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 therecovery factor. Recovery factors vary greatly among oil fields. 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, water-flooding,[1] or microbial enhanced oil recovery. 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.[2] 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 some national governments are suspected of being manipulated for political reasons.[3] Reserves are those quantities of petroleum claimed to be commercially recoverable by application of development projects to known accumulations under defined conditions.[5] Reserves must satisfy four criteria: They must be: 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—"proven" (or "proved") and "unproven" (or "unproved").[5] Unproven reserves can further be divided into two subcategories—"probable" and "possible"—to indicate the relative degree of uncertainty about their existence.[5] The most commonly accepted definitions of these are based on those approved by theSociety of Petroleum Engineers (SPE) and the World Petroleum Council (WPC) in 1997.[6] Proven reserves are those reserves claimed to have a reasonable certainty (normally at least 90% confidence) of being recoverable under existing economic and political conditions, with existing technology. Industry specialists refer to this as P90 (i.e., having a 90% certainty of being produced). Proven reserves are also known in the industry as 1P.[7][8] Proven reserves are further subdivided into "proven developed" (PD) and "proven undeveloped" (PUD).[8][9] 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.[9] PUD reserves require additional capital investment (e.g., drilling new wells) to bring the oil to the surface.[7][9] 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. Unproven reserves are based on geological and/or engineering data similar to that used in estimates of proven reserves, but technical, contractual, or regulatory uncertainties preclude such reserves being classified as proven.[10] Unproven reserves may be used internally by oil companies and government agencies for future planning purposes but are not routinely compiled. They are sub-classified as probable andpossible.[10] Probable reserves are attributed to known accumulations and claim a 50% confidence level of recovery. Industry specialists refer to them asP50 (i.e., having a 50% certainty of being produced). These reserves are also referred to in the industry as 2P (proven plus probable).[7] Possible reserves are attributed to known accumulations that 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) and projected reserves based on future recovery methods. They are referred to in the industry as 3P (proven plus probable plus possible).[7] 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 nation's 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.[5] 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 undiscoveredaccumulations 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).[5] 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).[9] Only a fraction of this oil can be recovered from a reservoir. This fraction is called the recovery factor.[9] 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.[9][10] 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. Current recovery factors for oil fields around the world typically range between 10 and 60 percent; some are over 80 percent. The wide variance is due largely to the diversity of fluid and reservoir characteristics for different deposits.[12][13][14]The method is most useful early in the life of the reservoir, before significant production has occurred. 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.[10] Rashid Ali 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.[10] 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.[2] 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.[18] 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.[18][19] The following table illustrates these rises. The sudden revisions in OPEC reserves, totaling nearly 300 bn barrels, have been much debated.[20] 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.[18][21] The most prominent explanation of the revisions is prompted by a change in 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.[18] Total reserves in many OPEC countries hardly changed in the 1990s.[18] 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.[18] The case of Saudi Arabia is also striking, with proven reserves estimated at between 260 and 264 billion barrels (4.20×1010 m3) in the past 18 years, a variation of less than 2%,[18] while extracting approximately 60 billion barrels (9.5×109 m3) during this period. 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 proven reserves should be recategorized as speculative resources, though he did not specify which countries had inflated their reserves.[22] 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 has said, "As for Iran, the usually accepted official 132 billion barrels (2.10×1010 m3) is almost one hundred billion over any realistic assay."[23] 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.[19] A 2008 United States Geological Survey estimates that areas north of the Arctic Circle have 90 billion barrels (1.4×1010 m3) of undiscovered, technically recoverable oil and 44 billion barrels (7.0×109 m3) of natural gas liquids in 25 geologically defined areas thought to have potential for petroleum. This represented 13% of the expected undiscovered oil in the world. Of the estimated totals, more than half of the undiscovered oil resources were 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 was estimated to occur in five provinces: Arctic Alaska, Amerasia Basin, East Greenland Rift Basins, East Barents Basins, and West Greenland–East Canada. It was further estimated that approximately 84% of the oil and gas would occur 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 was lower than a 2000 survey, which had included lands south of the Arctic Circle.[24][25][26] In October 2009, the USGS updated the Orinoco tar sands (Venezuela) value to 513 billion barrels (8.16×1010 m3).[27] The Exclusive Economic Zone is a delineated offshore area, mostly to the west and north of Cuba, which, under international agreements, is owned by Cuba. This 112,000-square-kilometer zone has been divided into 59 exploration blocks. 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 produce ultimately between 4.6 and 9.3 billion barrels of crude oil.[28] The US Geological Survey (USGS) estimates that Cuba has resources up to 9 billion barrels (1.4×109 m3) of oil. In October 2008, the Cuban government announced that it had discovered oil basins that would double its total oil resources to 20 billion barrels (3.2×109 m3).[29] Note that, consistent with the definitions of reserves and resources as given in the above sections, at this stage (June 2009), given no commercial discoveries to date, all recoverable oil estimates in the Exclusive Economic Zone (EEZ) are prospective resources estimates and not reserves estimates. Energy and resources:Oil reserves
Contents
[hide][edit]Classifications
[edit]Proven reserves
[edit]Unproven reserves
[edit]Strategic petroleum reserves
[edit]Resources
[edit]Estimation techniques
[edit]Volumetric method
[edit]Materials balance method
[edit]Production decline curve method
[edit]Reserves growth
[edit]Estimated reserves by country
Country Reserves [16] Production [17] Reserve life 1 109 bbl 109 m3 106 bbl/d 103 m3/d years Saudi Arabia 267 42.4 9.7 1,540 127.5 Iraq 180 29 3.5 560 142 Canada 179 28.5 2.1 330 188 Iran 138 21.9 4.0 640 95 Kuwait 104 16.5 2.6 410 110 Venezuela 99 15.7 2.7 430 100 United Arab Emirates 98 15.6 2.9 460 93 Russia 60 9.5 9.9 1,570 17 Kazakhstan 47 7.5 1.4 220 93 Libya 41 6.5 1.7 270 66 Nigeria 36 5.7 2.4 380 41 United States 21 3.3 7.5 1,190 8 China 16 2.5 3.9 620 11 Qatar 15 2.4 0.9 140 46 Algeria 12 1.9 2.2 350 15 Brazil 12 1.9 2.3 370 14 Mexico 12 1.9 3.5 560 9 Total of top seventeen reserves 1,243 197.6 63.5 10,100 54 Notes: [edit]OPEC countries
Declared reserves of major Opec Producers (billion of barrels) BP Statistical Review - June 2009 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 87.3 41.5 36.2 2007 138.2 115.0 101.5 264.2 97.8 99.4 43.7 36.2 2008 137.6 115.0 101.5 264.1 97.8 99.4 43.7 36.2 [edit]Prospective resources
[edit]Arctic prospective resources
[edit]Miscellaneous prospective resources
[edit]See also
[edit]References
[edit]External links
[hide]Peak Oil Core issues 
Results/responses People Books Films Organizations Other "peaks"
Friday, 1 April 2011
From Wikipedia, the free encyclopedia
Main article: global strategic petroleum reserves
Further information: Extraction of petroleum, Oil in place
See also: List of countries by proven oil reserves
See also: Petroleum exploration in the Arctic
Hirsch report · Oil Depletion Protocol · Price of petroleum · 2000s energy crisis · Energy crisis · Export Land Model · Food vs fuel · Oil reserves · Pickens Plan ·Swing producer · Transition Towns
Posts
