The total estimated amount of oil in an oil reservoir, including both producible and non-producible oil, is called 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 producible oil reserves to total oil in place for a given field is often referred to as the recovery factor. Recovery factors vary greatly from one oil field to oil field. The recovery factor of any particular 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.
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.
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.
Reserves are those quantities of petroleum claimed 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 principal 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.
Proved reserves are those reserves claimed to have a reasonable certainty (normally at least 90% confidence) of being recoverable under existing economic and political conditions, and using existing technology. 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.
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.
Probable reserves are based on median estimates, and claim a 50% confidence level of recovery. Industry specialists refer to this as P50 (i.e. having a 50% certainty of being produced). Referred to in the industry as 2P (proved plus probable).
Possible reserves have a less likely chance of being recovered than probable reserves. This term is often used for reserves which are claimed to have at least a 10% certainty of being produced (P10). Reasons for classifying reserves as possible include varying interpretations of geology, reserves not producible at commercial rates, uncertainty due to reserve infill (seepage from adjacent areas), projected reserves based on future recovery methods. Referred to in the industry as 3P (proved plus probable plus possible).
Unproved reserves are used internally by oil companies and government agencies for future planning purposes.
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.
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.
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.
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). 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.
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.
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%.
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%.
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.
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.
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.
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.
Estimated reserves in order
- See also: Oil reserves in Saudi Arabia, Oil reserves in Canada, Oil reserves in Iran, Oil reserves in Iraq, Oil reserves in Kuwait, Oil reserves in the United Arab Emirates, Oil reserves in Venezuela, Oil reserves in Russia, Oil reserves in Libya, Oil reserves in Nigeria, Oil reserves in the United States, Oil reserves in Cuba, and Oil reserves in Mexico
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.
|Country||Reserves 1||Production 2||Reserve life 3|
|109 bbl||109 m3||106 bbl/d||103 m3/d||years|
|United Arab Emirates||97||15.4||2.5||400||106|
|Total of top twelve reserves||1,137||180.8||48.2||7,660||65|
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.
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.
The following table illustrates these rises.
|Declared reserves of major Opec Producers (billion of barrels)|
|BP Statistical Review - June 2008|
The sudden revisions in OPEC reserves, totaling nearly 300 bn barrels, have been much debated. 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. 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%.
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 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". 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.
Arctic Prospective Resources
- See also: Petroleum exploration in the Arctic
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% 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% 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% 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.
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.
Greenland is believed by some geologists to have some of the world’s largest remaining 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.
Miscellaneous Prospective Resources
A 2004 joint partnership between a Spanish oil company and Cuba’s state oil company (CUPET) estimated Cuba's off-shore reserves to be able to ultimately produce between 4.6 and 9.3 billion barrels of crude oil. The US Geological Survey (USGS) estimates that Cuba has 9 billion barrels of oil. In October 2008, the Cuban government announced that it had discovered oil basins which would double it's total oil reserves to 20 billion barrels, mostly in off-shore oil. If the estimates are accurate, then Cuba would have one of the top 20 reserves in the world.