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Usgs assessment: Undiscovered, Technically Recoverable Oil and Gas Resources of Armenia, 2014

Using a geology-based assessment methodology, the U.S. Geological Survey estimated mean volumes of 1 million barrels of undiscovered, technically recoverable conventional oil and 6 billion cubic feet of undiscovered, technically recoverable conventional natural gas in Armenia.

http://pubs.usgs.gov/fs/2014/3048/

— — — — — —

1 million barrels = 136,4 тыс. тонн геологических(?) ресурсов,
Извлекамых запасов не более 45 тыс. тонн в самом лучшем случае.

Потребление нефти в Армении (2013) 49.28 tbd = 2454.144 тыс. тонн в год

6 billion cubic feet = 0.168 млрд. м3 геологических(?) ресурсов,
Извлекамых запасов не более 84 млн.м3 самом лучшем случае.

Потребление газа в Армении (2012) 86.52 billion cubic feet = 2.4 млрд. м3

— — — — — —
Искать в Армении нефть и газ является интересным (для поисковиков), но малоперспективным (для добытчиков) занятием.
Для Армении имеет смысл концентрация на горнометаллургической отрасли

Usgs assessment: Undiscovered Conventional Resources of the Western Canada, 2012

Assessment of Undiscovered Conventional Oil and Gas Resources of the Western Canada Sedimentary Basin, Canada, 2012

— — — — —
Нефть Минимум-Среднее-Максимум
million barrels of oil = 891-1321-1861
млн.т н.э. = 121.5-180.2-253.8

Газ Минимум-Среднее-Максимум
billion cubic feet = 17097-25386-35797
Млрд. м3 = 479-711-1002

— — — — —
Согласно BP Statistical Review of World Energy (June 2012) для Канады
Нефть
В 2011 (с нефтяными песками) Oil Proved reserves = 175200 million barrels of oil =
23897 млн.т
В 1998 (без нефтяных песков) Oil Proved reserves = 49800 million barrels of oil = 6793 млн.т
Газ
В 2011 Natural Gas Proved reserves = 2000 млрд. м3
— — — — —
Согласно EIA,
Нефть
2013 Proved reserves = 173.105 Billion Barrels = 173105 million barrels of oil
http://www.eia.gov/countries/country-data.cfm?fips=CA&trk=m#pet
— — — — —
По нефти
Western Canada Sedimentary Basin получается как 1/26.8 к Proved reserves Канады 1998 г.
По газу
Western Canada Sedimentary Basin получается как от 1/3 до 1/2 к Proved reserves Канады 2011 г.

очень странная, очень разная картина получается по нефти и газу для Western Canada Sedimentary Basin даже при неучете нефтяных песков.
— — — — —
Рассматриваемая территория примыкает с севера с Северной Дакоте с ее Баккеном, по мере истощения которого добыча неизбежно сдвинется к западу (Монтана, США), к югу (Южная Дакота) так и к северу (Канада). О стремительном росте добычи в Монтане и Южной Дакоте по ка ничего не слышно. По пропорциям традиционная-нетрадиционная нефть для Северной Дакоты можно грубо оценить пропорции для Канады.

Для Миннесоты, расположенной к востоку от Сев.Дакоты, нет никаких данных о добыче и запасах
— — — — —
По состоянию на December 2012
Добыча в Северной Дакоте в 10.2 раза больше, чем в Монтане
Добыча в Северной Дакоте в 154.6 раза больше, чем в Юж.Дакоте
http://www.eia.gov/state/rankings/?sid=ND#series/46

Crude Oil Proved Reserves, Reserves Changes, and Production, декабрь 2012

Для Южной Дакоты данных нет отдельным пунктом

По сравнению с Северной Дакотой в Монтане нет никакого роста запасов нефти и даже падение по сравнению с 2005 г.

Crude Oil Production, monthly tb/d

Если следовать официальной статистике, получается, что сдвиг из Сев.Дакоты может быть только на север.

Но тогда согласно представленной карте USGS НГБ Уиллистон в своей части, примыкающей к Монтане мало продуктивен.

Usgs assessment: Undiscovered Conventional Resources of the Arabian Peninsula and Zagros, 2012

Assessment of Undiscovered Conventional Oil and Gas Resources of the Arabian Peninsula and Zagros Fold Belt, 2012

Using a geology-based assessment methodology, the U.S. Geological Survey estimated means
of 86 billion barrels of oil and 336 trillion cubic feet of undiscovered natural gas resources in
the Arabian Peninsula and Zagros Fold Belt.

Twenty-three assessment units within seven petroleum systems were quantitatively assessed in this study, which represents a reassessment of this area last published in 2000 (U.S. Geological Survey World Energy Assessment Team, 2000) (fig. 1).

The seven TPSs and the main geologic elements used to define them are as follows: (1) Huqf–Paleozoic TPS―petroleum generated from Precambrian–Cambrian shales of the Huqf Supergroup in three Oman basins; (2) Paleozoic Composite TPS―petroleum generated from Silurian (and possibly Ordovician) marine source rocks over much of the Arabian Peninsula; (3) Paleozoic–Mesozoic Composite TPS includes the Euphrates Graben of Syria in which petroleum from Triassic source rock is present in addition to that from Paleozoic source rocks; (4) Mesozoic Composite TPS―petroleum generated from synrift Triassic and other Mesozoic source rocks in the Palmyra and Sinjar areas; (5) Madbi–Amran–Qishn TPS of Yemen―petroleum generated from Upper Jurassic marine source rocks; (6) Middle Cretaceous Natih TPS―petroleum from the Natih Formation trapped in the Fahud Salt Basin of Oman; and (7) Mesozoic–Cenozoic Composite TPS―
petroleum generated from Middle and Upper Jurassic and Lower and Upper Cretaceous source marine rocks over a wide area of the eastern Arabian Peninsula and Zagros. The 23 AUs that were defined geologically and assessed within these TPS are listed in table 1.

The USGS assessed undiscovered conventional oil and gas resources in 23 AUs within seven petroleum systems, with the following estimated mean totals: (1) for conventional oil resources, 85,856 million barrels of oil (MMBO), with a range from 34,006 to 161,651 MMBO; (2) for undiscovered conventional gas, 336,194 billion cubic feet of gas (BCFG), with a range from 131,488 to 657,939 BCFG; and (3) for natural gas liquids (NGL), 11,972 MMBNGL, with a range from 4,513 to 24,788 MMBNGL (table 1).

Of the mean undiscovered conventional oil resource of 85,856 MMBO, about 92 percent (78,747 MMBO) is estimated to be in six AUs within the Mesozoic–Cenozoic Composite Total Petroleum System (fig. 1B); most of this oil is estimated to be in the Zagros Fold Belt Structures AU (mean of 38,464 MMBO), the Mesopotamian Basin Anticlines AU (mean of 26,856 MMBO), the Arabian Platform Structures AU (mean of 6,626 MMBO), and the Horst Block and Suprasalt Structural Oil AU (mean of 5,300 MMBO).

For the undiscovered conventional gas resource mean of 336,194 BCFG, 96 percent is in two total petroleum systems: Paleozoic Composite TPS (mean of 189,273 BCFG) and the Mesozoic–Cenozoic Composite TPS (mean of 132,876 BCFG). In the Paleozoic Composite TPS, 56 percent (106,180 BCFG) of the undiscovered gas is estimated to be in the Zagros Fold Belt Reservoirs AU (table 1).

Similarly, 64 percent (85,610 BCFG) of the undiscovered gas in the Mesozoic–Cenozoic Composite TPS is in the Zagros Fold Belt Structures AU.

— — — — —
conventional oil resources
Среднее 85,856 million barrels of oil (MMBO) = 11.7 млрд. т
range 34,006-161,651 = 4.64 — 22.05 млрд. т

conventional gas
336,194 billion cubic feet of gas (BCFG) = 9.4 трлн. м3
range 131,488-657,939 = 3.7 — 18.4 трлн. м3

— — — — —
BP Statistical Review of World Energy June 2012

Запасы
нефти 765 млрд.барр = 104 млрд. т
газа 80 трлн. м3

Отношение средних неоткрытых ресурсов к известным запасам
нефть = 11.7/104 =11.3%
газ = 9.4/80 = 11.8%

Почти все открыто. Если использовать более скептичный подход и разделить на 3 неоткрытые ресурсы, то получается 3.8-3.9% от известных запасов.

Usgs assessment: Undiscovered Conventional Resources of Six Geologic Provinces of China, 2011

Assessment of Undiscovered Conventional Oil and Gas Resources of Six Geologic Provinces of China, 2011

The U.S. Geological Survey (USGS) assessed the potential for undiscovered conventional oil and
gas resources in six geologic provinces of China: Junggar Basin, Bohaiwan Basin, Ordos Basin,
Sichuan Basin, Songliao Basin, and Tarim Basin (fig. 1). Each province was divided into 1–4 assessment
units (AU), for a total of 13 AUs (table 1).

Only conventional oil and gas potential was assessed. Continuous (unconventional) resources such as shale gas, coalbed gas, and tight gas sands may exist in some of these basins but were not assessed at this time.

The assessment methodology included a study of the petroleum systems in each province, including tectonics, source rocks, reservoirs, and other geologic characteristics relevant to petroleum generation, migration, and trapping. The characteristics of discovered fields and their exploration histories were also studied. Estimates of the numbers and sizes of undiscovered oil fields were made separately from the estimates for gas fields. Coproduct ratios were applied to make additional estimates of gas and natural gas liquids (NGL) in oil fields and liquids in gas fields.

The Junggar Basin, in northwestern China, was divided into two AUs: one for the pre-Jurassic reservoirs and one for the Jurassic through Tertiary reservoirs. The Pre-Jurassic Reservoirs AU has oil and gas fields that are primarily in Permian and Triassic fluvial sandstones and fluvial and alluvial fan conglomerates. The main source rocks are Permian lacustrine rocks and Jurassic coals. The Jurassic-Tertiary Reservoirs AU has Jurassic and Tertiary fluvial and nearshore lacustrine sandstone reservoirs. The main source rocks are also Jurassic coals and Permian lacustrine rocks. Traps for both AUs are mostly anticlines and fault blocks.

The Bohaiwan Basin was assessed as a single AU: the Tertiary Lacustrine and Buried Hills AU. Tertiary reservoir rocks are mostly fluvial, lacustrine deltaic, and lacustrine turbiditic sandstones. The reservoirs in the buried hills include fractured Archean crystalline basement rocks, karsted Proterozoic limestones and dolomites, Cambrian and Ordovician limestones, and Mesozoic volcanics. Source rocks are deep-water lacustrine shales and mudstones, most importantly those in the Eocene Shahejie Formation. The traps include structural and stratigraphic traps for the Tertiary reservoirs, as well as classic examples of buried hills.

The Ordos Basin was divided into two conventional AUs. The Ordovician Gas AU has gas fields producing from carbonates of the Ordovician Majiagou Formation that have significant karst development beneath a regional unconformity. Source rocks are primarily Upper Carboniferous and Permian coals and shales, but there may be some contribution from Ordovician carbonate sources. The Triassic-Jurassic Fluvial and Lacustrine Sandstones AU has reservoirs in Triassic and Jurassic fluvial and deltaic sandstones. The main source rock is lacustrine mudstones of the Triassic Yanchang Formation. Traps are mostly stratigraphic.

The Sichuan Basin was divided geographically into three AUs: one for gas fields in the heavily folded southeastern part of the basin (Southeastern Fold Belt AU), one for gas fields in the northwestern depression and foldbelt (Northwestern Depression and Foldbelt AU), and one for oil and gas fields in the central uplift (Central Uplift AU). Most of the fields are gas fields, with reservoirs ranging in age from Proterozoic to Jurassic. Most of the oil fields have Jurassic reservoirs. Reservoir rocks include Proterozoic and Carboniferous through Triassic carbonates, as well as Triassic and Jurassic sandstones. Source rocks are shales ranging from Cambrian to Jurassic in age. Traps include anticlines and buried hills.

The Songliao Basin was divided into four AUs. Oil and gas fields of the Stratigraphic Traps AU have Upper Cretaceous fluvial and deltaic sandstone reservoirs in stratigraphic traps, primarily sourced from Lower Cretaceous lacustrine rocks. The Anticlinal AU has similar reservoir and source rocks, but the traps are primarily structural and are located on the major anticlines in the center of the basin. The Kailu Depression AU, in the southwestern part of the basin, also has similar reservoir and source rocks; it contains both structural and stratigraphic traps. The Structural Traps AU has older sandstone reservoirs that are below the Cretaceous Qingshankou Formation and are sourced by the Jurassic coal beds. The Structural Traps AU has both structural and stratigraphic traps.

The Tarim Basin was assessed as a single AU: the Conventional Reservoirs AU. Reservoirs are mainly Jurassic and Miocene fluvial and lacustrine sandstones, along with some clastic and carbonate reservoirs of Ordovician and Carboniferous ages. Source rocks are primarily the Jurassic lacustrine shales and coals, but there may be some contribution from Ordovician marine rocks and Carboniferous coals. Traps are mostly anticlines and fault blocks.

Using a geology-based assessment methodology, the U.S. Geological Survey estimated
mean volumes of undiscovered conventional petroleum resources in six geologic provinces
of China at 14.9 billion barrels of oil, 87.6 trillion cubic feet of natural gas, and 1.4 billion
barrels of natural-gas liquids.

— — — —
Ресурсы
нефть
средние 14,945 million barrels of oil (MMBO) = 2 млрд.т
интервальные 6,980-26,526 = 0.95-3.6 млрд.т

газ
средние 87,602 billion cubic feet of gas (BCFG) = 2.45 трлн. м3
интервальные 35,553-167,555 = 1.0 — 4.7 трлн. м3

NGL при пересчете из баррелей в т.н.э как для нефти (самый лучший случай)
средние 1,419 million barrels = 0.194 млрд.т
интервальные 490-2,997 = 0.0668-0.4 млрд.т

— — — —
BP Statistical Review of World Energy June 2012
Oil: Proved reserves, Thousand million barrels, 1980-2011

После выхода на международную арены прыжки резкие изменения запасов прекратились и стабилизировались на уровне 14.8-14.7 Thousand million barrels
(2001) 14.7 Thousand million barrels = 2.00508 млрд.т
Неоткрытые ресурсы нефти = открытым запасам.
Если учесть, что оценен не весь Китай в Usgs assessment, то в лучшем случаем величину неоткрытых ресурсов нефти можно удвоить.

Годовая добыча в 2011 г. = 203.6 млн.т.
R/P ratio = 9.9. лет
На примере Китая можно изучать в реальном времени пик нефти

Natural Gas (2011)
Proved reserves = 3.1 Trillion cubic metres
Natural Gas Production = 102.5 млрд. м3
R/P ratio = 29.8 лет

Usgs assessment: Taranaki Basin Assessment Unit, New Zealand, 2013

Assessment of Undiscovered Oil and Gas Resources of the Cretaceous-Tertiary Composite Total Petroleum System, Taranaki Basin Assessment Unit, New Zealand

USGS recently completed an assessment of the conventional undiscovered resources of the Cretaceous-Tertiary Composite Total Petroleum System (TPS), Taranaki Basin Assessment Unit (AU), onshore and offshore New Zealand (fig. 1).

The Cretaceous-Tertiary Composite TPS and Taranaki Basin AU include an area of approximately 153,000 square kilometers (km2). The TPS and AU boundaries are coincident and will be referred to as the AU. The offshore portion of the AU makes up approximately 80 percent of the total area. Water depths range from 0 to 1,500 meters. The AU includes Cretaceous and Tertiary rocks in all or part of the Taranaki, Wanganui, and Deep-Water Taranaki Basins (fig. 1).

Situated on the Australian tectonic plate, the AU consists of an onshore and offshore eastern graben complex and an offshore western stable platform. The graben complex and stable platform developed during Jurassic and Late Cretaceous–Paleogene rifting events between Australia and New Zealand that created a rift sag basin and the Tasman Sea. The Late Cretaceous–Paleogene rifting was followed, from 35 to 24 million years ago (Ma), by a relatively continuous period of regional compression and initiation of subduction of the Pacific plate. Collision of the Australian and Pacific plates resulted in the Australian plate overriding the Pacific plate on North Island and the Pacific plate overriding the Australian plate on South Island creating a plate inversion zone between the North and South Islands. The southernmost portion of the AU, between the North and South Islands, is part of the plate inversion zone. Back-arc extension related to subduction started approximately 4 Ma and continues today.

The source rocks include Cretaceous and Paleogene marine and lacustrine shales and mudstones and Cretaceous and possibly Jurassic coals. Oil and gas generation occurred as early as Late Cretaceous in the deep-water part of the AU (Deep-Water Taranaki Basin) (Uruski and Warburton, 2010). Due to a varied
burial history, generation has continued intermittently in different parts of the AU throughout the Cenozoic and is ongoing today in parts of the AU. The Taranaki Basin is filled with as much as 9 km of sediments. Maximum burial depth occurred during late Miocene in much of the basin. Migration is primarily along fault zones and into adjacent reservoirs.

Cretaceous and Tertiary reservoir rocks and potential reservoir rocks include turbidites, carbonates, alluvial sandstones, and volcaniclastics. Traps are primarily structural. Collisionrelated late Tertiary tectonics created three primary structural trap types—faulted anticlines, overthrusts, and tilted fault blocks (Crown Minerals, 2011). Seals are primarily shales and mudstones. Production is mainly from sandstones of the Eocene Kapuni Group and Oligocene Otaraoa Formation. There are eight discovered oil accumulations and twelve gas accumulations with a grown size (maximum expected volume of production) greater than the 5 million barrels of oil equivalent minimum assessed size (IHS Energy, 2010). Two fields, Kapuni and Maui, presently account for over 80 percent of New Zealand’s gas production and condensate (Crown Minerals, 2011). The Kapuni and Maui fields formed in faulted anticline traps.

USGS estimated mean volumes of 487 million barrels of oil, 9.8 trillion cubic feet of gas, and 408 million barrels of natural gas liquids.
— — — —

487 million barrels of oil = 66.4 млн т. нефти
9.8 trillion cubic feet of gas = 274.4 млрд. м3

— — — —
BP Statistical Review of World Energy June 2012

Нет своей добычи нефти и газа

2011
Oil: Consumption = 6.9 млн.т
Natural Gas: Consumption = 3.9 млрд. м3

Максимум
Oil: Consumption (2007-2008)= 7.2 млн.т
Natural Gas: Consumption (2001) = 5.9 млрд. м3

Usgs Assessment: Undiscovered Conventional Oil and Gas Resources of North Africa, 2012

Using a geology-based assessment methodology, the U.S. Geological Survey estimated means of 19 billion barrels of technically recoverable undiscovered conventional oil and 370 trillion cubic feet of undiscovered conventional natural gas resources in 8 geologic provinces of North Africa.

Eight priority geologic provinces were assessed in this study, which represents a reassessment of North Africa last published in 2000 (U.S. Geological Survey World Energy Assessment Team, 2000). The eight geologic provinces include (1) Nile Delta Basin; (2) Sirte Basin; (3) Pelagian Basin; (4) Trias/Ghadames Basin; (5) Hamra Basin; (6) Illizi Basin; (7) Grand Erg/Ahnet Basin; and (8) Essaouira Basin (fig. 1). Resource estimates for the Nile Delta, Sirte, and Pelagian Basin provinces were published previously (Kirschbaum and others, 2010; Whidden and others, 2011), but are included here for a more complete view of undiscovered conventional oil and gas resources across North Africa.

The USGS assessed undiscovered conventional oil and gas resources in 18 AUs within eight geologic provinces, with the following estimated mean totals: (1) for conventional oil resources, 18,618 million barrels of oil (MMBO), with a range from 6,846 to 37,460 MMBO; (2) for undiscovered conventional
gas, 370,375 billion cubic feet of gas (BCFG), with a range from 149,541 to 712,430 BCFG; and (3) for natural gas liquids (NGL), 12,553 MMBNGL, with a range from 4,809 to 24,785 MMBNGL.

Of the mean undiscovered conventional oil resource of 18,618 MMBO, about 41 percent (7,557 MMBO) is estimated to be in the Offshore Salt Structures AU, offshore Morocco. Other significant AUs for potential undiscovered oil include the Offshore Sirte Basin AU (2,267 MMBO), Onshore Sirte Carbonate-Clastic AU (1,278 MMBO), and the Berkine Paleozoic and Mesozoic Reservoirs AU (1,839 MMBO) of the Trias/Ghadames Basin. Of the mean undiscovered gas resource of 370,375 BCFG, about 59 percent (217,313 BCFG) is estimated to be in the Nile Cone AU. Other significant AUs for potential undiscovered gas resources include the Offshore Salt Structures AU of Morocco (45,208 BCFG), the Offshore Sirte Basin AU
(22,637 BCFG), and the Gourara Paleozoic Reservoirs AU (15,559 BCFG) of the Grand Erg/Ahnet Basin Province. These four AUs encompass about 81 percent of the undiscovered gas resource.

http://pubs.usgs.gov/fs/2012/3147/
http://pubs.usgs.gov/fs/2012/3147/FS12-3147.pdf

— — — — —
Нефть
18,618 million barrels of oil = 2.54 млрл. т
range from 6,846 to 37,460 MMBO = 0.93-5.1 млрл. т
Наибольшие запасы нефти прогнозируют в Essaouira Basin Province, Paleozoic-Mesozoic Composite TPS (шельф Марокко)

Газ
370,375 billion cubic feet of gas (BCFG) = 10.4 трлн. куб.м
range from 149,541 to 712,430 BCFG = 4.2-19.9 трлн. куб.м
По средней оценке 2/3 ресурсов газа в дельте Нила

Usgs, Eia: Оценки запасов нефти и газа Арктики

Usgs assessment: Circum-Arctic Resource Appraisal

eia.gov: Forecasts & Analysis > Natural Gas Analysis Reports

eia.gov: Forecasts & Analyses > Natural Gas Analysis Reports > Arctic Oil and Natural Gas Potential, 2009

The Arctic is defined as the Northern hemisphere region located north of the Arctic Circle.
The Arctic could hold about 22 percent of the world’s undiscovered conventional oil and natural gas resources.

Discovered Arctic Oil and Natural Gas Resources
The best place to find oil and natural gas is where oil and natural gas have already been found.

Large Arctic oil and natural gas discoveries began in Russia with the discovery of the Tazovskoye Field in 1962 and in the United States with the Alaskan Prudhoe Bay Field in 1967. Approximately 61 large oil and natural gas fields have been discovered within the Arctic Circle in Russia, Alaska, Canada’s Northwest Territories, and Norway. Fifteen of these 61 large Arctic fields have not yet gone into production; 11 are in Canada’s Northwest Territories, 2 in Russia, and 2 in Arctic Alaska.

Forty-three of the 61 large Arctic fields are located in Russia. Thirty-five of these large Russian fields (33 natural gas and 2 oil) are located in the West Siberian Basin. Of the eight remaining large Russian fields, five are in the Timan-Pechora Basin, two are in the South Barents Basin, and one is in the Ludlov Saddle.

Of the 18 large Arctic fields outside Russia, 6 are in Alaska, 11 are in Canada’s Northwest Territories, and 1 is in Norway.

Arctic Undiscovered Technically Recoverable, Conventional Oil and Natural Gas Resources

The USGS Arctic assessment estimated a total oil and natural gas resource of 412 billion barrels of oil equivalent, with 78 percent of those resources expected to be natural gas and natural gas liquids (NGL). The composition of undiscovered Arctic hydrocarbons is largely determined by the West Siberian Basin and East Barents Basin, which hold 47 percent of the undiscovered Arctic resources, with 94 percent of those resources being natural gas and NGL.

According to the USGS mean estimate, the Arctic holds about 22 percent of the world’s undiscovered conventional oil and natural gas resource base, about 30 percent of the world’s undiscovered natural gas resources, about 13 percent of the world’s undiscovered oil resources, and about 20 percent of the world NGL resources

Сингапур намерен войти в Арктический совет в качестве наблюдателя

Сингапур намерен войти в состав Арктического совета в качестве страны-наблюдателя. Об этом в рамках конференции Arctic Frontiers в норвежском городе Тромсе сообщил Карл Бильдт — министр иностранных дел Швеции, председательствующей в совете.

Также в качестве стран-наблюдателей в состав совета хотят вступить Китай и Индия, которые имеют интересы в Арктике.

Как пояснил К.Бильдт, названные страны хотят участвовать в дискуссиях о ситуации в Арктике. В настоящее время обсуждается, в какой форме могли бы проходить подобные обсуждения. Глава МИД Швеции также отметил, что интерес Сингапура к Арктике связан с активным участием этой страны в судоходстве, в том числе по Северному морскому пути из Европы в Азию.

В настоящее время в состав Арктического совета входят восемь государств: США, Канада, Норвегия, Швеция, Россия, Дания, Финляндия и Исландия. Еще несколько стран являются наблюдателями.

Совет был создан по инициативе Финляндии в 1996г. для защиты окружающей среды и развития Арктики. В 2013г. председательствовать в нем будет Канада.
http://www.rbc.ru/rbcfreenews/20130121155012.shtml

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Сингапур, население в 4,987 миллиона в 2009 году (4,42 миллиона в 2005 году), большинство населения составляют китайцы — 76,8 %.

Большой Китай (2003)— надгосударственное образование или своеобразная транснациональная корпорация, включающая кроме континентального Китая, Гонконг (Сянган), Тайвань, Сингапур и обширную китайскую диаспору (300 млн. хуацяо) с населением более 1,5 миллиардов человек. Желтый китайский сверхмиллиард противостоит «золотому миллиарду» Запада. Суммарный валовой внутренний продукт Большого Китая сопоставим с американским ВВП. Свободные валютные средства банков, контролируемых китайцами, оцениваются в 400 млрд. долл. Традиционно континентальный Китай считает представителей диаспоры гражданами своей страны.

— — — — — —
Usgs assessment: An Estimate of Undiscovered Conventional Oil and Gas Resources of the World, 2012

Arctic Oil and Gas Ultimates (2011)

Арктика: карты запасов УВ (2010)

Арктика и окрестности, оценка 2008, таблицы Oil and Natural Gas Potential

Usgs assessment: Central Burma Basin and the Irrawaddy–Andaman and Indo-Burman Geologic Provinces

Assessment of Undiscovered Oil and Gas Resources of the Central Burma Basin and the Irrawaddy–Andaman and Indo-Burman Geologic Provinces, Myanmar

The Irrawaddy–Andaman and Indo-Burman Geologic Provinces were recently assessed for undiscovered technically recoverable oil, natural gas, and natural gas liquids resources as part of the U.S. Geological Survey’s (USGS) World Oil and Gas Assessment. Using a geology-based assessment methodology, the USGS estimated mean volumes of 2.3 billion barrels of oil, 79.6 trillion cubic feet of gas, and 2.1 billion barrels of natural gas liquids.

Introduction
The U.S. Geological Survey (USGS) World Petroleum Resources Project assesses the potential for undiscovered, technically recoverable oil and natural gas resources of the world, exclusive of the United States. As a part of this program, the USGS recently completed an assessment of the onshore and offshore areas of the Central Burma Basin and the Irrawaddy–Andaman and Indo-Burman Geologic Provinces (fig. 1). This assessment was based on data from oil and gas exploration and production wells, production data, and published geologic reports. Only conventional oil and gas resources were assessed.

Central Burma Basin Assessment Unit
The Central Burma Basin assessment unit (AU) encompasses an area of 242,000 km2 in the Central Burma Basin and includes source, reservoir, and seal rocks predominately of Eocene to Miocene age, although Upper Cretaceous and Paleocene source rocks also may contribute to the AU. The basin is an Eocene back arc basin formed by oblique collision of oceanic and continental plates and filled with sediments of a restricted marine environment overlain by sediments of a southward-prograding delta and alluvial system. Compression and folding developed anticlines and faulted anticlines intermittently from Oligocene to present (U.S. Geological Survey

World Energy Assessment Team, 2000). Traps are primarily anticlines and stratigraphic traps including pinchouts. Eleven oil and nine gas fields greater than the minimum assessed size of 5 million barrels of oil equivalent (MMBOE) (grown or maximum expected recovery) have been discovered in the Central Burma Basin AU (IHS Energy, 2010).

Irrawaddy–Andaman Assessment Unit
The Irrawaddy–Andaman AU includes an area of 226,000 km2 and includes source, reservoir, and seal rocks primarily of Eocene to Miocene age. It is the southward extension of the Central Burma Basin with a similar geologic setting and tectonic history; however, the effects of compression caused by plate collision are less evident, whereas the oblique or strike-slip component becomes more dominant. The features distinguishing the Irrawaddy–Andaman AU from the Central Burma Basin AU are that the source and reservoir rocks were deposited in a predominately deltaic and marine environment, and source rocks are more gas prone. Source rock burial depths become greater to the south, and cracking of oil to gas because of greater depths of burial may contribute to this AU being more gas prone. Traps are primarily anticlines, alluvial channels, deltaic features, and carbonate reefs and pinnacles (Wandrey, 2006). Twenty-two gas fields greater than the minimum assessed size of 5 MMBOE (grown) have been discovered (IHS Energy, 2010).

Cenozoic Assessment Unit
The Cenozoic AU encompasses an area of 71,000 km2 and includes source, reservoir, and seal rocks primarily of Eocene to Pliocene age. The AU includes the Rahkine Basin and occupies the eastern abyssal plain of the Bay of Bengal and part of the accretionary wedge created by oblique subduction of the Indian Plate beneath the Burmese Plate. Source rocks are postulated to be middle to late Eocene shales. Reservoirs are Oligocene-Miocene thick sheet sandstones and turbidites sourced by the Bengal fan, Miocene-Pliocene turbidites, and aggraded lower-slope channel sandstones sourced by the younger Rahkine-Yoma fan. Three gas fields greater than the minimum assessed size of 5 MMBOE (grown) have been discovered (IHS Energy, 2010).

Resource Summary
The USGS geology-based assessment of the undiscovered technically recoverable oil, natural gas, and natural gas liquids resources in the Central Burma Basin and the Irrawaddy–Andaman and Indo-Burman Geologic Provinces resulted in estimated undiscovered mean volumes of 2.3 billion barrels of oil, 79.6 trillion cubic feet of gas, and 2.1 billion barrels of natrual gas liquids.
http://pubs.usgs.gov/fs/2012/3107/
http://pubs.usgs.gov/fs/2012/3107/FS12-3107.pdf

— — — — — —
2.3 billion barrels of oil * 0.1364 = 314 млн.т
79.6 trillion cubic feet of gas * 0.028 = 2.2 трлн. м3
Ресурсы нефти и газ при 95% вероятности почти в раза ниже, чем при средней.

Usgs assessment: Undiscovered Oil and Gas Resources of Four East Africa Geologic Provinces

Four geologic provinces along the east coast of Africa recently were assessed for undiscovered, technically recoverable oil, natural gas, and natural gas liquids resources as part of the U.S. Geological Survey’s (USGS) World Oil and Gas Assessment. Using a geology-based assessment methodology, the USGS estimated mean volumes of 27.6 billion barrels of oil, 441.1 trillion cubic feet of natural gas, and 13.77 billion barrels of natural gas liquids.

Introduction
The main objective of the U.S. Geological Survey’s (USGS) World Petroleum Resources Project is to assess the potential for undiscovered, technically recoverable oil and natural gas resources of the world, exclusive of the United States. As part of this program, the USGS recently completed an assessment of four geologic provinces: three along the eastern part of the African coast and one more than 900 miles east of the African coast and extending to water depths ranging from 2,000−3,000 meters (m) (fig. 1). From north to south,

the provinces are as follows:
(1) the Tanzania Coastal, containing rift, marginal sag, and passive margin rocks of Middle Jurassic to Holocene age;
(2) Seychelles, characterized by rift, marginal sag, and drift rocks;
(3) the Morondava, containing failed rift, marginal sag, and passive margin rocks; and
(4) the Mozambique Coastal, described by rift, marginal sag, and passive margin rocks.
These assessments were based on data from oil and gas exploration wells and published geologic reports. The four provinces were related to the breakup of Gondwana (fig. 2) in the late Paleozoic and Mesozoic (Reeves and others, 2002), and developed similarly through two tectonic phases (fig. 3): (1) a syn-rift phase that was started during the Permo–Triassic and continued

into the Jurassic, resulting in the formation of grabens and half-grabens and (2) a drift phase that began in the mid-Jurassic and continued into the Paleogene. A later passive margin phase began in the late Paleogene and continues to the present in the Morondava, Mozambique, and Tanzania Coastal Provinces, whereas in the Seychelles Province the drift phase continues to the present because there is no significant sediment source after the Seychelles-India breakup. The total thickness of the Mesozoic to Cenozoic stratigraphic section is more than 5,000 m on the outer parts of the continental shelf along the east Africa coast in the Morondava and Mozambique Coastal Provinces and more than 4,000 m in the Seychelles Province.

The four provinces and associated assessment units (AU) were assessed for the first time because of increased exploratory activity, recent discoveries, and increased interest in their future potential. The assessment was geology based and used the total petroleum system (TPS) concept. The geologic elements of a TPS include hydrocarbon source rocks (source rock maturation and hydrocarbon generation and migration), reservoir rocks (quality and distribution), and traps for hydrocarbon accumulation.

Using these geologic criteria, the USGS defined four TPSs and one AU for each TPS (table 1). The TPSs were defined to include Mesozoic to Paleocene source rocks and conventional reservoirs (fig. 3). The Permian to Triassic contains fluvial and lacustrine source rocks, and the Jurassic contains restricted marine Type II kerogen source rocks and marginal marine and deltaic Types II and III kerogen source rocks. Types II and III kerogen source rocks of Cretaceous age have been identified in the Morondava, Mozambique, Seychelles, and Tanzania Provinces, and Types II and III kerogen source rocks of Paleogene age have been identified in Mozambique, Seychelles, and Tanzania Provinces. Permian to Triassic source rocks contain 1.0 to 6.7 weight percent total organic carbon (TOC), with some samples having as much as 17.4 percent. The Early to Middle Jurassic restricted marine Type II source rocks contain as much as 12 weight percent TOC. Upper Jurassic and Cretaceous marine strata include (1) Aptian source containing Type II kerogen, ranging from 2.0 to 4.28 weight percent TOC; and (2) Cenomanian–Turonian source rocks containing Type II kerogen, ranging from 1.0 to 3.0 weight percent TOC. All four AUs contain Mesozoic and Cenozoic clastic reservoirs. Traps are mostly structural within the syn-rift rock units and both structural and stratigraphic in the postrift-rock units. The east African provinces (Mozambique, Morondava, and Tanzania, fig. 1) contain reservoirs that mostly are associated with growth-fault-related structures, rotated fault blocks within the continental shelf, deep water fans, turbidite channels and sandstones, slope truncations along the present-day shelf and paleoshelf edge. Permian to Triassic sandstone and Late Jurassic reefs and platform limestone also are possible reservoirs. The primary seals are Mesozoic and Cenozoic mudstones and shales. The Seychelles Province contains possible reservoirs in Permian to Middle Jurassic rift-related sandstones, Middle Jurassic carbonates, Lower and Upper Cretaceous turbidite sandstones, and Tertiary carbonates. The primary seals are intraformational shales.

At the time of the assessment, the four east African provinces contained 1 oil and 11 gas accumulations (HIS Energy, 2009), thus exceeding the minimum size of 5 million barrels of oil equivalent and 30 billion cubic feet of gas; these provinces are considered to be underexplored for their size. The Seychelles Province contained no discoveries and was also underexplored.

Exploration wells and discovered accumulations on the continental shelf and upper slope (IHS Energy, 2009) provide evidence for (1) the existence of an active petroleum system containing Mesozoic source rocks, (2) the migration of the hydrocarbons most likely since the Late Cretaceous, and (3) the migration of the hydrocarbons into Cretaceous and Cenozoic reservoirs.

Resource Summary
The results of the USGS assessment of undiscovered, technically recoverable conventional oil and gas resources in the east Africa provinces are listed in table 1.
The mean volumes are estimated at (1) 10,750 million barrels of oil (MMBO), 167,219 billion cubic feet of gas (BCFG), and 5,176 million barrels of natural gas liquids (MMBNGL) for the Mesozoic-Cenozoic Reservoirs AU in the Morondava Province; (2) 11,682 MMBO, 182,349 BCFG, and 5,645 MMBNGL for the Mesozoic-Cenozoic Reservoirs AU in the Mozambique Coastal Province; (3) 2,394 MMBO, 20,376 BCFG, and 739 MMBNGL for the Seychelles Rifts AU in the Seychelles Province; and (4) 2,806 MMBO, 71,107 BCFG, and 2,212 MMBNGL for the Mesozoic-Cenozoic Reservoirs AU in the Tanzania Coastal Province.
For this assessment, a minimum undiscovered field size of 5 million barrels of oil equivalent (MMBOE) was used. No attempt was made to estimate economically recoverable reserves.

http://pubs.usgs.gov/fs/2012/3039/
http://pubs.usgs.gov/fs/2012/3039/contents/FS12-3039.pdf

— — — — — — —
27.6 billion barrels of oil = 3.76 млрд. т. (геол. запасы); *0.3 (КИН) = 1.25 млрд. т. (извлекаемые запасы);
441.1 trillion cubic feet of natural gas = 12.348 трлн. куб. м. (геол. запасы);

Usgs assessment: An Estimate of Undiscovered Conventional Oil and Gas Resources of the World, 2012

Introduction
The authors of this report summarize a geology-based assessment of undiscovered conventional oil and gas resources of priority geologic provinces of the world, completed between 2009 and 2011 as part of the U.S. Geological Survey (USGS) World Petroleum Resources Project (fig. 1). One hundred seventy-one geologic provinces were assessed in this study (exclusive of provinces of the United States), which represent a complete reassessment of the world since the last report was published in 2000 (U.S. Geological Survey World Energy Assessment Team, 2000). The present report includes the recent oil and gas assessment of geologic provinces north of
the Arctic Circle (U.S. Geological Survey Circum-Arctic Resource Appraisal Assessment Team, 2008). However, not all potential oil- and gas-bearing provinces of the world were assessed in the present study.

The methodology for the assessment included a complete geologic framework description for each province based mainly on published literature, and the definition of petroleum systems and assessment units (AU) within these systems. In this study, 313 AUs were defined and assessed for undiscovered oil and gas accumulations. Exploration and discovery history was a critical part of the methodology to determine sizes and numbers of undiscovered accumulations. In those AUs with few or no discoveries, geologic and production analogs were used as a partial guide to estimate sizes and numbers of undiscovered oil and gas accumulations, using a database developed by the USGS following the 2000 assessment (Charpentier and others, 2008). Each AU was assessed for undiscovered oil and nonassociated gas accumulations, and co-product ratios were used to calculate the volumes of associated gas (gas in oil fields) and volumes of natural gas liquids. This assessment is for conventional oil and gas resources only; unconventional resource assessments (heavy oil, tar sands, shale gas, shale oil, tight gas, coalbed gas) for priority areas of the world are being completed in an ongoing but separate USGS study.

Resource Summary
The USGS assessed undiscovered conventional oil and gas resources in 313 AUs within 171 geologic provinces. In this report the results are presented by geographic region, which correspond to the eight regions used by the U.S. Geological Survey World Energy Assessment Team (2000) (table 1). For undiscovered, technically recoverable resources, the mean totals for the world are as follows:
(1) 565,298 million barrels of oil (MMBO);
(2) 5,605,626 billion cubic feet of gas (BCFG);
and (3) 166,668 million barrels (MMBNGL) of natural gas liquids.

The ranges of resource estimates (between the 95 and 5 fractiles) reflect the geologic uncertainty in the assessment process (table 1). The assessment results indicate that about 75 percent of the undiscovered conventional oil of the world is in four regions:
(1) South America and Caribbean,
(2) sub-Saharan Africa,
(3) Middle East and North Africa, and
(4) the Arctic provinces portion of North America.

Significant undiscovered conventional gas resources remain in all of the world’s regions (table 1).

Regions 0 and 1 (29 assessed provinces) encompass geologic provinces within countries of the former Soviet Union and include many provinces of the Arctic (fig. 1). Of the mean undiscovered estimate of 66 billion barrels of oil (BBO) in this region, about 43 percent
is estimated to be in Arctic provinces. This region also contains significant gas resources [mean of 1,623 trillion cubic feet of gas (TCFG)], about 58 percent of which is estimated to be in three Arctic AUs: South Kara Sea AU (622 TCFG); South Barents Basin AU (187 TCFG), and North Barents Basin AU (127 TCFG).

Region 2 (26 assessed provinces), the Middle East and North Africa, includes the Zagros Fold Belt of Iran, Arabian Peninsula, southern Turkey, and geologic provinces of North Africa from Egypt to Morocco. This region is estimated to contain a mean of 111 BBO, about 60 percent (65 BBO) of which is estimated to be in the Zagros and Mesopotamian provinces. This region is estimated to contain a conventional gas resource mean of 941 TCFG, about 60 percent (566 TCFG)
of which is estimated to be in the Zagros Fold Belt and the offshore areas of the Red Sea Basin, Levantine Basin, and Nile Delta provinces.

Region 3 (39 assessed provinces), Asia and Pacific, includes geologic provinces of China, Vietnam, Thailand, Malaysia, Cambodia, Philippines, Brunei, Indonesia, Papua New Guinea, East Timor, Australia, and New Zealand. Of the total mean undiscovered oil resources of 48 BBO, about 33 percent is estimated to be in China provinces (15.7 BBO), and 10 percent is in Australian provinces (5 BBO). Other significant oil resources are in offshore Brunei (3.6 BBO), Kutei Basin (3 BBO), and South China Sea (2.5 BBO) provinces. Of the undiscovered mean total of 738 TCFG, about 45 percent (335 TCFG) is in provinces of Australia (227 TCFG) and China (108 TCFG). The rest of the gas resource is distributed across the other provinces of Southeast Asia.

Region 4 (6 assessed provinces) includes Europe and several Arctic provinces. Of the mean of 9.9 BBO of undiscovered oil, about 50 percent (5 BBO) is estimated to be in the North Sea province. Of the undiscovered gas resource of 149 TCFG, the Arctic provinces are estimated to contain about 40 percent (58 TCFG). Significant undiscovered gas resources are estimated to be in the Norwegian continental margin, Provencal Basin, and Po Basin provinces.

Region 5 (21 assessed provinces), North America exclusive of the United States, includes Mexico, Canada, and several Arctic provinces. Of the mean oil resource of 83 BBO, about 75 percent (61 BBO) is estimated to be in Arctic provinces, and 23 percent (19 BBO) is estimated to be in Mexican Gulf provinces. In this region about 83 percent (459 TCFG) of the undiscovered conventional gas is in the Arctic provinces.

Region 6 (31 assessed provinces) includes South America and the Caribbean area. Of the mean estimate of 126 BBO in this region, about 44 percent (55.6 BBO) is estimated to be in offshore subsalt reservoirs in the Santos, Campos, and Espirito Santo basin provinces. Other significant mean oil resources are estimated to be in the Guyana−Suriname Basin (12 BBO), Santos Basin (11 BBO), Falklands (5.3 BBO), and Campos Basin (3.7 BBO) provinces. Undiscovered gas resources are less concentrated and are distributed among many provinces.

Region 7 (13 assessed provinces), sub-Saharan Africa, is estimated to contain a mean 115 BBO, of which about 75 percent is estimated to be in coastal provinces related to the opening of the Atlantic Ocean, such as Senegal, Gulf of Guinea, West African Coastal, and West-Central Coastal provinces. Of the undiscovered gas resource mean of 744 TCFG, more than half is estimated to be in provinces of offshore east Africa, including those offshore Tanzania, Mozambique, Madagascar, and Seychelles.

Region 8 (6 assessed provinces), South Asia, includes India, Pakistan, Afghanistan, Bangladesh, and Burma. Of the mean of 5.9 BBO, about 1.8 BBO is estimated to be in the Central Burma Basin province and 1.4 BBO is in the Bombay province. Of the undiscovered gas resource of 159 TCFG, about 39 percent (62 TCFG) of the undiscovered gas resource is in the three provinces of offshore eastern India. Although unconventional oil and gas resources, such as heavy oil, tar sands, shale gas, shale oil, tight gas, and coalbed gas, are not included in this study, unconventional resource volumes can be truly significant. For example, the mean estimate for recoverable heavy oil from the Orinoco Oil Belt in Venezuela alone is 513 BBO (U.S. Geological Survey Orinoco Oil Belt Assessment Team, 2009), compared to mean conventional resources of 565 BBO for 171 provinces reported in this study.

http://energy.usgs.gov/Miscellaneous/Articles/tabid/98/ID/160/An-Estimate-of-Undiscovered-Conventional-Oil-and-Gas-Resources-of-the-World-2012.aspx
http://pubs.usgs.gov/fs/2012/3042/
http://pubs.usgs.gov/fs/2012/3042/fs2012-3042.pdf

USGS World Petroleum Assessment 2000

Usgs assessment: Potential Shale Gas Resources of the Bombay, Cauvery, and Krishna–Godavari Province

2011

Resource Summary
The results of the USGS assessment of potential shale gas resources in the Bombay, Cauvery, and Krishna–Godavari Provinces of India are listed in table 2. In summary, the estimated mean volumes of technically recoverable petroleum resources are as follows: (1) for the Cambay Shale Gas South Assessment Unit (AU) of the Bombay Province—924 billion cubic feet of gas (BCFG; range, 383 to 1,966 BCFG) and 31 million barrels of natural gas liquids (MMBNGL; range, 12 to 69 MMBNGL); (2) for the Sattapadi-Andimadam Shale Gas AU in the Cauvery Province—1,123 BCFG (range, 444 to 2,660 BCFG) and 39 MMBNGL (range, 14 to 95 MMBNGL); and (3) for the Raghavapuram Shale Gas AU of the Krishna–Godavari Province—4,080 BCFG (range, 1,406 to 9,133 BCFG) and 90 MMBNGL (range, 28 to 207 MMBNGL). The ranges of resource estimates for shale gas reflect the considerable geologic uncertainty in these assessment units.

http://pubs.usgs.gov/fs/2011/3131/
http://pubs.usgs.gov/fs/2011/3131/pdf/fs2011-3131.pdf

Assessment of Undiscovered Oil and Gas Resources of the Sud Province, North-Central Africa, 2011

The Sud Province located in north-central Africa recently was assessed for undiscovered, technically recoverable oil, natural
gas, and natural gas liquids resources as part of the U.S. Geological Survey’s (USGS) World Oil and Gas Assessment. Using
a geology-based assessment methodology, the USGS estimated mean volumes of 7.31 billion barrels of oil, 13.42 trillion
cubic feet of natural gas, and 353 million barrels of natural gas liquids.

Introduction
The main objective of the U.S. Geological Survey’s (USGS) World Petroleum Resources Project is to assess the potential for undiscovered, technically recoverable oil and natural gas resources of the world, exclusive of the United States. As part of this program, the USGS recently completed an assessment of the Sud Province (fig. 1), an area of approximately 978,800 square

kilometers (km2) that covers parts of the Central African Republic, Chad, Ethiopia, Camaroon, and Sudan. This assessment was based on data from oil and gas wells and fields, field production records, and published geologic reports. At the time of the assessment, the province contained 113 oil fields—18 in Chad and 95 in Sudan—and was considered to be underexplored for its size. There was one gas field in the province but several discoveries reported associated gas in oil fields. The producing oil fields and recent petroleum discoveries were limited to the Cretaceous-Tertiary rift basins.

The Sud Province was assessed for the first time because of increased exploratory activity and interest in its future potential for
energy resources. The assessment was geology-based and used the total petroleum system (TPS) concept. The geologic elements of a TPS include hydrocarbon source rocks (source rock maturation and hydrocarbon generation and migration), reservoir rocks (quality and distribution), and traps for hydrocarbon accumulation. Using these geologic criteria, the USGS defined the Cretaceous-Cenozoic Composite Total Petroleum System (TPS) with one assessment unit (AU), the Central African Rifts AU (fig. 1), encompassing about 848,825 km2, that extends beyond the Sud Province boundary. The AU includes parts of the Central African Republic, Chad, Ethiopia, Kenya, Sudan, and Tanzania (fig. 1). The TPS was defined to include Cretaceous and Paleogene lacustrine and marine source rocks and the AU contains Cretaceous and Paleogene clastic reservoirs, shale seals, and traps that mostly are associated structurally with extensional and transtensional faulting and minor compressional inversion.

The Central African Rift system was initiated during the Early Cretaceous, during the opening of the south Atlantic and the commencement of regional northwest-southeast extension. The rifting continued into the Neogene and can be divided into two rifting events in the western part and three rifting events in the eastern part. The rift basins of central Africa are linked along the Central African shear zone (CASZ) right-lateral fault system (fig. 1). Several thousand meters of Lower Cretaceous clastic sediments, mostly lacustrine clays, silts, and sands, were deposited during this rifting phase.

The Cretaceous-Tertiary rift basins of the western part of the Sud Province (fig. 1) are extensional and transtensional and are filled with Lower Cretaceous to Neogene sedimentary rocks, ranging in thickness from about 3,000 meters (m) to more than 7,500 m (fig. 2) that were deposited in fluvial and lacustrine environments. During the Early Cretaceous, the first rifting phase occurred and fluvial and lacustrine sediments were deposited in the rift basins of southern Chad and the Central African Republic (fig. 2). In the Late Cretaceous (Cenomanian to Turonian) there was a regional rifting event that deposited thick continental clastic sediments. During the Late Cretaceous and Paleogene, transtensional faulting and sag events occurred in the western part of the Sud Province and fluvial and lacustrine sediments were deposited.

The rift basins in the eastern part of the province are extensional and transtensional and filled with Lower Cretaceous to Neogene sedimentary rocks, ranging in thickness from 6,000 m to more than 13,000 m that were deposited in fluvial and lacustrine environments. The initial rifting event began in the latest Jurassic and continued through the Early Cretaceous (fig. 3), resulting in the deposition of Lower Cretaceous lacustrine source sediments (figs. 3, 4). The second rifting event began in the Turonian and continued into the Senonian, and the third stage of rifting occurred during the Paleogene, contemporaneous with the commencement of the Red Sea rifting. Each rifting event was followed by a sag event, during which thick continental clastic sediments were deposited (fig. 3).

The central African rift basins are known to contain Cretaceous to Paleogene lacustrine and marine source rocks that have generated hydrocarbons since the Late Cretaceous. The generated hydrocarbons migrated into Cretaceous and Paleogene reservoirs and structural traps.

Resource Summary
Using a geology-based assessment, the USGS estimated mean volumes of undiscovered, technically recoverable conventional oil and gas resources for the Central African Rifts AU in the Sud Province (table 1). The mean volumes are estimated at 7,310 million barrels of oil (MMBO), 13,418 billion cubic feet of gas (BCFG), and 353 million barrels of natural gas liquids. The estimated mean size of the largest oil field that is expected to be discovered is 1,112 MMBO, and the estimated mean size of the expected largest gas field is 3,677 BCFG. A minimum undiscovered field size of 1 million barrels of oil equivalent (MMBOE) was used for this assessment. No attempt was made to estimate economically recoverable reserves.

http://pubs.usgs.gov/fs/2011/3029/
http://pubs.usgs.gov/fs/2011/3029/pdf/FS11-3029.pdf

Assessment of Undiscovered Oil and Gas Resources of the West African Coastal Province, 2011

The West African Coastal Province along the west African coastline recently was assessed for undiscovered, technically
recoverable oil, natural gas, and natural gas liquids resources as part of the U.S. Geological Survey’s (USGS) World Oil and
Gas Assessment. Using a geology-based assessment methodology,
the USGS estimated mean volumes of 3.2 billion barrels of oil, 23.63 trillion cubic feet of natural gas, and 721 million barrels of natural gas liquids.

Introduction
The main objective of the U.S. Geological Survey’s (USGS) World Petroleum Resources Project is to assess the potential for undiscovered, technically recoverable oil and natural gas resources of the world, exclusive of the United States. As part of this program, the USGS recently completed an assessment of the West African Coastal Province (fig. 1), an area of about 202,715 square kilometers (km2) that covers parts of Guinea, Liberia, and Sierra Leone. This assessment was based on data from oil and gas exploration wells and published geologic reports. At the time of the assessment, the province contained no discovered fields and only 10 exploration wells had been drilled—and it is considered to be underexplored for its size.

The West African Coastal Province developed in two phases: (1) the syn-rift phase was initiated during the Early Cretaceous and resulted in the formation of deep grabens and half-grabens; and (2) the passive margin-transform phase began in the late Albian and continues to the present. The total thickness of the Mesozoic to Cenozoic section is about 5,000 meters (m) on the outermost part of the continental shelf and thickens to as much as 10,000 m in the basin depocenters.

The West African Coastal Province was assessed for the first time because of increased exploratory activity and interest in its future potential. The assessment was geology-based and used the total petroleum system (TPS) concept. The geologic elements of a TPS include hydrocarbon source rocks (source rock maturation and hydrocarbon generation and migration), reservoir rocks (quality and distribution), and traps for hydrocarbon accumulation. Using these geologic criteria, the USGS defined the Cretaceous Composite TPS with one assessment unit (AU), the Mesozoic-Cenozoic Reservoirs AU (fig. 1), encompassing about 188,550 km2, that includes the offshore parts of the province to a water depth of 4,000 m. The TPS was defined to include Cretaceous marine source rocks, including the Cenomanian-Turonian source containing Type II kerogen ranging from 3 to 10 weight percent total organic carbon. Possible lacustrine source rocks may be present in grabens that developed in the Lower Cretaceous. The AU contains Cretaceous and Paleogene clastic reservoirs and traps that mostly are associated growth-fault related structures, rotated fault blocks within the continental shelf and below the mid-Cretaceous unconformity, deep water fans, turbidite channels and sandstones, slope truncations along the present-day shelf and paleoshelf edge, and Cretaceous and Paleogene stratigraphic pinch-outs along the eastern basin margin. The primary seals are Cretaceous and Paleogene marine mudstones and shales.

Exploration wells on the continental shelf and upper slope, in water depths ranging from 100 to 470 m (IHS Energy, 2009), have demonstrated the existence of an active petroleum system containing Cretaceous marine source rocks that have produced hydrocarbons most likely since the Late Cretaceous and that the hydrocarbons have migrated into Cretaceous and Paleogene reservoirs.

Resource Summary
Using a geology-based assessment, the USGS estimated mean volumes of undiscovered, technically recoverable conventional oil and gas resources for the Mesozoic-Cenozoic Reservoirs AU in the West African Coastal Province (table 1). The mean volumes are estimated at 3,200 million barrels of oil (MMBO), 23,629 billion cubic feet of gas (BCFG), and 721 million barrels of natural gas liquids. The estimated mean size of the largest oil field that is expected to be discovered is 783 MMBO, and the estimated mean size of the expected largest gas field is 4,695 BCFG. For this assessment, a minimum undiscovered field size of 5 million barrels of oil equivalent (MMBOE) was used. No attempt was made to estimate economically recoverable reserves.


http://pubs.usgs.gov/fs/2011/3034/
http://pubs.usgs.gov/fs/2011/3034/pdf/FS11-3034.pdf

Petroleum Geology and Resources of the Baykit High Province, East Siberia, Russia. 2001

http://pubs.usgs.gov/bul/2201/F/
http://pubs.usgs.gov/bul/2201/F/b2201-f.pdf

Petroleum Geology of the Widyan Basin and Interior Platform of Saudi Arabia and Iraq, 2002


http://pubs.usgs.gov/bul/b2202-e/
http://pubs.usgs.gov/bul/b2202-e/B2202-E.pdf

Total Petroleum Systems of the Carpathian–Balkanian Basin Province of Romania and Bulgaria



http://pubs.usgs.gov/bul/2204/f/
http://pubs.usgs.gov/bul/2204/f/pdf/B2204F_508.pdf

Usgs Assessment: Undiscovered Petroleum Resources of the Barents Sea Shelf, 2009


http://pubs.usgs.gov/fs/2009/3037/
http://pubs.usgs.gov/fs/2009/3037/pdf/FS09-3037.pdf

Usgs Assessment:Undiscovered Oil and Gas Resources Каспия и Прикаспия, 2010

Assessment of Undiscovered Oil and Gas Resources of the North Caspian Basin, Middle Caspian Basin, North Ustyurt Basin, and South Caspian Basin Provinces, Caspian Sea Area, 2010

Introduction
The U.S. Geological Survey (USGS) estimated technically recoverable, conventional, undiscovered oil and gas resources of the Caspian Sea area as part of a program to estimate these resources for priority basins around the world. Four petroliferous geologic provinces cover the Caspian Sea area, (1) the North Caspian Basin, (2) Middle Caspian Basin, (3) North Ustyurt Basin, and (4) South Caspian Basin (fig. 1). The provinces encompass approximately 1,315,000 square kilometers and were based on interpretations by Delia and others (2008) and Natal’in and Şengör (2005). This assessment was based on published geologic information and on commercial data from oil and gas wells and fields, and field production records. The USGS approach is to define total petroleum systems and assessment units, and assess the potential for undiscovered oil and gas resources.

Total Petroleum Systems and Assessment Units
One total petroleum system (TPS), Paleozoic Composite, was defined for the North Caspian Basin Province to include source rocks ranging in age from Late Devonian through Early Permian (table 1, Ulmishek, 2001b). Five assessment units (AU) were defined geologically within this TPS. Four of the AUs lie below Lower Permian (Kungarian) evaporites (fig. 2A) — North and West Margins Subsalt AU, East and Southeast Margins Subsalt AU, South Margin Subsalt AU, and Central Basin Subsalt AU (table 1). Most reservoirs and seals in these AUs are associated with carbonate shelves and reefs, although some shelf and basin-slope clastic reservoirs of poor quality exist. Because of the extreme depths, a greater uncertainty was assumed that the Central Basin Subsalt AU contains technically recoverable oil or gas exceeding the minimum accumulation size set for the assessment (0.5 million barrels of oil equivalent) and therefore it was assigned a probability of 0.63 (table 1). Carbonate reefs and features associated with carbonate shelves are important traps for the subsalt AUs. Structural traps and likely stratigraphic traps are known in the East and Southeast Margins Subsalt AU. The Suprasalt AU lies above the evaporites (fig. 2A). Reservoirs and seals in this AU include clastic rocks ranging in age from Late Permian through Cretaceous and traps are associated with salt tectonics.

Three TPSs were identified in the North Ustyurt Basin Province — Buzachi Arch and Surrounding Areas Composite TPS, Mesozoic-Cenozoic Composite TPS, and Paleozoic Composite TPS (table 1, Ulmishek, 2001c). The Buzachi Arch and Surrounding Areas Composite TPS was defined to include source rocks within the Buzachi Arch and possible contributions of oil and gas from the neighboring North and Middle Caspian Basins. One AU was defined for each TPS — Mesozoic Sandstone Reservoirs AU, Mesozoic-Cenozoic Reservoirs AU,
and Upper Paleozoic Carbonates AU, respectively. Reservoirs and seals are indicated in the AU names. Most known traps are structural, although some pinchout traps are inferred.

The Terek-Caspian, South Mangyshlak, and Stavropol-Prikumsk TPSs were identified in the Middle Caspian Basin Province (table 1, Ulmishek, 2001a). Source rocks in the Terek-Caspian TPS include Oligocene to Lower Miocene Maykop Formation, Eocene Kuma Formation, and possibly some Middle to Upper Jurassic subsalt mudstones. The South Mangyshlak TPS includes Triassic and possibly Jurassic source rocks. Lower Triassic, Middle Jurassic, and the Oligocene to lower Miocene

Maykop Formation are source rocks in the Stavropol-Prikumsk TPS. Two AUs were defined for the Terek-Caspian TPS — Foldbelt-Foothills AU and Foreland Slope and Foredeep AU (fig. 2B). Reservoirs and seals in these AUs are mainly Upper Cretaceous to Eocene carbonate rocks and Lower to Upper Cretaceous and Miocene clastic rocks. One AU was defined for each of the other TPSs, having the same names as the TPS — South Mangyshlak AU and Stavropol-Prikumsk AU (fig. 2B, table 1). In the South Mangyshlak AU, reservoirs and seals exist in Lower to Middle Jurassic and Cretaceous clastic rocks, Triassic carbonates, and in fractured and weathered basement granite. Triassic carbonate rocks; Jurassic, Cretaceous, and Oligocene clastic rocks; and fractured Maykop mudstone provide reservoirs and seals in the Stavropol-Prikumsk AU. Known traps in all of the AUs are mostly structural, with some pinchout and stratigraphic traps.
The Cenozoic Composite TPS was defined for the South Caspian Basin Province (table 1) to include Oligocene to lower Miocene Maykop Formation and overlying Diatom Formation marine source rocks, and possibly also Eocene marine source rocks. The Apsheron-Pribalkhan Zone, Lower Kura Depression and Adjacent Shelf, and Turkmen Block AUs were defined in the TPS (fig. 2C). Reservoir and seal rocks are predominantly Pliocene to Pleistocene clastic rocks. Known traps include both structural and stratigraphic.

Assessment Results
Estimates of volumes of technically recoverable, conventional, undiscovered oil and gas resources are shown in table 1. No attempt was made to estimate economically recoverable resources because it is beyond the scope of this study. The combined mean undiscovered petroleum resources in the Caspian Sea area are 19.6 billion barrels of recoverable crude oil, 243 trillion cubic feet of recoverable natural gas, and 9.3 billion barrels of recoverable natural gas liquids.

In the North Caspian Basin Province, the mean volumes and probability ranges (F95 to F05) of undiscovered petroleum are approximately 4,671 million barrels (MMB) of crude oil, with a range of 1,278 to 10,565 MMB; 33,099 BCF of natural gas (both associated and dissolved, and nonassociated), with a range of 7,511 to 83,623 billion cubic feet (BCF); and 4,864 MMB of natural gas liquids, with a range of 1,294 to
11,153 MMB.

In the North Ustyurt Basin Province, the mean volumes and probability ranges (F95 to F05) of undiscovered oil are approximately 342 MMB of crude oil, with a range of 118 to 707 MMB; 4,651 BCF of natural gas (both associated and dissolved, and nonassociated), with a range of 1,339 to 10,587 BCF; and 61 MMB of natural gas liquids, with a range of 17 to 140 MMB.

In the Middle Caspian Basin Province, the mean volumes and probability ranges (F95 to F05) of undiscovered oil are approximately 1,908 MMB of crude oil, with a range of 569 to 4,200 MMB; 8,655 BCF of natural gas (both associated and dissolved, and nonassociated), with a range of 2,408 to 20,362 BCF; and 352 MMB of natural gas liquids, with a range of 94 to 850 MMB.

In the South Caspian Basin Province, the mean volumes and probability ranges (F95 to F05) of undiscovered oil are approximately 12,671 MMB of crude oil, with a range of 2,358 to 32,543 MMB; 196,835 BCF of natural gas (both associated and dissolved, and nonassociated), with a range of 38,330 to 494,358 BCF; and 4,002 MMB of natural gas liquids, with a range of 760 to 10,249 MMB.

http://pubs.usgs.gov/fs/2010/3094/
http://pubs.usgs.gov/fs/2010/3094/pdf/FS10-3094.pdf

Usgs Assessment: Undiscovered Petroleum Resources of the Laptev Sea Shelf Province, 2007

Introduction
In 2007, the U.S. Geological Survey (USGS) completed an assessment of potential undiscovered, technically recoverable (assuming the absence of sea ice) crude oil, natural gas, and natural gas liquids (collectively referred to as petroleum) resources in the Laptev Sea Shelf Province of the Russian Federation. As with other areas assessed in the USGS Circum-Arctic Oil and Gas Resource Appraisal (CARA), this area shares important characteristics with many Arctic basins, including sparse data, significant petroleum-resource potential, geologic uncertainty, and technical barriers that impede exploration and development. As defined for CARA, the province includes an area of approximately 500,000 km2, most of which underlies less than 500 m of water offshore of northern Russia between long. 110º and 150º E and between lat. 70º and 80º N.

Assessment Units
The Laptev Sea Shelf Province contains a composite sedimentary basin, in which sediments were deformed by compression during Early Cretaceous time; later, in Paleogene and Neogene time, a superimposed rift/sag system developed in the area. The province was subdivided into three geologically distinctive assessment units based on structural style—the West Laptev Grabens, East Laptev Horsts, and Anisin-Novosibirsk Basins assessment units (AUs) (fig. 1).
The West Laptev Grabens AU was evaluated using two different geological scenarios (table 1) because geologic models for petroleum occurrence considered for this AU are mutually exclusive. The differences between the two scenarios are so extreme that the populations of undiscovered accumulations cannot be statistically combined into a single distribution. The Anisin-Novosibirsk Basins AU was also assessed.
The East Laptev Horsts AU, although defined, was not quantitatively assessed because of the extremely low assessment-unit probability for the existence of an undiscovered accumulation exceeding the defined minimum size of 50 million barrels of oil equivalent.

Petroleum System Elements
Onshore field work and interpretation of geophysical data gathered from offshore areas by geologists from several countries and organizations indicate that two or more total petroleum systems might exist in the study area. Because of possible mixing of petroleum, the Jurassic-Cretaceous-Paleogene Composite Total Petroleum System (TPS) was identified for the West Laptev Grabens AU. Geologic scenarios evaluated for the assessment were based on the existence and distribution of source rocks of these ages. The Paleogene TPS was identified for the Anisin-Novosibirsk Basins AU. The greatest geologic uncertainty for the assessment of both assessment units is with respect to the petroleum charge.

Analyses of natural gas collected from bottom sediments and near-bottom waters of the Laptev Sea Shelf indicate the presence of mature oil-prone marine source rocks, presumably of Paleogene age. Upper Jurassic (Volgian) organic-rich mudstone might also be an important petroleum source rock in the study area, as are synrift Lower Cretaceous and Paleogene carbonaceous and coaly rocks. Major synrift reservoir rocks are likely to be shelf and slope siliciclastic sediments deposited by deltas of the paleo- and present-day Lena River. Whether prerift reservoir rocks are present is uncertain. Traps for petroleum accumulation could include extensional structures and stratigraphic traps associated with shelf sediments.

Resource Summary
The U.S. Geological Survey assessed undiscovered conventional, technically recoverable petroleum (discovered reserves not included) resulting in the estimated mean volumes of a probability distribution of approximately 3,069 million barrels (419 million metric tons) of crude oil, 32,252 billion cubic feet (913 billion cubic meters) of natural gas, and 861 million barrels (117 million metric tons) of natural gas liquids (table 1). The greatest volume of undiscovered petroleum is estimated to be in the West Laptev Grabens AU.

http://pubs.usgs.gov/fs/2007/3096/
http://pubs.usgs.gov/fs/2007/3096/pdf/FS07-3096_508.pdf

UsgsAssessment: Undiscovered PetroleumResources of the North and East Margins of the Siberian Craton

May 2008


http://pubs.usgs.gov/fs/2008/3020/
http://pubs.usgs.gov/fs/2008/3020/pdf/FS08-3020_508.pdf

Usgs Assessment:Undiscovered Oil and Gas Resources of the West Siberian Basin Province, Russia, 2010


http://pubs.usgs.gov/fs/2011/3050/
http://pubs.usgs.gov/fs/2011/3050/pdf/fs2011-3050.pdf

Usgs Assessment: Undiscovered Oil and Gas Resources of Libya and Tunisia, 2010

Using a geology-based assessment methodology, the U.S. Geological Survey estimated means of 3.97 billion barrels of undiscovered oil, 38.5 trillion cubic feet of undiscovered natural gas, and 1.47 billion barrels of undiscovered natural gas liquids in two provinces of North Africa.

Introduction
The U.S. Geological Survey (USGS) assessed the potential for undiscovered conventional oil and gas fields within two geologic provinces of North Africa―Sirte Basin in Libya and Pelagian Basin in Tunisia and western Libya―as part of the USGS World Petroleum Resources Project (fig. 1). The Sirte Basin originated as a Cretaceous rift that evolved into a post-rift basin dominated by thermal subsidence; it is characterized by carbonate deposition on high blocks and fine-grained clastic deposition in troughs.

The Pelagian Basin was dominated by Mesozoic and Cenozoic subsidence related to tectonism along the northern margin of the African plate. One total petroleum system (TPS) was defined in the Sirte Basin Province, and two TPSs were defined in the Pelagian Basin Province. The Sirte Rachmat Composite TPS in the Sirte Basin Province contains the post-rift Coniacian−Campanian Sirte−Rachmat organic-rich shale/marl, which was deposited in troughs across the Sirte Basin during the early phase of thermal subsidence. Major reservoirs in the Sirte Basin Province include syn-rift continental sandstones and post-rift shallow-marine carbonates, with shales and evaporites acting as seals for hydrocarbon reservoirs. Two assessment units (AU) were defined within the Sirte−Rachmat Composite TPS: the Onshore Sirte Carbonate−Clastic AU and the Offshore Sirte Basin AU.

Within the Pelagian Basin, two TPSs were retained for this assessment.
The Jurassic−Cretaceous Composite TPS consists of fluids from Jurassic and Cretaceous deep-marine shales that migrated into Jurassic−Cretaceous shallow marine limestones and Upper Cretaceous fractured deepwater chalks. Seals include Jurassic and Cretaceous shales and evaporites. One AU was defined for this TPS, the Jurassic−Cretaceous Structural/Stratigraphic AU. The Bou Dabbous Cenozoic TPS contains the Eocene Bou Dabbous organic-rich shale, with hydrocarbons that migrated into lower and middle Eocene shallow-water limestones that are


Figure 1. Locations of the Sirte and Pelagian Basin Provinces, North Africa. AU, assessment unit

sealed by overlying shales and marls. This TPS contains the Bou Dabbous−Cenozoic Structural/Stratigraphic AU. The methodology for the assessment included a complete geologic framework description for each province, based mainly on published literature and the definition of petroleum systems and assessment units within these systems. Exploration and discovery history was a critical part of the methodology used to estimate sizes and numbers of undiscovered accumulations. In areas where there are few or no discoveries (for example, offshore Sirte Basin), geologic analogs were used as a basis for estimating volumes of undiscovered oil and gas resources. Each assessment unit was assessed for undiscovered oil and nonassociated gas accumulations, and coproduct ratios were used to calculate the volumes of associated gas (gas in oil fields) and natural gas liquids.

Resource Summary
The USGS assessed undiscovered conventional oil and gas resources within the three TPSs in the Sirte and Pelagian Basin Provinces (table 1). The mean total of undiscovered oil in these two provinces is 3,974 million barrels of oil (MMBO), with a range from 1,119 MMBO (95 percent probability) to 9,044 MMBO (5 percent probability); for undiscovered gas the mean total is 38,509 billion cubic feet of gas (BCFG), with a range from 11,520 to 84,347 BCFG; and the mean total for natural gas is 1,466 million barrels of natural gas liquids (MMBNGL), with a range from 405 to 3,384 MMBNGL.

About 90 percent of the mean total of undiscovered oil (3,545 MMBO), 85 percent of the mean total of undiscovered gas (32,451 BCFC), and 89 percent of the mean total of undiscovered natural gas liquids (1,298 MMBNGL) are estimated to be in the Sirte Basin Province. Of these volumes, 64 percent of the undiscovered oil (2,267 MMBO), 80 percent of the undiscovered gas (25,609 BCFG), and 78 percent of the undiscovered natural gas liquids (1,010 MMBNGL) are in the Offshore Sirte Basin AU, with the remaining percentages in the Onshore Sirte Carbonate−Clastic AU. The higher percentage of undiscovered oil and gas resources assessed in the Offshore Sirte Basin AU reflects the relatively underexplored history of this part of the Sirte Basin Province.
Overall, the assessment indicates that 80−90 percent of the undiscovered oil and gas resources are in the Sirte Basin Province, there is significantly more total undiscovered gas resource in both provinces (38,509 BCFG or 6,640 MMBOE) than total undiscovered oil resource (3,974 MMBO), and (3) there is almost twice as much undiscovered gas (25,609 BCFG or 4,415 MMBOE) in the Offshore Sirte Basin AU as there is undiscovered oil (2,267 MMBO).

http://pubs.usgs.gov/fs/2011/3105/
http://pubs.usgs.gov/fs/2011/3105/pdf/FS11-3105.pdf

Usgs Assessment: Dnieper–Donets Basin Province and Pripyat Basin Province

Introduction
The U.S. Geological Survey (USGS) estimated technically recoverable, conventional, undiscovered oil and gas resources of the Dnieper–Donets Basin Province and Pripyat Basin Province in
Russia, Ukraine and Belarus as part of a program to estimate these resources for priority basins around the world. The Dnieper–Donets Basin Province encompasses about 99,000 square kilometers and the Pripyat Basin Province, 35,000 square kilometers (fig. 1). These assessments were based on published geologic information and on commercial data from oil and gas wells and fields, and field production records. The USGS approach is to define total petroleum systems and assessment units, and assess the potential for undiscovered oil and gas resources.


Figure 1. Generalized map showing the boundaries of the Pripyat Basin and Dnieper-Donets Basin geologic provinces (red lines), centerpoints of oil and gas fields (green and red circles, respectively), and the location of geologic cross section A-A’ shown in figure 2 (green line). Country boundaries are represented by blue lines. Field data from IHS Energy (2009); geologic province boundaries from Persits and others (1998).

Total Petroleum Systems and Assessment Units
One total petroleum system (TPS), the Paleozoic Composite, was defined for the Dnieper–Donets Basin and Pripyat Basin Provinces (table 1). It was defined to include petroleum source rocks ranging in age from Upper Devonian through Carboniferous. Two assessment units (AU) were defined geologically within the TPS, each encompassing the respective provinces—Clastic and
Carbonate Reservoirs for the Dnieper–Donets Basin Province and Carbonate Reservoirs for the Pripyat Basin Province (figs. 1 and 2). Two additional AUs containing continuous accumulations, Continuous Basin–Centered Gas and Visean Shale Gas, were identified in the Dnieper–Donets Basin Province, but were not quantitatively assessed in this study.


Figure 2. Geologic cross section for the Dnieper-Donets Basin. See figure 1 for location. Modified from Ulmishek (2001) and Law and others (1998). Explanation: 1, Upper Devonian; 2, Devonian evaporites; 3, Carboniferous; 4, Permian; 5, Triassic; 6, Jurassic; 7, Cretaceous; 8, Cenozoic; 9, oil accumulation; 10, gas accumulation; 11, top of overpressure; 12, 100° C isotherm; 13, 0.9 percent vitrinite reflectance isochore; 14, stratigraphic boundary.

In the Dnieper–Donets Basin Province, source rocks include the Visean Rudov Bed, Carboniferous mudstones and coals, and possibly Frasnian and lower Famennian mudstones (Ulmishek and others, 1994; Ulmishek, 2001). These source rocks at present are in the lower part of the oil window and upper part of the gas window; however, they attained maximum maturation during the Late Permian. Reservoir rocks are mainly Carboniferous to Lower Permian sandstones. Other reservoirs are in Lower Carboniferous and Lower Permian carbonate rocks, fractured metamorphic basement rocks, and Devonian carbonate rocks. Seal rocks include Devonian and Permian evaporites and intraformational mudstones. Traps are mostly structural, associated with salt and fault blocks,
drapes, reef facies, and stratigraphic pinchouts. Undiscovered accumulations could exist in deeper structural and stratigraphic traps and in association with complex salt structures.

Source rocks in the Pripyat Basin Province primarily are Frasnian (Moiseev Bed) and lower Famennian mudstones (Ulmishek and others, 1994). Reservoir rocks include Devonian carbonate
rocks and Carboniferous to Lower Permian sandstones. Devonian and Permian evaporites and intraformational mudstones serve as seal rocks. Traps are mostly structural, associated with salt and fault blocks, drapes, reef facies, and pinchouts. Nearly all of the known accumulations are in the northern part of the Carbonate Reservoirs AU (fig. 1), probably because of an underlying magmatic body that increased thermal maturation of the source rocks. Undiscovered accumulations could exist in traps similar to those already discovered in the northern part of the AU.

Assessment Results
Estimates of volumes of technically recoverable, conventional, and undiscovered oil and gas resources are shown in table 1. No attempt was made to estimate economically recoverable resources because it is beyond the scope of this study. The mean volumes of undiscovered petroleum in the Dnieper-Donets Basin Province are estimated at approximately 84 million barrels (MMB) of crude oil, 4,739 billion cubic feet (BCF) of natural gas (286 BCF of associated and dissolved natural gas and 4,453 BCF of nonassociated natural gas), and 130 MMB of natural gas liquids. The mean volumes of undiscovered petroleum in the Pripyat Basin Province are estimated at approximately 39 MMB of crude oil, 48 BCF of natural gas (31 BCF of associated and dissolved natural gas and 17 BCF of nonassociated natural gas), and 1 MMB of natural gas liquids. The mean volumes of undiscovered petroleum for both provinces combined are approximately 123 MMB of crude oil, 4,787 BCF of natural gas (317 BCF of associated and dissolved natural gas and 4,470 BCF of nonassociated natural gas), and 130 MMB of natural gas liquids.


http://pubs.usgs.gov/fs/2011/3051/
http://pubs.usgs.gov/fs/2011/3051/pdf/fs2011-3051.pdf