits can
be had from solution-gas drives. Secondary recovery involves the
injection of gas or water to maintain reservoir pressure. The gas/oil
ratio and the oil production rate are stable until the reservoir
pressure drops below the bubble point when critical gas saturation is
reached. When the gas is exhausted, the gas/oil ratio and the oil rate
drops, the reservoir pressure has been reduced, and the reservoir energy
is exhausted.
Gas cap drive
In
reservoirs already having a gas cap (the virgin pressure is already
below bubble point), the gas cap expands with the depletion of the
reservoir, pushing down on the liquid sections applying extra pressure.
This is present in the reservoir if there is more gas than can be
dissolved in the reservoir. The gas will often migrate to the crest of
the structure. It is compressed on top of the oil reserve, as the oil is
produced the cap helps to push the oil out. Over time the gas cap moves
down and infiltrates the oil, and the well will produce more and more
gas until it produces only gas.
It is best to manage the gas cap effectively, that is, placing
the oil wells such that the gas cap will not reach them until the
maximum amount of oil is produced. Also a high production rate may cause
the gas to migrate downward into the production interval. In this case,
over time the reservoir pressure depletion is not as steep as in the
case of solution-based gas drive. In this case, the oil rate will not
decline as steeply but will depend also on the placement of the well
with respect to the gas cap. As with other drive mechanisms, water or
gas injection can be used to maintain reservoir pressure. When a gas cap
is coupled with water influx, the recovery mechanism can be highly
efficient.
Aquifer (water) drive
Water
(usually salty) may be present below the hydrocarbons. Water, as with
all liquids, is compressible to a small degree. As the hydrocarbons are
depleted, the reduction in pressure in the reservoir allows the water to
expand slightly. Although this unit expansion is minute, if the aquifer
is large enough this will translate into a large increase in volume,
which will push up on the hydrocarbons, maintaining pressure.
With a water-drive reservoir, the decline in reservoir pressure
is very slight; in some cases, the reservoir pressure may remain
unchanged. The gas/oil ratio also remains stable. The oil rate will
remain fairly stable until the water reaches the well. In time, the
water cut will increase, and the well will be watered out.
The water may be present in an aquifer (but rarely one replenished with surface water).
This water gradually replaces the volume of oil and gas that is
produced out of the well, given that the production rate is equivalent
to the aquifer activity. That is, the aquifer is being replenished from
some natural water influx. If the water begins to be produced along with
the oil, the recovery rate may become uneconomical owing to the higher
lifting and water disposal costs.
If the natural drives are insufficient, as they very often are, then
the pressure can be artificially maintained by injecting water into the
aquifer or gas into the gas cap.
Gravity drainage
The
force of gravity will cause the oil to move downward of the gas and
upward of the water. If vertical permeability exists then recovery rates
may be even better.
Gas and gas condensate reservoirs
These
occur if the reservoir conditions allow the hydrocarbons to exist as a
gas. Retrieval is a matter of gas expansion. Recovery from a closed
reservoir (i.e., no water drive) is very good, especially if bottom hole
pressure is reduced to a minimum (usually done with compressors at the
wellhead). Any produced liquids are light-colored to colorless, with a
gravity higher than 45 API. Gas cycling is the process where dry gas is
injected and produced along with condensed liquid.
Hydraulic fracturing began as an experiment in 1947,
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. Such treatment is generally necessary to achieve adequate flow rates in shale gas, tight gas, tight oil, and coal seam gas wells. Some hydraulic fractures can form naturally in certain veins or dikes. Drilling and hydraulic fracturing have made the United States a major crude oil exporter as of 2019, but leakage of methane, a potent greenhouse gas, has dramatically increased.
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.
Hydraulic fracturing is highly controversial. Its proponents highlight the economic benefits of more extensively accessible hydrocarbons (such as petroleum and natural gas), the benefits of replacing coal with natural gas, which burns more cleanly and emits less carbon dioxide (CO2), and the benefits of energy independence. Opponents of fracking argue that these are outweighed by the environmental impacts, which include groundwater and surface water contamination, noise and air pollution, the triggering of earthquakes, and the resulting hazards to public health and the environment.Research has found adverse health effects in populations living near hydraulic fracturing sites,
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. Adherence to regulation and safety procedures are required to avoid further negative impacts.
The scale of methane leakage
associated with hydraulic fracturing 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.
Diagram of Hydraulic Fracking Machinery and Process
Increases in seismic activity following hydraulic fracturing along dormant or previously unknown faults
are sometimes caused by the deep-injection disposal of hydraulic
fracturing flowback (a byproduct of hydraulically fractured wells), and produced formation brine (a byproduct of both fractured and non-fractured oil and gas wells).
For these reasons, hydraulic fracturing is under international
scrutiny, restricted in some countries, and banned altogether in others. The European Union is drafting regulations that would permit the controlled application of hydraulic fracturing.
Fracturing 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.
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. In natural examples, such as dikes or vein-filled fractures, the orientations can be used to infer past states of stress.
Veins
Most 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.
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".
Dikes
Minor intrusions in the upper part of the crust, such as dikes, propagate in the form of fluid-filled cracks. In such cases, the fluid is magma. In sedimentary rocks with a significant water content, fluid at fracture tip will be steam.
Fracturing
as a method to stimulate shallow, hard rock oil wells dates back to the
1860s. 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". It was employed in Pennsylvania, New York, Kentucky, and West Virginia using liquid and also, later, solidified nitroglycerin.
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.
The 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. 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 fracturing
treatments in Stephens County, Oklahoma, and Archer County, Texas. Since then, hydraulic fracturing has been used to stimulate approximately one million oil and gas wells 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.
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.
Massive fracturing
Well head where fluids are injected into the groundWell head after all the hydraulic fracturing equipment has been taken off location
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.
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. 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
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).
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.
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; sedimentary beds are usually nearly horizontal, so horizontal wells have much larger contact areas with the target formation.
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.
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.
In 1976, the United States government started the Eastern Gas Shales Project, which included numerous public-private hydraulic fracturing 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, 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.
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, including the Eagle Ford and Bakken Shale. 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.
According 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.
Method
A 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.
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.
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.
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.
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), fracking hose (low-pressure flexible hoses), and many gauges and meters for flow rate, fluid density, and treating pressure.
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).
Well types
A
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.
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.
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.
Water-soluble gelling agents (such as guar gum) increase viscosity and efficiently deliver proppant into the formation.
Example of high pressure manifold combining pump flows before injection into well
Fluid is typically a slurry of water, proppant, and chemical additives. 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%. However, fracturing fluids have been developed using liquefied petroleum gas (LPG) and propane. This process is called waterless fracturing.
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
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.
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.
USGS map of water use from hydraulic fracturing between 2011 and 2014. One cubic meter of water is 264.172 gallons.
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.
A typical fracture treatment uses between 3 and 12 additive chemicals. Although there may be unconventional fracturing fluids, typical 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.
Polyacrylamide
and other friction reducers decrease turbulence in fluid flow and pipe
friction, thus allowing the pumps to pump at a higher rate without
having greater pressure on the surface.
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 proppant. 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 guar-based gels. The crosslinking
mechanism is not reversible, so once the proppant is pumped down along
with 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 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. 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.
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.
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.
Fracture monitoring
Measurements
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.
Injection of radioactive tracers along with the fracturing fluid is sometimes used to determine the injection profile and location of created fractures. Radiotracers
are selected 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.
A new technique in well-monitoring involves fiber-optic cables
outside the casing. Using the fiber optics, temperatures can be measured
every foot along the well – even while the wells are being fracked and
pumped. By monitoring the temperature of the well, engineers can
determine how much hydraulic fracturing fluid different parts of the
well use as well as how much natural gas or oil they collect, during
hydraulic fracturing operation and when the well is producing.
Microseismic monitoring
For more advanced applications, microseismic
monitoring is sometimes used to estimate the size and orientation of
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 fracture, the approximate geometry of
the fracture is inferred. Tiltmeter arrays deployed on the surface or down a well provide another technology for monitoring strain.
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 motion
along the fault plane to be estimated and its location in the Earth's
subsurface mapped. Hydraulic fracturing, an increase in formation stress
proportional to the net fracturing pressure, as well as an increase in
pore pressure due to leakoff. Tensile stresses are generated ahead of the fracture's tip, generating large amounts of shear stress. The increases in pore water pressure
and in formation stress combine and affect weaknesses near the
hydraulic fracture, like natural fractures, joints, and bedding planes.
Different methods have different location errors
and advantages. Accuracy of microseismic event mapping is dependent on
the signal-to-noise ratio and the distribution of sensors. 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. Geomechanical
analysis, such as understanding a formations material properties,
in-situ conditions, and geometries, helps monitoring by providing a
better definition of the environment in which the fracture network
propagates.
The next task is to know the location of proppant within the fracture
and the distribution of fracture conductivity. This can be monitored
using multiple types of techniques to finally develop a reservoir model
than accurately predicts well performance.
Horizontal completions
Since the early 2000s, advances in drilling and completion technology have made horizontal wellbores much
more economical. Horizontal wellbores allow far greater exposure to a
formation than conventional vertical wellbores. 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 is used to
determine how many times a formation is fractured, and at what locations
along the horizontal section.
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 horizontally through the producing intervals, completed and fractured.
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 steel casing, cemented or uncemented, set in the drilled hole.
Once the drilling rig has been removed, a wireline truck is used to perforate
near the bottom of the well, and then fracturing fluid is pumped. Then
the wireline truck sets a plug in the well to temporarily seal off that
section so the next section of the wellbore can be treated. Another
stage is pumped, and the process is repeated along the horizontal length
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 due to be
fractured, the bottom sliding sleeve is opened using one of several
activation techniques
and the first stage gets pumped. Once finished, the next sleeve is
opened, concurrently isolating the previous stage, and the process
repeats. For the sliding sleeve method, wireline is usually not
required.
Sleeves
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 that had
far fewer feet of producing zone exposed.
Uses
Hydraulic
fracturing is used to increase the rate at which substances such as
petroleum or natural gas can be recovered from subterranean natural
reservoirs. Reservoirs are typically porous sandstones, limestones or dolomite rocks, but also include "unconventional reservoirs" such as shale rock or coal
beds. Hydraulic fracturing enables the extraction of natural gas and
oil from rock formations deep below the earth's surface (generally
2,000–6,000 m (5,000–20,000 ft)), which is greatly below typical
groundwater reservoir levels. At such depth, there may be insufficient permeability
or reservoir pressure to allow natural gas and oil to flow from the
rock into the wellbore at high economic return. Thus, creating
conductive fractures in the rock is instrumental in extraction from
naturally impermeable shale reservoirs. Permeability is measured in the
microdarcy to nanodarcy range.
Fractures are a conductive path connecting a larger volume of reservoir
to the well. So-called "super fracking" creates cracks deeper in the
rock formation to release more oil and gas, and increases efficiency.
The yield for typical shale bores generally falls off after the first
year or two, but the peak producing life of a well can be extended to
several decades.
Non-oil/gas uses
While the main industrial use of hydraulic fracturing is in stimulating production from oil and gas wells, hydraulic fracturing is also applied:
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 United States, Australia, and South Africa.
Hydraulic fracturing has been seen as one of the key methods of extracting unconventional oil and unconventional gas resources. According to the International Energy Agency,
the remaining technically recoverable resources of shale gas are
estimated to amount to 208 trillion cubic metres (7,300 trillion cubic
feet), tight gas to 76 trillion cubic metres (2,700 trillion cubic
feet), and coalbed methane
to 47 trillion cubic metres (1,700 trillion cubic feet). 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.
A large majority of studies indicate that hydraulic fracturing in
the United States has had a strong positive economic benefit so far.
The Brookings Institution estimates that the benefits of Shale Gas
alone has led to a net economic benefit of $48 billion per year. Most of
this benefit is within the consumer and industrial sectors due to the
significantly reduced prices for natural gas. Other studies have suggested that the economic benefits are outweighed by the externalities and that the levelized cost of electricity (LCOE) from less carbon and water intensive sources is lower.
The primary benefit of hydraulic fracturing is to offset imports
of natural gas and oil, where the cost paid to producers otherwise exits
the domestic economy. However, shale oil and gas is highly subsidised in the US, and has not yet covered production costs
– meaning that the cost of hydraulic fracturing is paid for in income
taxes, and in many cases is up to double the cost paid at the pump.
Research suggests that hydraulic fracturing wells have an adverse
effect on agricultural productivity in the vicinity of the wells.
One paper found "that productivity of an irrigated crop decreases by
5.7% when a well is drilled during the agriculturally active months
within 11–20 km radius of a producing township. This effect becomes
smaller and weaker as the distance between township and wells
increases."
The findings imply that the introduction of hydraulic fracturing wells
to Alberta cost the province $14.8 million in 2014 due to the decline in
the crop productivity,
The Energy Information Administration of the US Department of
Energy estimates that 45% of US gas supply will come from shale gas by
2035 (with the vast majority of this replacing conventional gas, which
has a lower greenhouse-gas footprint).
An anti-fracking movement has emerged both internationally with involvement of international environmental organizations and nations such as France and locally in affected areas such as Balcombe in Sussex where the Balcombe drilling protest was in progress during mid-2013.
The considerable opposition against hydraulic fracturing activities in
local townships in the United States has led companies to adopt a
variety of public relations measures to reassure the public, including the employment of former military personnel with training in psychological warfare operations. According to Matt Pitzarella, the communications director at Range Resources,
employees trained in the Middle East have 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.
There have been many protests directed at hydraulic fracturing.
For example, ten people were arrested in 2013 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 someone shot two rounds of a small-caliber rifle in the
direction of a drilling rig. In Washington County, Pennsylvania, 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.
U.S. government and Corporate lobbying
The United States Department of State established the Global Shale Gas Initiative to persuade governments around the world to give concessions to the major oil and gas companies to set up fracking operations. A document from the United States diplomatic cables leak
show that, as part of this project, U.S. officials convened conferences
for foreign government officials that featured presentations by major
oil and gas company representatives and by public relations
professionals with expertise on how to assuage populations of target
countries whose citizens were often quite hostile to fracking on their
lands. The US government project succeeded as many countries on several
continents acceded to the idea of granting concessions for fracking; Poland, for example, agreed to permit fracking by the major oil and gas corporations on nearly a third of its territory. The US Export-Import Bank, an agency of the US government, provided $4.7 billion in financing for fracking operations set up since 2010 in Queensland, Australia.
Alleged Russian state advocacy
In
2014 a number of European officials suggested that several major
European protests against hydraulic fracturing (with mixed success in
Lithuania and Ukraine) may be partially sponsored by Gazprom, Russia's state-controlled gas company. The New York Times
suggested that Russia saw its natural gas exports to Europe as a key
element of its geopolitical influence, and that this market would
diminish if hydraulic fracturing is adopted in Eastern Europe, as it
opens up significant shale gas
reserves in the region. Russian officials have on numerous occasions
made public statements to the effect that hydraulic fracturing "poses a
huge environmental problem".
Current fracking operations
Hydraulic
fracturing is currently taking place in the United States in Arkansas,
California, Colorado, Louisiana, North Dakota, Oklahoma, Pennsylvania,
Texas, Virginia, West Virginia,
and Wyoming. Other states, such as Alabama, Indiana, Michigan,
Mississippi, New Jersey, New York, and Ohio, are either considering or
preparing for drilling using this method. Maryland
and Vermont have permanently banned hydraulic fracturing, and New York
and North Carolina have instituted temporary bans. New Jersey currently
has a bill before its legislature to extend a 2012 moratorium on
hydraulic fracturing that recently expired. Although a hydraulic
fracturing moratorium was recently lifted in the United Kingdom, the
government is proceeding cautiously because of concerns about
earthquakes and the environmental effect of drilling. Hydraulic
fracturing is currently banned in France and Bulgaria.
Documentary films
Josh Fox's 2010 Academy Award nominated film Gasland
became a center of opposition to hydraulic fracturing of shale. The
movie presented problems with groundwater 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. ExxonMobil, Chevron Corporation and ConocoPhillips
aired advertisements during 2011 and 2012 that claimed to describe the
economic and environmental benefits of natural gas and argue that
hydraulic fracturing was safe.
The 2012 film Promised Land, starring Matt Damon, takes on hydraulic fracturing. The gas industry countered the film's criticisms of hydraulic fracturing with flyers, and Twitter and Facebook posts.
In January 2013, Northern Irish journalist and filmmaker Phelim McAleer released a crowdfunded documentary called FrackNation as a response to the statements made by Fox in Gasland, claiming it "tells the truth about fracking for natural gas". FrackNation premiered on Mark Cuban's AXS TV. The premiere corresponded with the release of Promised Land.
In April 2013, Josh Fox released Gasland 2, his
"international odyssey uncovering a trail of secrets, lies and
contamination related to hydraulic fracking". It challenges the gas
industry's portrayal of natural gas as a clean and safe alternative to
oil as a myth, and that hydraulically fractured wells inevitably leak
over time, contaminating water and air, hurting families, and
endangering the Earth's climate with the potent greenhouse gas methane.
In 2014, Scott Cannon of Video Innovations released the documentary The Ethics of Fracking.
The film covers the politics, spiritual, scientific, medical and
professional points of view on hydraulic fracturing. It also digs into
the way the gas industry portrays hydraulic fracturing in their
advertising.
Typically
the funding source of the research studies is a focal point of
controversy. Concerns have been raised about research funded by
foundations and corporations, or by environmental groups, which can at
times lead to at least the appearance of unreliable studies.
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. Some have argued there is a need for more research into the environmental and health effects of the technique.
Health risks
Anti-fracking banner at the Clean Energy March (Philadelphia, 2016)
There is concern over the possible adverse public health implications of hydraulic fracturing activity.
A 2013 review on shale gas production in the United States stated,
"with increasing numbers of drilling sites, more people are at risk from
accidents and exposure to harmful substances used at fractured wells."
A 2011 hazard assessment recommended full disclosure of chemicals used
for hydraulic fracturing and drilling as many have immediate health
effects, and many may have long-term health effects.
In June 2014 Public Health England
published a review of the potential public health impacts of exposures
to chemical and radioactive pollutants as a result of shale gas
extraction in the UK, based on the examination of literature and data
from countries where hydraulic fracturing already occurs.
The executive summary of the report stated: "An assessment of the
currently available evidence indicates that the potential risks to
public health from exposure to the emissions associated with shale gas
extraction will be low if the operations are properly run and regulated.
Most evidence suggests that contamination of groundwater,
if it occurs, is most likely to be caused by leakage through the
vertical borehole. Contamination of groundwater from the underground
hydraulic fracturing process itself (i.e. the fracturing of the shale)
is unlikely. However, surface spills of hydraulic fracturing fluids or
wastewater may affect groundwater, and emissions to air also have the
potential to impact on health. Where potential risks have been
identified in the literature, the reported problems are typically a
result of operational failure and a poor regulatory environment."
A 2012 report prepared for the European Union Directorate-General
for the Environment identified potential risks to humans from air
pollution and ground water contamination posed by hydraulic fracturing. This led to a series of recommendations in 2014 to mitigate these concerns.
A 2012 guidance for pediatric nurses in the US said that hydraulic
fracturing had a potential negative impact on public health and that
pediatric nurses should be prepared to gather information on such topics
so as to advocate for improved community health.
A 2017 study in The American Economic Review
found that "additional well pads drilled within 1 kilometer of a
community water system intake increases shale gas-related contaminants
in drinking water."
A 2022 study conduced by Harvard T.H. Chan School of Public
Health and published in Nature Energy found that elderly people living
near or downwind of unconventional oil and gas
development (UOGD) -- which involves extraction methods including
fracking—are at greater risk of experiencing early death compared with
elderly persons who don't live near such operations.
Statistics collected by the U.S. Department of Labor and analyzed by the U.S. Centers for Disease Control and Prevention
show a correlation between drilling activity and the number of
occupational injuries related to drilling and motor vehicle accidents,
explosions, falls, and fires.
Extraction workers are also at risk for developing pulmonary diseases,
including lung cancer and silicosis (the latter because of exposure to
silica dust generated from rock drilling and the handling of sand). The U.S. National Institute for Occupational Safety and Health (NIOSH) identified exposure to airborne silica as a health hazard to workers conducting some hydraulic fracturing operations. NIOSH and OSHA issued a joint hazard alert on this topic in June 2012.
Additionally, the extraction workforce is at increased risk for
radiation exposure. Fracking activities often require drilling into rock
that contains naturally occurring radioactive material (NORM), such as
radon, thorium, and uranium.
Another report done by the Canadian Medical Journal reported that
after researching they identified 55 factors that may cause cancer,
including 20 that have been shown to increase the risk of leukemia and
lymphoma. The Yale Public Health analysis warns that millions of people
living within a mile of fracking wells may have been exposed to these
chemicals.
The potential environmental effects of hydraulic fracturing include
air emissions and climate change, high water consumption, groundwater
contamination, land use, risk of earthquakes, noise pollution, and various health effects on humans.
Air emissions are primarily methane that escapes from wells, along with
industrial emissions from equipment used in the extraction process. Modern UK and EU regulation requires zero emissions of methane, a potent greenhouse gas. Escape of methane is a bigger problem in older wells than in ones built under more recent EU legislation.
In December 2016 the United States Environmental Protection
Agency (EPA) issued the "Hydraulic Fracturing for Oil and Gas: Impacts
from the Hydraulic Fracturing Water Cycle on Drinking Water Resources in
the United States (Final Report)." The EPA found scientific evidence
that hydraulic fracturing activities can impact drinking water
resources. A few of the main reasons why drinking water can be contaminated according to the EPA are:
Water removal to be used for fracking in times or areas of low water availability
Spills while handling fracking fluids and chemicals that result in
large volumes or high concentrations of chemicals reaching groundwater
resources
Injection of fracking fluids into wells when mishandling machinery, allowing gases or liquids to move to groundwater resources
Injection of fracking fluids directly into groundwater resources
Leak of defective hydraulic fracturing wastewater to surface water
Disposal or storage of fracking wastewater in unlined pits resulting in contamination of groundwater resources.
The lifecycle greenhouse gas emissions of shale oil are 21%-47% higher than those of conventional oil, while emissions from unconventional gas are from 6% lower to 43% higher than the emissions of conventional gas.
Hydraulic fracturing uses between 1.2 and 3.5 million US gallons (4,500 and 13,200 m3) of water per well, with large projects using up to 5 million US gallons (19,000 m3). 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. 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. Surface water may be contaminated through spillage and improperly built and maintained waste pits, and ground water can be contaminated if the fluid is able to escape the formation being fractured (through, for example, abandoned wells, fractures, and faults) or by produced water (the returning fluids, which also contain dissolved constituents such as minerals and brine waters). The possibility of groundwater contamination from brine and fracturing fluid leakage through old abandoned wells is low. Produced water is managed by underground injection, municipal and commercialwastewater treatment and discharge, self-contained systems at well sites or fields, and recycling to fracture future wells.Typically less than half of the produced water used to fracture the formation is recovered.
In the United States over 12 million acres are being used for
fossil fuels. About 3.6 hectares (8.9 acres) of land is needed per each drill pad for surface installations. This is equivalent of six Yellowstone National Parks.
Well pad and supporting structure construction significantly fragments
landscapes which likely has negative effects on wildlife. These sites need to be remediated after wells are exhausted. Research indicates that effects on ecosystem services costs (i.e., those processes that the natural world provides to humanity) has reached over $250 million per year in the U.S.
Each well pad (in average 10 wells per pad) needs during preparatory
and hydraulic fracturing process about 800 to 2,500 days of noisy
activity, which affect both residents and local wildlife. In addition,
noise is created by continuous truck traffic (sand, etc.) needed in
hydraulic fracturing. Research is underway to determine if human health has been affected by air and water pollution,
and rigorous following of safety procedures and regulation is required
to avoid harm and to manage the risk of accidents that could cause harm.
In July 2013, the US Federal Railroad Administration listed oil
contamination by hydraulic fracturing chemicals as "a possible cause" of
corrosion in oil tank cars.
Hydraulic fracturing has been sometimes linked to induced seismicity or earthquakes.
The magnitude of these events is usually too small to be detected at
the surface, although tremors attributed to fluid injection into
disposal wells have been large enough to have often been felt by people,
and to have caused property damage and possibly injuries.
A U.S. Geological Survey reported that up to 7.9 million people in
several states have a similar earthquake risk to that of California,
with hydraulic fracturing and similar practices being a prime
contributing factor.
Microseismic events are often used to map the horizontal and vertical extent of the fracturing.
A better understanding of the geology of the area being fracked and
used for injection wells can be helpful in mitigating the potential for
significant seismic events.
People obtain drinking water from either surface water, which
includes rivers and reservoirs, or groundwater aquifers, accessed by
public or private wells. There are already a host of documented
instances in which nearby groundwater has been contaminated by fracking
activities, requiring residents with private wells to obtain outside
sources of water for drinking and everyday use.
Per- and polyfluoroalkyl substances
also known as "PFAS" or "forever chemicals" have been linked to cancer
and birth defects. The chemicals used in fracking stay in the
environment. Once there those chemicals will eventually break down into
PFAS. These chemicals can escape from drilling sites and into the
groundwater. PFAS are able to leak into underground wells that store
million gallons of wastewater.
Despite these health concerns and efforts to institute a
moratorium on fracking until its environmental and health effects are
better understood, the United States continues to rely heavily on fossil
fuel energy. In 2017, 37% of annual U.S. energy consumption is derived
from petroleum, 29% from natural gas, 14% from coal, and 9% from nuclear
sources, with only 11% supplied by renewable energy, such as wind and
solar power.
In 2022 the USA experienced a fracking boom, when the war in
Ukraine led to a massive increase in approval of new drillings. Planned
drillings will release 140 billion tons of carbon, 4 times more that the
annual global emissions.
Countries using or considering use of hydraulic fracturing have
implemented different regulations, including developing federal and
regional legislation, and local zoning limitations. In 2011, after public pressure France became the first nation to ban hydraulic fracturing, based on the precautionary principle as well as the principle of preventive and corrective action of environmental hazards. The ban was upheld by an October 2013 ruling of the Constitutional Council.
Some other countries such as Scotland have placed a temporary
moratorium on the practice due to public health concerns and strong
public opposition. Countries like England and South Africa have lifted their bans, choosing to focus on regulation instead of outright prohibition.
Germany has announced draft regulations that would allow using
hydraulic fracturing for the exploitation of shale gas deposits with the
exception of wetland areas.
In China, regulation on shale gas still faces hurdles, as it has
complex interrelations with other regulatory regimes, especially trade. Many states in Australia have either permanently or temporarily banned fracturing for hydrocarbons. In 2019, hydraulic fracturing was banned in UK.
The European Union has adopted a recommendation for minimum principles for using high-volume hydraulic fracturing. Its regulatory regime requires full disclosure of all additives.
In the United States, 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. Hydraulic fracturing is excluded from the Safe Drinking Water Act's underground injection control's regulation, except when diesel fuel is used. The EPA assures surveillance of the issuance of drilling permits when diesel fuel is employed.
In 2012, Vermont became the first state in the United States to
ban hydraulic fracturing. On 17 December 2014, New York became the
second state to issue a complete ban on any hydraulic fracturing due to
potential risks to human health and the environment.
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