Oil reserves

Oil reserves are the estimated quantities of crude oil that are claimed to be recoverable
under existing economic and operating conditions.[1]

The total amount of oil in an oil reservoir is known as oil in place. However, because of
reservoir characteristics and limitations in petroleum extraction technologies only a
fraction of this oil can be brought to the surface, and it is only this producible fraction
that is considered to be reserves. The ratio of reserves to oil in place for a given field is
often referred to as the recovery factor. The recovery factor of a field may change over
time based on operating history and in response to changes in technology and economics.
The recovery factor may also rise over time if additional investment is made in enhanced
oil recovery techniques such as gas injection or water-flooding.[2]

Because the geology of the subsurface cannot be examined directly, indirect techniques
must be used to estimate the size and recoverability of the resource. While new
technologies have increased the accuracy of these techniques, significant uncertainties
still remain. In general, most early estimates of the reserves of an oil field are
conservative and tend to grow with time. This phenomenon is called reserves growth.[3]

In most cases, oil refers to conventional oil and excludes oil from coal and oil shale.
Depending on the source, bitumen and extra-heavy oil (tar sands) may also be excluded.[4]
The exact definition varies from country to country and national statistics are not always
comparable. Many oil producing nations do not reveal their reservoir engineering field
data, and instead provide unaudited claims for their oil reserves. The numbers disclosed
by national governments are also sometimes manipulated for political reasons. [5]

Hubbert Peak Graph showing that oil production has peaked in non-OPEC and non-FSU
countries
Contents

[hide]
 1 Classifications
o 1.1 Proved reserves
o 1.2 Unproved reserves
o 1.3 Strategic petroleum reserves
o 1.4 Resources
 2 Estimation Techniques
o 2.1 Volumetric method
o 2.2 Materials balance method
o 2.3 Production decline curve method
 3 Reserves growth
 4 Estimated reserves in order
o 4.1 Saudi Arabia
o 4.2 Canada
o 4.3 Iran
o 4.4 Iraq
o 4.5 Kuwait
o 4.6 United Arab Emirates
o 4.7 Venezuela
o 4.8 Russia
o 4.9 Libya
o 4.10 Nigeria
 4.10.1 Prospective resources
o 4.11 United States
 4.11.1 Proven reserves
 4.11.2 Strategic Petroleum Reserve
 4.11.3 Prospective resources
 4.11.4 Unconventional prospective resources
  4.11.4.1 Oil shale
o 4.12 Mexico
 5 Arctic prospective resources
 6 OPEC countries
 7 See also
 8 Notes
 9 References

 10 External links

Classifications

Schematic graph illustrating petroleum volumes and probabilities. Curves represent

categories of oil in assessment. There is a 95-percent chance (i.e., probability, F95) of at
least volume V1 of economically recoverable oil, and there is a 5-percent chance (F05) of
at least volume V2 of economically recoverable oil.

Reserves are those quantities of petroleum anticipated to be commercially recoverable by

application of development projects to known accumulations under defined conditions.
Reserves must satisfy four criteria: They must be:
  discovered through one or more exploratory wells
 recoverable using existing technology
 commercially viable
 remaining in the ground

All reserve estimates involve uncertainty, depending on the amount of reliable geologic
and engineering data available and the interpretation of those data. The relative degree of
uncertainty can be expressed by dividing reserves into two principle classifications -
proved and unproved. Unproved reserves can further be divided into two subcategories -
probable and possible to indicate the relative degree of uncertainty about their existence.
The most commonly accepted definitions of these are based on those approved by the
Society of Petroleum Engineers (SPE) and the World Petroleum Council (WPC) in 1997.
[6]

Proved reserves

Proved reserves are claimed with reasonable certainty (80% to 90% confidence) to be
recoverable in future years by specified techniques. To meet this definition, the
development scenario must have been defined and use known technology, and the
scenario must be commercial under current economic conditions (prices and costs
prevailing at the time of the evaluation).[7] Industry specialists refer to this as P90 (i.e.
having a 90% certainty of being produced). Proved reserves are also known in the
industry as 1P.[8]

Proved reserves are further subdivided into Proved Developed (PD) and Proved
Undeveloped (PUD). PD reserves are reserves that can be produced with existing wells
and perforations, or from additional reservoirs where minimal additional investment
(operating expense) is required. PUD reserves require additional capital investment
(drilling new wells, installing gas compression, etc.) to bring the oil and gas to the
surface.

Proved reserves are the only type the U.S. Securities and Exchange Commission allows
oil companies to report to investors. Companies listed on U.S. stock exchanges must
substantiate their claims, but many governments and national oil companies do not
disclose verifying data to support their claims.

Unproved reserves

An oil well in Canada, which has the world's second largest oil reserves.

Probable reserves are based on median estimates of the accumulation that are more
likely to be recovered than not (50% confidence). This can result from either better
reservoir behaviour than expected under the proved category or additional investments to
be decided over the medium to long term (three to ten years) using conventional
techniques.[7] Industry specialists refer to this as P50 (i.e. having a 50% certainty of being
produced). Proved plus probable reserves are known in the industry as 2P.[8]

Possible reserves ideally have a chance of being developed under favourable

[7]
circumstances. Industry specialists refer to this as P10 (i.e. having a 10% certainty of
being produced). Proved plus probable plus possible reserves are known in the industry
as 3P.[8]

Unproved reserves are used internally by oil companies and government agencies for
future planning purposes.

Strategic petroleum reserves

Main article: global strategic petroleum reserves

Many countries maintain government-controlled oil reserves for both economic and
national security reasons. According to the United States Energy Information
Administration, approximately 4.1 billion barrels (650,000,000 m3) of oil are held in
strategic reserves, of which 1.4 billion is government-controlled. These reserves are
generally not counted when computing a nations oil reserves.

Resources

A more sophisticated system of evaluating petroleum accumulations was adopted in 2007

by the Society of Petroleum Engineers (SPE), World Petroleum Council (WPC),
American Association of Petroleum Geologists (AAPG), and Society of Petroleum
Evaluation Engineers (SPEE). It incorporates the 1997 definitions for reserves, but adds
categories for contingent resources and prospective resources. [9]

Contingent resources are those quantities of petroleum estimated, as of a given date, to

be potentially recoverable from known accumulations, but the applied project(s) are not
yet considered mature enough for commercial development due to one or more
contingencies. Contingent resources may include, for example, projects for which there
are currently no viable markets, or where commercial recovery is dependent on
technology under development, or where evaluation of the accumulation is insufficient to
clearly assess commerciality.

Prospective resources are those quantities of petroleum estimated, as of a given date, to

be potentially recoverable from undiscovered accumulations by application of future
development projects. Prospective resources have both an associated chance of discovery
and a chance of development.

Unconventional oil resources are greater then conventional ones.[10]

The United States Geological Survey uses the terms technically and economically
recoverable resources when making its petroleum resource assessments. Technically
recoverable resources represent that proportion of assessed in-place petroleum that may
be recoverable using current recovery technology, without regard to cost. Economically
recoverable resources are technically recoverable petroleum for which the costs of
discovery, development, production, and transport, including a return to capital, can be
recovered at a given market price.

Unconventional resources exist in petroleum accumulations that are pervasive

throughout a large area. Examples include extra heavy oil, natural bitumen, and oil shale
deposits. Unlike Conventional resources, in which the petroleum is recovered through
wellbores and typically requires minimal processing prior to sale, unconventional
resources require specialized extraction technology to produce. For example, steam
and/or solvents are used to mobilize bitumen for in-situ recovery. Moreover, the extracted
petroleum may require significant processing prior to sale (e.g. bitumen upgraders).[9] The
total amount of unconventional oil resources in the world considerably exceeds the
amount of conventional oil reserves, but are much more difficult and expensive to
develop.

Estimation Techniques

The amount of oil in a subsurface reservoir is called Oil in place (OIP). Only a fraction of
this oil can be recovered from a reservoir. This fraction is called the recovery factor. The
portion that can be recovered is considered to be a reserve. The portion that is not
recoverable is not included unless and until methods are implemented to produce it.

There are a number of different methods of calculating oil reserves. These methods can
be grouped into three general categories: volumetric, material balance, and production
performance. Each method has its advantages and drawbacks. [11] [12]

Volumetric method

Further information: Extraction of petroleum, Oil in place

Steam is injected into many oil fields where the oil is thicker and heavier than normal
crude oil

Volumetric methods attempt to determine the amount of oil-in-place by using the size of
the reservoir as well as the physical properties of its rocks and fluids. Then a recovery
factor is assumed, using assumptions from fields with similar characteristics. OIP is
multiplied by the recovery factor to arrive at a reserve number. The method is most useful
early in the life of the reservoir, before significant production has occurred.

The first step is to calculate the stock tank oil, or oil in place. This calculation is made
using the volume of rock containing oil (Bulk Rock Volume, in the USA this is usually in
acre-feet), percentage porosity of the rock in the reservoir, percentage water content of
that porosity, and the amount of shrinkage that the oil undergoes when brought to the
earth's surface.

The recovery factor is the percentage of the oil in place that can be produced from the
reservoir. The recovery factor depends on the viscosity of the oil (resistance of the oil to
flow), the permeability of the reservoir (ability of oil to flow through the pores in the
reservoir rock to the well), and the reservoir drive (what creates and maintain pressure in
the field besides pumps).
During the primary recovery stage, reservoir drive comes from a number of natural
mechanisms. These include: natural water displacing oil upward into the well, expansion
of the natural gas at the top of the reservoir, expansion of gas initially dissolved in the
crude oil, and gravity drainage resulting from the movement of oil within the reservoir
from the upper to the lower parts where the wells are located. Recovery factor during the
primary recovery stage is typically 5-15%.[13]

After natural reservoir drive diminishes, secondary recovery methods are applied. They
rely on the supply of external energy into the reservoir in the form of injecting fluids to
increase reservoir pressure, hence replacing or increasing the natural reservoir drive with
an artificial drive. Typically this is done by injecting water (water-flooding) in the
reservoir using a number of injection wells. Typical recovery factor from water-flood
operations is about 30%, depending on the properties of oil and the characteristics of the
reservoir rock. On average, the recovery factor after primary and secondary oil recovery
operations is between 30 and 50%. [13]

After this stage, tertiary or enhanced oil recovery techniques may be applied. These refer
to a number of operations that are typically done towards the end of life of an oilfield, to
maintain oil production and produce an additional 5-15% original OIP. Examples include
injection of CO2, nitrogen, or steam to improve oil flow.[13] [14]

Materials balance method

The materials balance method for an oil field uses an equation that relates the volume of
oil, water and gas that has been produced from a reservoir, and the change in reservoir
pressure, to calculate the remaining oil. It assumes that as fluids from the reservoir are
produced, there will be a change in the reservoir pressure that depends on the remaining
volume of oil and gas. The method requires extensive pressure-volume-temperature
analysis and an accurate pressure history of the field. It requires some production to occur
(typically 5% to 10% of ultimate recovery), unless reliable pressure history can be used
from a field with similar rock and fluid characteristics. [12]
Example of a production decline curve for an individual well

Production decline curve method

The decline curve method uses production data to fit a decline curve and estimate future
oil production. The three most common forms of decline curves are exponential,
hyperbolic, and harmonic. It is assumed that the production will decline on a reasonably
smooth curve, and so allowances must be made for wells shut in and production
restrictions. The curve can be expressed mathematically or plotted on a graph to estimate
future production. It has the advantage of (implicitly) including all reservoir
characteristics. It requires a sufficient history to establish a statistically significant trend,
ideally when production is not curtailed by regulatory or other artificial conditions. [12]

Reserves growth

Experience shows that initial estimates of the size of newly discovered oil fields are
usually too low. As years pass, successive estimates of the ultimate recovery of fields
tend to increase. The term reserve growth refers to the typical increases in estimated
ultimate recovery that occur as oil fields are developed and produced.[3]
Estimated reserves in order

Countries with largest oil reserves

Most of the world's oil reserves are in the Middle East.[15]

Estimating the amount of oil in any particular oil field involves a degree of uncertainty
until the last barrel of oil is produced and the last oil well is abandoned. The following
estimates are the best that could be obtained using publicly available data, and the
confidence in them varies greatly from country to country. Estimates in developed
countries are generally much more accurate than those for undeveloped countries. For
instance, reserves estimates in the United States are considered highly conservative,
while those in Russia are more speculative, and those in Iraq are highly uncertain due to
the lack of exploration data. In many countries (particularly OPEC producers) the
estimates may involve a great deal of political influence. The raw data underlying
reserves estimates is considered a state secret in some countries, so independent
assessments of their reserves cannot be made.

Summary of Reserve Data as of 2007

Country Reserves 1 Production 2 Reserve life 3

109 bbl 109 m3 106 bbl/d 103 m3/d years

Saudi Arabia 260 41 8.8 1,400 81

Canada 179 28.5 2.7 430 182

Iran 136 21.6 3.9 620 96

Iraq 115 18.3 3.7 590 85

Kuwait 99 15.7 2.5 400 108

United Arab Emirates 97 15.4 2.5 400 106

Venezuela 80 13 2.4 380 91

Russia 60 9.5 9.5 1,510 17

Libya 41.5 6.60 1.8 290 63

Nigeria 36.2 5.76 2.3 370 43

United States 21 3.3 4.9 780 11

Mexico 12 1.9 3.2 510 10

Total of top twelve

1,137 180.8 48.2 7,660 65
reserves
Notes:

1 Claimed or estimated reserves in billions (10 9) of barrels (converted to billions of cubic metres).
(Source: Oil & Gas Journal, January, 2007)
2 Production rate in millions (10 6) of barrels per day (converted to thousands of cubic metres per
day) (Source: US Energy Information Authority, September, 2007)[16]
3 Reserve to Production ratio (in years), calculated as reserves / annual production. (from above)

Saudi Arabia

Saudi Arabia has the largest proven oil reserves in the world, estimated to be 267 billion
barrels (42×109 m3) including 2.5 billion barrels in the Saudi-Kuwaiti neutral zone. This
is around one-fifth of the world's total conventional oil reserves. Although Saudi Arabia
has around 100 major oil and gas fields, over half of its oil reserves are contained in only
eight giant oil fields, including the Ghawar Field, the biggest oil field in the world with
an estimated 70 billion barrels (11×109 m3) of remaining reserves. Saudi Arabia maintains
the world’s largest crude oil production capacity, estimated to be around 11 million
barrels per day (1.7×106 m3/d) at mid-year 2008 and has announced plans to increase this
capacity to 12.5 million barrels per day (2.0×106 m3/d) by 2009[17]

Saudi Arabia produced 10.6 million barrels per day in 2006, and 10.3 million in 1980. [18]
At the beginning of 2008, the kingdom was producing around 9.2 million barrels per day
(1.46×106 m3/d) of oil.[19] After US President Bush asked the Saudis to raise production
on a visit to Saudi Arabia in January 2008, and they declined, Bush questioned whether
they had the ability to raise production any more. [20] In the summer of 2008, Saudi Arabia
announced an increase in planned production of 500,000 barrels per day.[21] However
there are experts who believe Saudi oil production has already peaked or will do so soon.
[18]

Despite its large number of oil fields, 90 percent of Saudi Arabia's oil production comes
from only five fields, and up to 60 percent of its production comes from the Ghawar field.
[22]
Since 1982 the Saudis have withheld their well data and any detailed data on their
reserves, giving outside experts no way to verify Saudi claims regarding the overall size
of their reserves and output. This has causes some to question the current state of their oil
fields. In a study discussed in Matthew Simmons book Twilight in the Desert, 200
technical papers on Saudi reserves by the Society of Petroleum Engineers were analyzed
to reach the conclusion that Saudi Arabia's oil production faces near term decline, and
that it will not be able to consistently produce more than current levels. [22] Simmons also
argues that the Saudis may have irretrievably damaged their large oil fields by over-
pumping salt water into the fields in an effort to maintain the fields' pressure and boost
short term oil extraction amounts.

Canada

See also: Athabasca Oil Sands and History of the petroleum industry in Canada
(oil sands and heavy oil)

Canadian conventional oil production peaked in 1973, but oil sands production is forecast
to increase to at least 2020

Canada's proven oil reserves were estimated at 179 billion barrels (28×109 m3) in 2007.
This figure includes oil sands reserves which are estimated by government regulators to
be economically producible at current prices using current technology.[23] According to
this figure, Canada's reserves are second only to Saudi Arabia. Over 95% of these
[24]
reserves are in the oil sands deposits in the province of Alberta. Alberta contains
nearly all of Canada's oil sands and much of its conventional oil reserves. The balance is
concentrated in several other provinces and territories. Saskatchewan and offshore areas
of Newfoundland in particular have substantial oil production and reserves.[25] Alberta has
39% of Canada's remaining conventional oil reserves, Saskatchewan 27% and offshore
Newfoundland 28%, but if oil sands are included, Albert's share is over 98%.[26]

Canada has a highly sophisticated energy industry and is both an importer and exporter of
oil and refined products. In 2006, in addition to producing 1.2 billion barrels
(190×106 m3), Canada imported 440 million barrels (70×106 m3), consumed 800 million
barrels (130×106 m3) itself, and exported 840 million barrels (134×106 m3) to the U.S.[24]
The excess of exports over imports was 400 million barrels (64×106 m3). Over 99% of
Canadian oil exports are sent to the United States, and Canada is the United States' largest
supplier of oil.[27]

The decision of accounting 174 billion barrels (28×109 m3) of the Alberta oil sands
deposits as proven reserves was made by the Alberta Energy and Utilities Board (AEUB),
now known as the Energy Resources Conservation Board (ERCB).[28] Although now
widely accepted, this addition was controversial at the time because oil sands contain an
extremely heavy form of crude oil known as bitumen which will not flow toward a well
under reservoir conditions. Instead, it must be mined, heated, or diluted with solvents to
allow it to be produced, and must be upgraded to lighter oil to be usable by refineries. [28].
Historically known as bituminous sands or sometimes as "tar sands", the deposits were
exposed as major rivers cut through the oil-bearing formations to reveal the bitumen in
the river banks. In recent years technological breakthroughs have overcome the
economical and technical difficulties of producing the oil sands, and by 2007 64% of
Alberta's petroleum production of 1.86 million barrels per day (296,000 m³/d) was from
oil sands rather than conventional oil fields. The ERCB estimates that by 2017 oil sands
production will make up 88% of Alberta's predicted oil production of 3.4 million barrels
per day (540,000 m³/d).[28]

The five-fold increase in oil prices from 1998 to 2007 made Canadian oil sands
production profitable.

Analysts estimate that a price of $30 to $40 per barrel is required to make new oil sands
production profitable.[24] In recent years prices have greatly exceeded those levels and the
Alberta government expects $116 billion worth of new oil sands projects to be
undertaken between 2008 and 2017.[28] However the biggest constraint on oil sands
development is a serious labor and housing shortage in Alberta as a whole and the oil
sands center of Fort McMurray in particular. According to Statistics Canada, by
September, 2006 unemployment rates in Alberta had fallen to record low levels [29] and
per-capita incomes had risen to double the Canadian average. Another hurdle has been
Canada's capacity to rapidly increase its export pipelines. The National Energy Board
indicated that exporters faced pipeline apportionment in 2007.[30] However, surging crude
oil prices sparked a jump in applications for oil pipelines in 2007, and new pipelines were
planned to carry Canadian oil as far south as U.S. refineries on the Gulf of Mexico.[31]

Canada is the only major oil producer in the Organization for Economic Co-operation
and Development (OECD) to have an increase in oil production in recent years.
Production in the other major OECD producers (the United States, United Kingdom,
Norway and Mexico) have been declining, as has conventional oil production in Canada.
But total crude oil production in Canada was projected to increase by an average of 8.6
percent per year from 2008 to 2011 as a result of new non-conventional oil projects.[32]

Iran

See also: National Iranian Oil Company

Iran claims to have the world's third largest reserves of oil at approximately 136 billion
barrels (21.6×109 m3) as of 2007, although it ranks second if Canadian reserves of non-
conventional oil are excluded. This is roughly 10% of the world's total proven petroleum
reserves. Iran is the world's fourth largest oil producer and is OPEC's second-largest
producer after Saudi Arabia. As of 2006 it was producing an estimated 3.8 million barrels
per day (600×103 m3/d) of crude oil, equal to 5% of global production. [33] At 2006 rates of
production, Iran's oil reserves would last 98 years if no new oil was found.

Iranian production peaked at 6 Mbbl/d (950×103 m3/d) in 1974, but it has been unable to
produce at that rate since the 1979 Iranian Revolution due to a combination of political
unrest, war with Iraq, limited investment, US sanctions, and a high rate of natural decline.
Iran's mature oil fields are in need of enhanced oil recovery (EOR) techniques such as gas
injection to maintain production, which is declining at an annual rate of approximately
8% onshore and 10% offshore. With its current technology it is only able to recover about
25% of the oil in place, 10% less than the world average. Iran consumed 1.6 Mbbl/d
(250×103 m3/d) of its own oil as of 2006. Domestic consumption is increasing due to a
growing population and large government subsidies on gasoline, which reduces the
amount of oil available for export and contributes to a large government budget deficit.
Due to a lack of refinery capacity, Iran is the second biggest gasoline importer in the
world after the United States.[33] High oil prices in recent years have enabled Iran to
amass nearly $60 billion in foreign exchange reserves, but have not helped solve
economic problems such as high unemployment and inflation.[34]

Iraq

An oil power plant in Iraq, which has some of the world's largest oil reserves

Iraq claims to have the world's fourth largest reserves of oil at approximately 115 billion
barrels (18.3×109 m3), although it would rank third if Canadian reserves of non-
conventional oil were excluded.

As a result of war and civil unrest, these statistics have not been revised since 2001 and
are largely based on 2-D seismic data from three decades ago. International geologists
and consultants have estimated that unexplored territory may contain an estimated
additional 45 to 100 billion barrels (bbls) of recoverable oil. [35] However, in the absence
of exploration data these estimates are highly speculative and do not meet the industry
definitions of proven, probable, or possible oil reserves (see above).

A measure of the uncertainty about Iraq's oil reserves is indicated by the fact that the U.S.
Department of Energy (DOE) estimated that Iraq had 112 billion barrels (17.8×109 m3),
whereas the United States Geological Survey (USGS) estimated it was closer to 78 Gbbl
(12.4×109 m3) and Iraq's prewar deputy oil minister claimed it might have 300 Gbbl
(48×109 m3). The source of the uncertainty is that due to decades of war and unrest, Iraq's
western desert (which would contain almost all of the undiscovered oil), remains almost
completely unexplored.[36]

After more than a decade of sanctions and two Gulf Wars, Iraq’s oil infrastructure needs
modernization and investment. Despite a large reconstruction effort, the Iraqi oil industry
has not been able to meet hydrocarbon production and export targets. The World Bank
estimates that an additional $1 billion per year would need to be invested just to maintain
current production. Long-term Iraq reconstruction costs could reach $100-billion or
higher, of which more than a third will go to the oil, gas and electricity sectors. Another
challenge to Iraq's development of the oil sector is that resources are not evenly divided
across sectarian lines. Most known resources are in the Shiite areas of the south and the
Kurdish north, with few resources in control of the Sunni population in the center.

In 2006, Iraq's oil production averaged 2.0 million barrels per day (320×103 m3/d), down
from around 2.6 Mbbl/d (410×103 m3/d) of production prior to the coalition invasion in
2003.[35] Iraq's reserve to production ratio is 158 years.

Kuwait

Kuwait is OPEC's third largest oil producer and claims to hold approximately 104 billion
barrels (16.5×109 m3), 8% of the world's world oil reserves. This includes half of the
5 billion barrels (790×106 m3) in the Neutral Zone which Kuwait shares with Saudi
Arabia. Most of Kuwait's oil reserves are located in the 70 billion barrels (11×109 m3)
Burgan field, the second largest conventional oil field in the world, which has been
producing oil since 1938. Since most of Kuwait's major oil fields are over 60 years old,
maintaining production rates is becoming a problem.

The size of Kuwait's reserves came into question in 2006 when a leaked memo from the
Kuwait Oil Company (KOC) reported by Petroleum Intelligence Weekly that national
reserves of were some 48 billion barrels. The data was produced at the end of 2001 by
state-owned Kuwait Oil Co. (KOC) and based on the findings of its reserves management
committee. The total includes the whole of Kuwait plus its share of the Neutral Zone
shared with Saudi Arabia, which is referred to in Kuwait as the Divided Zone (DZ).
These barrels are split roughly 50-50 between "proven" reserves -- those with a 90%
certainty of being produced -- and "nonproven," which is assumed to be a combination of
probable and potential. The total figure is more than 50% lower than Kuwait's official
proven reserves of 101.5 billion bbl. [37] [38]

Kuwait produces about 2.6 million barrels per day (410×103 m3/d) which translates to a
reserves-to-production ratio of about 100 years

United Arab Emirates

The United Arab Emirates (UAE) claims to have oil reserves of about 98 billion barrels
(15.6×109 m3), almost as big as Kuwait's claimed reserves. Of the emirates, Abu Dhabi
has most of the oil with 92 billion barrels (14.6×109 m3) while Dubai has 4 billion barrels
(640×106 m3) and Sharjah has 1.5 billion barrels (240×106 m3). Most of the oil is in the
Zakum field which is the third largest in the Middle East with an estimated 66 billion
barrels (10.5×109 m3). The UAE produces about 2.9 million barrels per day
(460×103 m3/d) of total oil liquids, but has stated its intention to increase this to 5 million
barrels per day (790×103 m3/d) by 2014. The UAE's reserves-to-production is about 93
years.[39]

Venezuela

Venezuela had 80 billion barrels (13×109 m3) of conventional oil reserves as of 2007, the
largest oil reserves of any country in South America. In 2006, it had net oil exports of
2.2 million barrels per day (350×103 m3/d), the sixth-largest in the world and the largest
in the Western Hemisphere. In recent years, crude oil production has been falling, mostly
due to depletion of existing oil fields and, since many of its oil fields suffer production
decline rates of at least 25 percent per year, industry analysts estimate that Venezuela
must spend some $3 billion each year just to maintain production levels. As a result of
the lack of transparency in the country's accounting, Venezuela's true level of oil
production is difficult to determine, but most industry analysts estimate that it produced
around 2.8 million barrels per day (450×103 m3/d) of oil in 2006[40] This would give it 88
years of remaining production at current rates.
In October 2007 the Venezuelan government said its proven oil reserves had risen to
100 billion barrels (16×109 m3). The energy and oil ministry said it had certified an
additional 12.4 billion barrels (2.0×109 m3) of proven reserves in the country's Faja del
Orinoco region.[41]

In addition to conventional oil, Venezuela has oil sands deposits similar in size to those
of Canada (approximately equal to the world's reserves of conventional oil). Venezuela's
Orinoco tar sands are less viscous than Canada's Athabasca oil sands – meaning they can
be produced by more conventional means, but they are buried deeper – meaning they
cannot be extracted by surface mining. Estimates of the recoverable reserves of the
Orinoco Belt range from 100 billion barrels (16×109 m3) to 270 billion barrels
(43×109 m3). However, they are not generally considered proven reserves since
Venezuela lacks enough technological expertise and capital to develop them on a
sufficiently large scale.

Venezuela's development of its oil reserves has been affected by political unrest in recent
years. In late 2002 nearly half of the workers at the state oil company PDVSA went on
strike, after which the company fired 18,000 of them. In the opinion of many industry
analysts this affected its ability to maintain its oil fields and has contributed to declines in
oil production. The crude oil that Venezuela has is very heavy by international standards,
and as a result much of it must be processed by specialized domestic and international
refineries. Venezuela continues to be one of the largest suppliers of oil to the United
States, sending about 1.4 million barrels per day (220×103 m3/d) to the U.S. Venezuela is
also a major oil refiner and the owner of the Citgo gasoline chain.[40]

Russia

Estimates of proven reserves vary wildly. Most estimates include only Western Siberian
reserves, exploited since the 1970s and supplying two-thirds of Russian oil, and not
potentially huge reserves elsewhere. In 2005, the Russian Ministry of Natural Resources
estimated that another 4.7 billion barrels (0.75×109 m3) of oil exist in Eastern Siberia.[42]
Following the collapse of the former Soviet Union, Russia’s petroleum output fell
sharply, and has rebounded only in the last several years. Russia reached a peak of
12.5 million barrels per day (1.99×106 m3/d) in total liquids in 1988, and production had
fallen to around 6 Mbbl/d (950×103 m3/d) by the mid 1990's. A turnaround in Russian oil
output began in 1999, which many analysts attribute to the privatization of the industry.
Higher world oil prices, the use of Western technology, and the rejuvenation of old oil
fields also helped. By 2007 Russian production had recovered to 9.8 Mbbl/d
(1.56×106 m3/d), but was growing at a slower rate than 2002-2004.[42] In 2008, production
fell 1 percent in the first quarter and Lukoil vice president Leonid Fedun said $1 trillion
would have to be spent on developing new reserves if current production levels were to
be maintained. The editor in chief of the Russian Petroleum Investor claims that Russian
production had reached a secondary peak in 2007.[43]

In 2007, Russia produced roughly 9.8 Mbbl/d (1.56×106 m3/d) of liquids, consumed

roughly 2.8 Mbbl/d (450×103 m3/d) in liquids, and exported (in net) around 7 Mbbl/d
(1.1×106 m3/d). Over 70 percent of Russian oil production was exported, while the
remaining 30 percent was refined locally. [44] In early 2008 Russian officials were reported
to be concerned because, after rising just 2% during 2007, oil production started to
decline again in 2008. The government proposed tax cuts on oil in an attempt to stimulate
production.[45]

Libya

Libya holds the largest oil reserves in Africa and the ninth largest oil reserves in the
world with 41.5 billion barrels (6.60×109 m3) as of 2007. Oil production was 1.8 million
barrels per day (290×103 m3/d) as of 2006, giving Libya 63 years of reserves at current
production rates if no new reserves were to be found. Libya is considered a highly
attractive oil area due to its low cost of oil production (as low as $1 per barrel at some
fields), and proximity to European markets. Libya would like to increase production from
1.8 Mbbl/d (290×103 m3/d) in 2006 to 3 Mbbl/d (480×103 m3/d) by 2010–13 but with
existing oil fields undergoing a 7–8% decline rate, Libya's challenge is maintaining
production at mature fields, while finding and developing new oil fields. Most of Libya
remains unexplored as a result of past sanctions and disagreements with foreign oil
companies.[47]

Nigeria

Although Libya has more reserves, Nigeria with 36.2 billion barrels (5.76×109 m3) of
proven reserves as of 2007 ranks as the largest oil producer in Africa and the 11th largest
in the world, averaging 2.28 million barrels per day (362×103 m3/d) as of 2006. At current
rates this would be 43 years of supply if no new oil was found. Pipeline vandalism,
kidnappings, and militant takeover of oil facilities have reduced production, which could
be increased to 3 million barrels per day (480×103 m3/d) in the absence of such problems.
The Nigerian government hopes to increase oil production capacity to 4 Mbbl/d
(640×103 m3/d) by 2010. Nigeria is the world’s eighth largest exporter of crude oil and
sends 42% of its exports to the United States. Nigeria is heavily dependent on the oil
sector, which accounts for 95% of its export revenues.[48]

Prospective resources

Nigeria and Sao Tome have an agreement in which the Joint Development Authority was
created to explore and produce oil in the waters between Sao Tome and Nigeria. Nigeria
and Sao Tome share together in this area, called the Joint Development Zone ( or JDZ ).
This area could contain up to and above 14 billion barrels of oil. In 2006 Chevron drilled
an exploratory well called OBO-1 and news reports came out that they had discovered
over a billion barrels of oil in block 1 alone. The news reports, reported on CNN, AP, and
FoxNews quickly quieted down and no more news came out from Chevron.[citation needed]

United States

United States oil reserves peaked sharply in 1970

United States oil production also peaked in 1970. By 2005 imports were twice
production.

Proven reserves

United States proven oil reserves were 21 billion barrels (3.3×109 m3) in 2006 according
[49]
to the Energy Information Administration. This represents a decline of 46%, or
18 billion barrels (2.9×109 m3) from 39 billion barrels (6.2×109 m3) in 1970. U.S. crude
production peaked in 1970 at 9.6 million barrels per day (1.53×106 m3/d), after the
supergiant Prudhoe Bay field was found in Alaska. It has declined 47% to 5.1 million
barrels per day (810×103 m3/d) by 2006. [50]
United States crude oil production has been
declining since reaching a smaller secondary production peak in 1988 (caused by Alaskan
production). Total production of crude oil from 1970 through 2006 was 102 billion
barrels (16.2×109 m3), or roughly five and a half times the decline in proved reserves.[51]

The reserves-to-production (R/P) equaled 11.26 years in 2007. The ratio was 11.08 years
in 1970. It hit a trough of 8.49 years in 1986 as oil pumped through the Alaska pipeline
began to peak.[52]

Because of declining production and increasing demand, Net US imports of oil and
petroleum products increased by 400% from 3.16 million barrels per day (502×103 m3/d)
in 1970 to 12.04 million barrels per day (1.914×106 m3/d) in 2007. Its largest net
suppliers of petroleum products in 2007 were Canada and Mexico, which supplied 2.2
and 1.3 Mbbl/d (350×103 and 210×103 m3/d), respectively.[53]

Net imports of oil and products account for nearly half of the US trade deficit. As of
2007, the US consumed 20.68m bbls of petroleum products/day and imported a net
12.04m bbls/day. The EIA reports the United States "Dependence on Net Petroleum
Imports" as 58.2%.[54]

Strategic Petroleum Reserve

Main article: Strategic Petroleum Reserve

The United States maintains a Strategic Petroleum Reserve at four sites in the Gulf of
Mexico, with a total capacity of 727 million barrels (115.6×106 m3) of crude oil. The
maximum total withdrawal capability from the United States Strategic Petroleum Reserve
is 4.4 million barrels (700,000 m³) per day. This is roughly 32% of US oil imports, or
75% of imports from OPEC.

Estimates of Oil Resources in the Outer Continental Shelf [55]

Estimates of Onshore Oil Resources [56]

Prospective resources

Services under the U.S. Department of the Interior estimate the total volume of
undiscovered, technically recoverable oil in the United States to be roughly 134 billion
barrels. Over 1 million exploratory and developmental crude oil wells have been drilled
in the US since 1949.[57]

The Minerals Management Service (MMS) estimates the Federal Outer Continental Shelf
(OCS) contains between 66.6 and 115.1 billion barrels (10.59×10 9 and 18.30×109 m3) of
undiscovered technically recoverable crude oil, with a mean estimate of 85.9 billion
barrels (13.66×109 m3). The Gulf of Mexico OCS ranks first with a mean estimate of
44.9 billion barrels (7.14×109 m3), followed by Alaska OCS with 38.8 billion barrels
(6.17×109 m3). At $80/bbl crude prices, the MMS estimates that 70 billion barrels
(11×109 m3) are economically recoverable. As of 2008, a total of about 574 million acres
of the OCS are off-limits to leasing and development. The moratoria and presidential
withdrawal cover about 85 percent of OCS acreage offshore the lower 48 states. The
MMS estimates that the resources in OCS areas currently off limits to leasing and
development total 17.8 billion barrels (2.83×109 m3)(mean estimate).[55]
The United States Geological Survey (USGS) estimates undiscovered technically
recoverable crude oil onshore in United States to be 48.5 billion barrels (7.71×109 m3) [56]
[58]
The last comprehensive National Assessment was completed in 1995. Since 2000 the
USGS has been re-assessing basins of the U.S. that are considered to be priorities for oil
and gas resources. Since 2000, the USGS has re-assessed 22 priority basins, and has
plans to re-assess 10 more basins. These 32 basins represent about 97% of the discovered
and undiscovered oil and gas resources of the United States. The three areas considered
to hold the most amount of oil are the coastal plain (1002) area of ANWR, the National
Petroleum Reserve of Alaska, and the Bakken Formation.

In 1998, the USGS estimated that 1002 area of the Arctic National Wildlife Refuge
contains a total of between 5.7 and 16.0 billion barrels of undiscovered, technically
recoverable oil, with a mean estimate of 10.4 billion barrels, of which 7.7 billion barrels
[59]
falls within the Federal portion of the ANWR 1002 Area. In May 2008 the EIA used
this assessment to estimate the potential cumulative production of the 1002 area of
ANWR to be a maximum of 4.3 billion barrels from 2018 to 2030. This estimate is a best
case scenario of technically recoverable oil during the area's primary production years if
legislation were passed in 2008 to allow drilling. [60]

A 2002 assessment concluded that the National Petroleum Reserve–Alaska contains

between 6.7 and 15.0 billion barrels of oil, with a mean (expected) value of 10.6 billion
barrels. The quantity of undiscovered oil beneath Federal lands (excluding State and
Native areas) is estimated to range between 5.9 and 13.2 BBO, with a mean value of 9.3
BBO. Most oil accumulations are expected to be of moderate size, on the order of 30 to
250 million barrels each. Large accumulations like the Prudhoe Bay oil field (whose
ultimate recovery is approximately 13 billion barrels), are not expected to occur. The
volumes of undiscovered, technically recoverable oil estimated for NPRA are similar to
the volumes estimated for ANWR. However, because of differences in accumulation
sizes (the ANWR study area is estimated to contain more accumulations in larger size
classes) and differences in assessment area (the NPRA study area is more than 12 times
larger than the ANWR study area), economically recoverable resources are different at
low oil prices. But at market prices above $40 per barrel, estimates of economically
recoverable oil for NPRA are similar to ANWR.[61]

In April 2008, the USGS released a report giving a new resource assessment of the
Bakken Formation underlying portions of Montana and North Dakota. The USGS
believes that with new horizontal drilling technology there is somewhere between 3.0 and
4.5 billion barrels (480×106 and 720×106 m3) of undiscovered, technically recoverable oil
in this 200,000 square miles (520,000 km2) formation that was initially discovered in
1951. If accurate, this reassessment would make it the largest continuous oil formation
ever discovered in the U.S.[58]

Unconventional prospective resources

Oil shale

Main article: Oil shale reserves

The United States has the largest known deposits of oil shale in the world, according to
the Bureau of Land Management and holds an estimated 2,175 gigabarrels of potentially
recoverable oil.[62] Oil shale does not actually contain oil, but a waxy oil precursor known
as kerogen. There is no significant commercial production of oil from oil shale in the
United States.

Mexico

Mexico's Major Southern offshore oil fields. Mexico is estimated to have about 12.4
billion barrels of oil reserves
Mexican production peaked in 2004 and is now in decline
See also: Oil in Mexico

The Oil and Gas Journal (OGJ) estimated that as of 2007, Mexico had 12.4 billion barrels
(1.97×109 m3) of proven oil reserves. Mexico was the sixth-largest oil producer in the
world as of 2006, producing 3.71 million barrels per day (590×103 m3/d) of petroleum
products, of which 3.25 million barrels per day (517×103 m3/d) was crude oil. Mexican
oil production has started to decline rapidly. The U.S. Energy Information Administration
had estimated that Mexican production of petroleum products would decline to
3.52 million barrels per day (560×103 m3/d) in 2007 and 3.32 million barrels per day
(528×103 m3/d) in 2008.[63] Mexican crude oil production fell in 2007, and was below
3.0 million barrels per day (480×103 m3/d) by the start of 2008. In mid-2008, Pemex said
that it would try to keep crude oil production above 2.8 million barrels per day
(450×103 m3/d) for the rest of the year.[64] Mexican authorities expected the decline to
continue in future, and were pessimistic that it could be raised back to previous levels
even with foreign investment.[65]

In Mexico, oil production is a state monopoly. The constitution of Mexico gives the state
oil company, PEMEX, exclusive rights over oil production, and the Mexican government
treats Pemex as a major source of revenue. As a result, Pemex has insufficient capital to
develop new and more expensive resources on its own, and cannot take on foreign
partners to supply money and technology it lacks.[66] To address some of these problems,
in September 2007, Mexico’s Congress approved reforms including a reduction in the
taxes levied on Pemex.[63]

Most of Mexico's production decline involves one enormous oil field in the Gulf of
Mexico. From 1979 to 2007, Mexico produced most of its oil from the supergiant
Cantarell Field, which used to be the second-biggest oil field in the world by production.
Because of falling production, in 1997 Pemex started a massive nitrogen injection project
to maintain oil flow, which now consumes half the nitrogen produced in the world. As a
result of nitrogen injection, production at Cantarell rose from 1.1 million barrels per day
(170×103 m3/d) in 1996 to a peak of 2.1 million barrels per day (330×103 m3/d) in 2004.
However, during 2006 Cantarell's output fell 25% from 2.0 million barrels per day
(320×103 m3/d) in January to 1.5 million barrels per day (240×103 m3/d) in December,
with the decline continuing through 2007.[63] In mid-2008, Pemex announced that it
would try to end the year with Cantarell producing at least 1.0 million barrels per day
(160×103 m3/d).[64]

As for its other fields, 40% of Mexico's remaining reserves are in the Chicontepec Field,
which was found in 1926. The field has remained undeveloped because the oil is trapped
in impermeable rock, requiring advanced technology and very large numbers of oil wells
to extract it. The remainder of Mexico's fields are smaller, more expensive to develop,
and contain heavy oil and trades at a significant discount to light and medium oil, which
is easier to refine.

In 2002 PEMEX began developing an oil field called "Proyecto Ku-Maloob-Zaap",

located 105 kilometers from Ciudad del Carmen. It is estimated that by 2011 the field
will produce nearly 800 thousand barrels per day (130×103 m3/d).[citation needed] However, this
level of production will be achieved by using a nitrogen injection scheme similar to that
of Cantarell. That same year, Pemex decreased its reserve estimate by 53%, from 26.8 to
12.6 billion barrels (4.26×109 to 2.00×109 m3). Later the estimate was increased to
15.7 billion barrels (2.50×109 m3).

In June, 2007 former U.S. Federal Reserve Chairman Alan Greenspan warned that
declining oil production in Mexico could cause a major fiscal crisis there, and that
Mexico needed to increase investment in its energy sector to prevent it.[67]

Arctic prospective resources

See also: Petroleum exploration in the Arctic

Location of Arctic Basins assessed by the USGS

A 2008 United States Geological Survey estimates that areas north of the Arctic Circle
have 90 billion barrels of undiscovered, technically recoverable oil (and 44 billion barrels
of natural gas liquids ) in 25 geologically defined areas thought to have potential for
petroleum. This represents 13 percent of the undiscovered oil in the world. Of the
estimated totals, more than half of the undiscovered oil resources are estimated to occur
in just three geologic provinces - Arctic Alaska, the Amerasia Basin, and the East
Greenland Rift Basins. More than 70 percent of the mean undiscovered oil resources is
estimated to occur in five provinces: Arctic Alaska, Amerasia Basin, East Greenland Rift
Basins, East Barents Basins, and West Greenland–East Canada. It is further estimated
that approximately 84 percent of the undiscovered oil and gas occurs offshore. The USGS
did not consider economic factors such as the effects of permanent sea ice or oceanic
water depth in its assessment of undiscovered oil and gas resources. This assessment is
lower than a 2000 survey, which had included lands south of the arctic circle. [68] [69] [70]

Extensive drilling was done in the Canadian Arctic during the 1970s and 1980s by such
companies as Panarctic Oils Ltd., Petro Canada and Dome Petroleum. After 176 wells
were drilled at billions of dollars of cost, approximately 1.9 billion barrels (300×106 m3)
of oil and 19.8 trillion cubic feet (560×109 m3) of natural gas were found. These
discoveries were insufficient to justify development, and all the wells which were drilled
were plugged and abandoned.
Drilling in the Canadian Arctic turned out to be expensive and dangerous. The geology of
the Canadian Arctic turned out to be far more complex than oil-producing regions like the
Gulf of Mexico. It was discovered to be gas prone rather than oil prone (i.e. most of the
oil had been transformed into natural gas by geological processes), and most of the
reservoirs had been fractured by tectonic activity, allowing most of the petroleum which
might at one time have been present to leak out.[71]

Greenland is believed by some geologists to have some of the world’s largest remaining
[72]
oil resources. . Prospecting is taking place under the auspices of NUNAOIL, a
partnership between the Greenland Home Rule Government and the Danish state. U.S.
Geological Survey found in 2001 that the waters off north-eastern Greenland (north and
south of the arctic circle) could contain up to 110 billion barrels (17×109 m3) of oil. [73]

OPEC countries

There are doubts about the reliability of official OPEC reserves estimates, which are not
provided with any form of audit or verification that meet external reporting standards.[74]

Since a system of country production quotas was introduced in the 1980s, partly based on
reserves levels, there have been dramatic increases in reported reserves among Opec
producers. In 1983, Kuwait increased its proven reserves from 67 Gbbl (10.7×109 m3) to
92 Gbbl (14.6×109 m3). In 1985-86, the UAE almost tripled its reserves from 33 Gbbl
(5.2×109 m3) to 97 Gbbl (15.4×109 m3). Saudi Arabia raised its reported reserve number
in 1988 by 50%. In 2001-02, Iran raised its proven reserves by some 30% to 130 Gbbl
(21×109 m3), which advanced it to second place in reserves and ahead of Iraq. Iran denied
accusations of a political motive behind the readjustment, attributing the increase instead
to a combination of new discoveries and improved recovery. No details were offered of
how any of the upgrades were arrived at. [38] [74]

The following table illustrates these rises.

OPEC countries
Oil reserves of OPEC 1980-2005
 Declared reserves of major Opec Producers (billion of barrels)
BP Statistical Review - June 2008
Year Iran Iraq Kuwait Saudi Arabia UAE Venezuela Libya Nigeria
1980 58.3 30.0 67.9 168.0 30.4 19.5 20.3 16.7
1981 57.0 32.0 67.7 167.9 32.2 19.9 22.6 16.5
1982 56.1 59.0 67.2 165.5 32.4 24.9 22.2 16.8
1983 55.3 65.0 67.0 168.8 32.3 25.9 21.8 16.6
1984 58.9 65.0 92.7 171.7 32.5 28.0 21.4 16.7
1985 59.0 65.0 92.5 171.5 33.0 54.5 21.3 16.6
1986 92.9 72.0 94.5 169.7 97.2 55.5 22.8 16.1
1987 92.9 100.0 94.5 169.6 98.1 58.1 22.8 16.0
1988 92.9 100.0 94.5 255.0 98.1 58.5 22.8 16.0
1989 92.9 100.0 97.1 260.1 98.1 59.0 22.8 16.0
1990 92.9 100.0 97.0 260.3 98.1 60.1 22.8 17.1
1991 92.9 100.0 96.5 260.9 98.1 62.6 22.8 20.0
1992 92.9 100.0 96.5 261.2 98.1 63.3 22.8 21.0
1993 92.9 100.0 96.5 261.4 98.1 64.4 22.8 21.0
1994 94.3 100.0 96.5 261.4 98.1 64.9 22.8 21.0
1995 93.7 100.0 96.5 261.5 98.1 66.3 29.5 20.8
1996 92.6 112.0 96.5 261.4 97.8 72.7 29.5 20.8
1997 92.6 112.5 96.5 261.5 97.8 74.9 29.5 20.8
1998 93.7 112.5 96.5 261.5 97.8 76.1 29.5 22.5
1999 93.1 112.5 96.5 262.8 97.8 76.8 29.5 29.0
2000 99.5 112.5 96.5 262.8 97.8 76.8 36.0 29.0
2001 99.1 115.0 96.5 262.7 97.8 77.7 36.0 31.5
2002 130.7 115.0 96.5 262.8 97.8 77.3 36.0 34.3
2003 133.3 115.0 99.0 262.7 97.8 77.2 39.1 35.3
2004 132.7 115.0 101.5 264.3 97.8 79.7 39.1 35.9
2005 137.5 115.0 101.5 264.2 97.8 80.0 41.5 36.2
2006 138.4 115.0 101.5 264.3 97.8 87.0 41.5 36.2
2007 138.4 115.0 101.5 264.2 97.8 87.0 41.5 36.2

The sudden revisions in OPEC reserves, totaling nearly 300 bn barrels, has been much
debated.[75] Some of it is defended partly by the shift in ownership of reserves away from
international oil companies, some of whom were obliged to report reserves under
conservative US Securities and Exchange Commission rules.[76] [74]
The most prominent
explanation is the revisions were prompted by OPEC rules which set production quotas
(partly) on reserves. In any event, the revisions in official data had little to do with the
actual discovery of new reserves. Total reserves in many OPEC countries hardly changed
in the 1990s. Official reserves in Kuwait, for example, were unchanged at 96.5 Gbbl
(15.34×109 m3) (including its share of the Neutral Zone) from 1991 to 2002, even though
the country produced more than 8 Gbbl (1.3×109 m3) and did not make any important
new discoveries during that period. The case of Saudi Arabia is also striking, with proven
reserves estimated at between 260 and 264 billion barrels in the past 18 years, a variation
of less than 2%. [74]

Sadad al-Huseini, former head of exploration and production at Saudi Aramco, estimates
300 Gbbl (48×109 m3) of the world’s 1,200 Gbbl (190×109 m3) of proved reserves should
be recategorized as speculative resources, though he did not specify which countries had
[77]
inflated their reserves. Dr. Ali Samsam Bakhtiari, a former senior expert of the
National Iranian Oil Company, has estimated that Iran, Iraq, Kuwait, Saudi Arabia and
the United Arab Emirates have overstated reserves by a combined 320-390bn barrels, and
"As for Iran, the usually accepted official 132 billion barrels is almost one hundred
billion over any realistic assay".[78] Petroleum Intelligence Weekly reported that official
confidential Kuwaiti documents estimate reserves of Kuwait were only 48 billion barrels
(7.6×109 m3), of which half were proven and half were possible. The combined value of
proven and possible is half of the official public estimate of proven reserves. [38]