Архив меток: газ запасы таблица

eia.gov: Overview of oil and natural gas in the Eastern Mediterranean region

http://www.eia.gov/countries/regions-topics.cfm?fips=EM

— — — — —
Oil and natural gas reserves, production, and consumption
Всего в регионе
Нефть
2.51 billion barrels Proved reserves = 342 млн. т. в почти все в Сирии
Газ
18.20 trillion cubic feet Proved reserves = 0.5096 трлн. м3 почти пополам в Израиле и Сирии

— — — — —
Восточное Средиземноморье: Турция-Кипр http://iv-g.livejournal.com/548719.html
Undiscovered Oil and Gas of the Nile Delta Basin, Eastern Mediterranean http://iv-g.livejournal.com/170928.html
Assessment of Undiscovered Oil and Gas Resources of the Levant Basin Province, Eastern Mediterranean http://iv-g.livejournal.com/183782.html

AGA.org: US Natural Gas Reserves 2012

http://www.aga.org/Kc/analyses-and-statistics/studies/supply/Pages/PreliminaryFindingsConcerning2012NaturalGasReserves(EnergyAnlaysis2013-01).aspx

Potential Gas Committee: Презентации за 2008 и 2010 годы

Отчеты Potential Gas Committee выходят раз в два года.
Сопоставление новых (2012) со старыми данными необходимо, чтобы понять технику газовых оценок

Презентация за 2008 г.
Potential Supply of Natural Gas in the United States. Report of the Potential Gas Committee
(December 31, 2008). Washington, DC, June 18, 2009

— — — — — —
— Презентацию скачал с energyseminar.stanford.edu
— Первая диаграмма самая интересная: по итогам 2008 г. в 2006 г. не было выделено отдельно «сланцевого газа», а в презентации по итогам 2012 г. в 2006 г. сланцевый газ нашли 🙂

Презентации за 2010 г.
http://potentialgas.org/download/pgc-press-release-april-2011-slides.pdf
Potential Supply of Natural Gas in the United States. Report of the Potential Gas Committee
(December 31, 2010).
Извлечения из презентаций
i/Washington, DC, April 27, 2011

ii/ NARUC Committee on Gas July 18, 2011

iii/ John B. Curtis, Potential Gas Agency, Colorado School of Mines, September 12, 2011

— — — —
— По итогам 2010 г. в 2006 г. был выделен отдельно сланцевый газ
— Даже EIA в 2007 г. не знало про сланцевые формации, на которых в следующем году случился сланцевый бум 🙂

Potential Gas Committee: Презентация 2013 г. (итоги 2012 г.)

http://potentialgas.org/download/pgc-press-release-april-2013-slides.pdf

— — — —
В общедоступных пресс-релизах и презентациях показывают Technically Recoverable Resources. Какие предположения о Technically Recoverable сделаны неизвестно, может быть они упомянуты в отчете, а может быть и не упомянуты. Самое главное в том, что для практического использования категории ресурсов должны отвечать Reserves and Resources Definitions


https://secure.spee.org/sites/default/files/wp-files/pdf/ReferencesResources/Petroleum_Resources_Management_System_2007.pdf

где нет никаких Technically Recoverable Resources. UnRecoverable в этой классификации категория экономическая. Technically Recoverable Resources получают применением некоторых КИН к геологическим запасам, например Undiscovered PIIP, какая часть попала в Unrecoverable Technically и как она соотносится с Unrecoverable Economically неизвестно 🙂

Вся американская классификация запасов нацелена на коммерческие цели, т.е. Есonomically Recoverable (Proved+Pobable Reserves).
Неясного происхождения Technically Recoverable Resources подразделяют для большей доходчивости и для возникновения подсознательных аналогий с действующей классификацией, на Probable, Possible, Speculative, причем последняя категория никак не значится в PRMS/

Смешивание Technically Recoverable Resources и экономически выверенных Proved Reserves при неупоминании величины геологических резервов, от которых неизвестно как получают Technically Recoverable Resources — это очень содержательное занятие, особенно без указания сделанных предположений 🙂

Также весьма интересно, что с точки зрения Potential Gas Committee shale & tight gas относят к группе Tradional, считая нетрадиционным только CBM

Potential Gas Committee, press release: Запасы газа в США на конец 2012 г.

PGC Members’ Positions and Professional Information 2011-2012
Potential Gas Agency at Colorado School of Mines
Representatives: American Gas Association; Natural Gas Pipelines; Natural Gas Distributors
Observers: American Association of Professional Landmen; Bureau of Economic Geology, University of Texas; Electric Power Research Institute; Research Partnership to Secure Energy for America (formerly Gas Technology Institute); U.S. Dept of Interior, Bureau of Land Management; AAPG Committee on Resource Evaluation; Advanced Resources International, Inc.; Boardwalk Pipeline Partners; CenterPoint Energy Inc.; Chesapeake Energy Corporation;
QEP Resources Inc.; DISCERN, Inc.; Drilling Info, Inc.; Drilling Info, Inc.; IHS Energy Group LLC; North Dakota Geological Survey; Ponderosa Advisors; Range Resources Corp.; Quicksilver Resources, Inc.

Отчет за 2012
The Potential Gas Committee (PGC) today released the results of its latest biennial assessment of the nation’s natural gas resources, which indicates that the United States possesses a total technically recoverable resource base of 2,384 trillion cubic feet (Tcf) as of year-end 2012. This is the highest resource evaluation in the Committee’s 48-year history, exceeding the previous high assessment (from 2010) by 486 Tcf. Most of the increase arose from new evaluations of shale gas resources in the Atlantic, Rocky Mountain and Gulf Coast areas.

These changes have been assessed in addition to 49 Tcf of domestic marketed-gas production estimated for the two-year period since the Committee’s previous assessment.

Current assessment assumes neither a time schedule nor a specific market price for the discovery and production of future gas supply. «Assessments of the Potential Gas Committee represent our best understanding of the geological endowment of the technically recoverable natural gas resource of the United States»

The Committee’s year-end 2012 assessment of 2,384 Tcf includes 2,226 Tcf of gas potentially recoverable from “Traditional” reservoirs (conventional, tight sands and carbonates, and shales) and 158 Tcf in coalbed reservoirs. Compared to year-end 2010, assessed Traditional resources increased by 486.4 Tcf (28%), while coalbed gas resources declined by a nominal 0.4 Tcf (0.2%), resulting in a net increase in total potential resources of 486.1 Tcf (25.6%). (See accompanying Table 1.)

When the PGC’s assessments of technically recoverable resources are combined with the U.S. Department of Energy’s latest available determination of proved reserves, 305 Tcf (dry gas) as of year-end 2010, the United States has a total available Future Supply of 2,688 Tcf, an increase of 486 Tcf over the previous evaluation.

As Dr. Curtis observed, “Our knowledge of the geological endowment of technically recoverable gas continues to improve with each assessment. Furthermore, new and advanced exploration, well drilling, completion and stimulation technologies are allowing us increasingly better delineation of and access to domestic gas resources—especially ‘unconventional’ gas—which, not all that long ago, were considered impractical or uneconomical to pursue.”

As a result of a substantial increase in the assessment of Appalachian basin shale gas, the PGC now ranks the Atlantic area as the country’s richest resource area with 33% of total U.S. Traditional resources, followed by the Gulf Coast (including the Gulf of Mexico) and Rocky Mountain areas, which together account for 76% of the assessed total Traditional resource. (See accompanying Table 2.)

Changes in the total assessment from 2010 to 2012 arose primarily from analyses of recent drilling, well-test and production data from these three regions. The largest volumetric and percentage gains were reported for Appalachian basin shales (primarily the Marcellus but including other Devonian shales and the Utica), which collectively rose by 335 Tcf (147%). A substantial increase, 21.6 Tcf (58%), also was made for the Eagle Ford Shale in the Texas Gulf Coast basin. Cretaceous shales in the Rocky Mountain area figured prominently in new record-high assessments for the Greater Green River basin (Baxter and Hilliard Shales) and San Juan basin (Mancos and Lewis Shales), in each case more than double the province’s total potential gas assessment for 2010. Reevaluation of another unconventional resource, the Niobrara Formation, led to a new record assessment of 7.5 Tcf for the Denver basin, a jump of nearly 3.5 Tcf (86%).

The growing importance of shale gas is substantiated by the fact that the PGC’s total assessed shale gas resource of 1,073 Tcf for 2012 accounts for approximately 48% of the country’s total Traditional potential resources.

PGC’s new concise biennial report includes a complete overview of the national aggregated mean-value assessment statistics, including tables and graphs, together with an area-by-area comparison of assessment results for year-end 2010 and 2012 and decennial changes in area-level assessments from 2002–12. The second chapter examines the 2012 evaluations at the area and province levels and discusses the factors behind the principal changes in assessments between 2010 and 2012. Also included are graphs for each area that track historical trends in the Committee’s “most likely” (nonaggregated) assessments since 1984 and the aggregated mean values since 1990. The concluding chapter presents definitions and details of the PGC’s resource assessment methodology.

— —
The Potential Gas Committee (PGC) reports its biennial potential gas resource assessments in three categories of decreasing geological certainty—Probable, Possible and Speculative. For each category, a minimum, most likely and maximum volume is assessed in each of 90 onshore and offshore provinces in the Lower 48 States and Alaska. The category and total mean values shown in Table 1 below were computed by statistical aggregation of the minimum, most likely and maximum value distributions for each category, in turn, for all provinces combined. Mean values for Total Traditional Resources and Total Coalbed Gas Resources were aggregated separately. This procedure imparts greater statistical validity to the results and allows for more direct comparison of PGC’s assessments with those made by other organizations.

Table 1

* Mean values for Probable, Possible and Speculative resources are not arithmetically additive in deriving Total Traditional Gas Resources and Total Coalbed Gas Resources.

** The separately aggregated mean values for Total Traditional Resources and Total Coalbed Gas Resources are arithmetically additive in deriving Grand Total Potential Resources.

† Latest available figure is for year-end 2010.

Note: Totals are subject to rounding and differences due to statistical aggregation of distributions.

PGC’s 90 geological provinces are grouped into seven geographic assessment areas. In similar fashion as above, the minimum, most likely and maximum value ranges for each category of Traditional resources in each province within an area are aggregated at the area level to yield mean values for Probable, Possible and Speculative Traditional resources and a separately aggregated area total. Coalbed gas resources are aggregated only at the national level. Table 2 compares the mean values for these areas for year-end 2012 and year-end 2010.

Table 2

* Mean values of Traditional Resources for the seven areas are not arithmetically additive in deriving Total U.S. Traditional Resources, which is a separately aggregated value. Area-level changes in values from 2010 to 2012 likewise are not arithmetically additive in deriving the total change.

** The separately aggregated mean values for Total U.S. Traditional Gas Resources and Coalbed Gas Resources are arithmetically additive in deriving Grand Total Potential Resources.

† Latest available figure is for year-end 2010.

Note: Totals are subject to rounding and differences due to statistical aggregation of distributions.
http://potentialgas.org/press-release

Россия: Запасы газа

Газпром: презентация ««Газпром» на Востоке России, выход на рынки стран АТР», Пресс-конференция г. Москва, 13 июня 2013 года

— — — — — — — — — —
2010-10-10 Генеральная схема развития газовой отрасли на период до 2030 года

Начальные суммарные ресурсы газа (НСР) России оцениваются по состоянию на 01.01.2007 в 248,6 трлн. м3, в том числе суша – 174,8 трлн. м3, шельф – 73,8 трлн. м3. Наиболее значительные ресурсы газа сосредоточены в недрах Западной Сибири (суша и шельф Карского моря) – 132,2 трлн. м3, Восточной Сибири – 37,9 трлн. м3, Дальнего Востока – 14,5 трлн. м3, а также в Северо-Западном районе России (суша Тимано-Печорской провинции и шельф Баренцева моря) – 26,4 трлн. м3. Доля России в мировых НСР составляет 40,6%. Ресурсная база газовой промышленности России представлена на рисунке 3.1.1.


Рисунок 3.1.1 Ресурсная база газовой промышленности России

Из 47,8 трлн. м3 разведанных запасов 21,0 трлн. м3 приходятся на Надым-Пур-Тазовский регион (НПТР), 10,4 трлн. м3 – полуостров Ямал, 5,9 трлн. м3 – шельф (в том числе 2,9 трлн. м3* – Штокмановское месторождение Баренцева моря), 4,6 трлн. м3 – суша Европейской части РФ, 4,0
трлн. м3 – Восточная Сибирь и Дальний Восток, 1,9 трлн. м3 – другие регионы.

По состоянию на 01.01.2007 из общего объема 47,8 трлн. м3 разведанных запасов газа России ОАО «Газпром» контролировало 29,8 трлн. м3 (62,3%), крупные нефтяные и независимые компании 10,2 трлн. м3 (21,4%), в нераспределенном фонде находилось 7,8 трлн. м3 (16,3%).
Разведанные запасы газа характеризуются сложной внутренней структурой (рисунок 3.1.2). Из 47,8 трлн. м3 суммарных запасов 8,3 составляют запасы месторождений с падающей добычей, 7,7 – запасы месторождений со стабильной добычей, 2,5 трлн. м3 – запасы Астраханского месторождения (ограничение добычи по экологии), 1,2 трлн. м3 – запасы мелких месторождений и 28,1 трлн. м3 – запасы неразрабатываемых месторождений (обеспечение добычи на среднюю и дальнюю перспективу).

Для обеспечения развития газовой отрасли необходимый общий прирост разведанных запасов газа в период 2008-2030 гг. оценивается в 26,0 трлн. м3, в т.ч. по суше Западной Сибири – 7,0 трлн. м3, по Европейским районам – 1,7 трлн. м3, по регионам Восточной Сибири, Дальнего Востока и Охотскому морю – 3,3 трлн. м3, по арктическому шельфу – 14,0 трлн. м3 При этом ожидаемый объем разведочного бурения в целом по России составит 13140 тыс. м.

— — — — — — — —

2011-10-24. Проект госпрограммы освоения российского шельфа до 2030 года

Госпрограмма рассчитана до 2030 года. В целом за период объем накопленной добычи нефти и конденсата составит 380-1250 млн тонн (без учета проектов СРП),
газа — 1-2,6 трлн кубометров.
Геологическую изученность шельфа в Минприроды признают различной: больше всего информации собрано о западно-арктическом регионе и дальневосточном (особенно в районе Сахалина), а меньше всего — о восточно-арктическом. При этом на текущий момент государственным балансом учтены только 25 нефтяных месторождений и 44 газовых. По нефти их общие запасы по категории С2 оцениваются в 595 млн тонн, а по газу — 3,5 трлн кубометров.
http://www.kommersant.ru/doc-y/1799668

Запасы нефти должны увеличиться на 0,8-1,3 млрд т, газа — на 3,4-13 трлн куб. м. Суммарные извлекаемые запасы нефти на шельфе, учтенные Госбалансом по состоянию на январь 2010 г., — 627 млн т (25 месторождений), газа — 7,5 трлн куб. м (44 месторождения). Примерно 70% запасов — в Баренцевом, Карском и Печорском морях.
http://www.vedomosti.ru/politics/news/1400501/gavan_na_shelfe

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

OPEC: Annual Statistical Bulletin, 2012. Запасы нефти и газа, сведения о бурении

«НОВАТЭК» сообщил о значительном росте доказанных запасов

21 февраля 2013 года. ОАО «НОВАТЭК» объявило сегодня о завершении оценки запасов углеводородов по состоянию на 31 декабря 2012 года, проведенной компанией DeGolyer & MacNaughton.

Доказанные запасы углеводородов Компании (включая долю в запасах совместных предприятий) по стандартам SEC составили 12 394 млн баррелей нефтяного эквивалента (бнэ), что на 32% больше по сравнению с аналогичным показателем на конец 2011 года. Прирост доказанных запасов (SEC), включая добычу 2012 года, составил 3,4 млрд бнэ, а коэффициент восполнения запасов — 842%. При этом объем доказанных запасов газа вырос до 1 758 млрд куб. м или на 493 млрд куб. м, включая добычу 2012 года. Обеспеченность Компании запасами углеводородов выросла с 25 лет по состоянию на конец 2011 года до 31 года на конец 2012 года.

По стандартам PRMS доказанные запасы углеводородов в 2012 году выросли на 38% или на 4 665 млн бнэ, включая добычу 2012 года, и составили 15 597 млн бнэ. Доказанные и вероятные запасы выросли на 45% до 22 355 млн бнэ, в том числе запасы газа увеличились на 1 054 млрд куб. м, включая добычу, и достигли 3 106 млрд куб. м.

Увеличение всех категорий запасов связано с успешным проведением геологоразведочных работ, продолжением разбуривания месторождений, включением в оценку запасов Салмановского (Утреннего) и Геофизического месторождений, лицензии на которые были приобретены в 2011 году, а также приобретением в 2012 году доли в ЗАО «Нортгаз», владеющем лицензией на Северо-Уренгойское месторождение.

Примечания:
В периметр оценки запасов по состоянию на конец 2012 года вошли Восточно-Таркосалинское, Ханчейское, Северо-Ханчейское, Северо-Русское, Юрхаровское, Западно-Юрхаровское, Салмановское (Утреннее) и Геофизическое месторождения, Олимпийский и Западно-Уренгойский лицензионные участки, лицензии на освоение которых принадлежат дочерним обществам Компании, а также Южно-Тамбейское, Термокарстовое, Ярудейское, Береговое, Хадырьяхинское, Пырейное, Северо-Часельское и Яро-Яхинское месторождения, Ево-Яхинский, Самбургский и Северо-Уренгойский лицензионные участки, запасы которых учтены в соответствии с долями Компании в совместных предприятиях.

Товарная добыча по месторождениям, вошедшим в периметр оценки, составила в 2012 году около 405 млн бнэ. Суммарная валовая добыча по всем месторождениям Компании составила около 411 млн бнэ.

Коэффициент восполнения запасов рассчитан как отношение изменения запасов, включая добычу в отчетном периоде, к добыче отчетного периода.

Коэффициенты пересчета:
1000 кубических метров газа = 6,54 барреля нефтяного эквивалента.
Для пересчета запасов нефти и газового конденсата из тонн в баррели использовались различные коэффициенты, зависящие от плотности нефти и газового конденсата каждого месторождении.
http://www.novatek.ru/ru/press/releases/index.php?id_4=698

Ernst&Young: Natural gas in Africa: frontier of the Golden Age

Компания Ernst&Young подготовила отчет «Natural gas in Africa: frontier of the Golden Age». В документе указано, что природным газом Африки в настоящее время интересуются очень многие – и нефтегазовые мейджоры, и компании поменьше, и национальные нефтегазовые компании других регионов. В отчете Ernst&Young отмечается, что природный газ может стать основой социально-экономического развития континента.

В документе «Are we entering a Golden Age of Gas?», подготовленном EIA в 2011 году, указано, что светлое будущее природного газа связано со следующими предпосылками: 1) ростом потребления природного газа в Китае; 2) более широким использованием газового топлива на транспорте; 3) снижением популярности АЭС после аварии на японской АЭС Фукусима-1; 4) ростом объемов добычи сланцевого газа и масштабов СПГ-торговли.

Доказанные запасы газа в Африке, по оценкам EIA, составляют 14 трлн куб м, что составляет примерно 7,5% всех запасов природного газа в мире. Но запасы газа в Африке постоянно растут: в этом году крупные месторождения природного газа были обнаружены у берегов Танзании (в настоящее время обнаружено порядка 900 млрд куб м газа) и Мозамбика (в настоящее время запасы газа у берегов этой страны оцениваются в 2,8 трлн куб м). Также перспективные структуры обнаружены у берегов Кении и Мадагаскара. При этом основная активность по разведке природного газа сейчас происходит на востоке Африки. Западная Африка традиционно ориентирована на нефть, попутный газ там сжигают в факелах.

Специалисты EIA полагают, что к 2035 году добыча газа в Африке вырастет до 400 млрд куб м в год (потребление – до 170 млрд куб м). Добыча будет расти со скоростью 2,7% ежегодно. Экспорт СПГ из африканских стран к 2035 достигнет 230 млрд куб м.

При этом в Wood Mackenzie подсчитали, что точка безубыточности для африканского СПГ составит 7 долл за MMBTU (247 долл за тыс куб м), а австралийского – 10 долл за MMBTU (353 долл за тыс куб м). В настоящее время СПГ-заводы в Африке расположены в Алжире, Египте, Ливии, Нигерии, Экваториальной Гвинее и Анголе.

Российские нефтегазовые компании в Африке

В планах Gazprom EP International на 2011 год значились проекты в Алжире, Ливии, Намибии (месторождение Куду) и Нигерии (там было основано СП c Нигерийской национальной нефтяной корпорацией Nigaz, название которого наделало много шума из-за созвучности с пренебрежительным прозвищем африканцев). Никакой активности Nigaz с момента основания замечено не было. С месторождением Куду тоже ничего не происходит. Какое-то продвижение «Газпрома» наблюдалось в Алжире, но там последняя новость датирована ноябрем 2010 года: «В ноябре 2010 года по итогам бурения скважины Rhourde Sayah-2, глубина которой составила 4400 м, на участке были открыты запасы углеводородов»). В Ливии проекты (в частности связанные с месторождением Elephant) осложнились революцией.

Африка, впрочем, включена в список приоритетов Газпрома в инвестиционной программе компании на 2012 год в новой редакции.

На Черном континенте (в частности, в Египте) также пытается работать НОВАТЭК, но летом работы были приостановлены. Роснефть планирует строительство нефтепровода из Мозамбика в Зимбабве протяженностью 700 км, а ЛУКОЙЛ на днях приобрел 25% геологоразведочного блока в акватории Сьерра-Леоне по соседству с другим своим проектом. В Западной Африке ЛУКОЙЛ также работает в Кот-д`Ивуаре и Гане.
http://www.trubagaz.ru/issue-of-the-day/gaz-v-afrike-chto-bylo-chto-budet-i-kakova-rol-rossijan/

http://www.ey.com/GL/en/Industries/Oil—Gas/Natural-gas-in-Africa-frontier-of-the-Golden-Age
http://www.ey.com/Publication/vwLUAssets/Natural_gas_in_Africa_frontier_of_the_Golden_Age/$FILE/Natural_Gas%20in_Africa.pdf

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.

crustgroup: Запасы российских месторождений нефти и газа

http://crustgroup.livejournal.com/23292.html

— — — —
Из комментариев к записи
— В табличке баррели и кубометры это по какой категории?
— В основном, где это было явно указано — А+В+С1+С2 в российской классификации. Что уже подсекли скважинами.

— а табличка с запасами она из открытого доступа или ваша компиляция?
— Компиляция из отрытых источников Сети. Табличка неполная, я её сейчас потихоньку дополняю.

rbcdaily: Аукционы и конкурсы Роснедр снова стали интересны нефтяникам

22.08.2012

С начала года на продаже углеводородных месторождений Роснедра заработали 9 млрд руб. Из заявленных аукционов и конкурсов состоялось 30%, это вдвое превышает показатели прошлых лет. Самые дорогие и привлекательные участки достались «Башнефти», ЛУКОЙЛу и «Газпром нефти». Но даже на совсем небольшие нефтяные «лужицы» нашлись покупатели. Но не исключено, что для выполнения плана Минфина по наполняемости бюджета ведомству все же придется выставить на торги долгожданные стратегические месторождения.

Всего на продажу было выставлено 83 участка, из которых новых собственников обрели 26, исходя из данных, опубликованных на официальном сайте Роснедр. При этом 53 аукциона были признаны несостоявшимися из-за отсутствия заявителей — никто из компаний не заинтересовался предложениями. Еще три были отменены по другим причинам. Например, Соболиный участок не был продан из-за ошибки самого ведомства, допущенной организатором в процессе аукциона. Что именно было сделано не так, в сообщении не поясняется, но говорится, что начальнику отдела лицензирования, экономики и бухгалтерского учета Роснедр было объявлено замечание.
В двух других случаях к участию в торгах были не допущены все заявители. Дело в том, что условия проведения аукционов и конкурсов достаточно жесткие — если хотя бы один из пунктов в сведениях о заявители нарушен, юристы имеют право не допустить его к аукциону, пояснил РБК daily источник в Роснедрах. «Там большой список необходимых документов, вплоть до копий паспортов сотрудников предприятия. И если хоть один документ не приложен, в заключении это отмечается. Например, отсутствие выписки по финансам или по технике, например, буровой — может, у них вообще нечем бурить», — отметил собеседник.

За семь месяцев этого года Роснедра заработали только на продаже углеводородных лицензий более 9 млрд руб. Это сопоставимо с результатами за 2010 год, без учета средств от продажи месторождений им. Требса и им. Титова (они ушли «Башнефти» за 18,4 млрд руб.). Как пояснили РБК daily в Минфине, «планируется, что, администрируя разовые платежи в аукционах и проводя экспертизы, Роснедра ежегодно будут пополнять бюджет на 42 млрд руб. вплоть до 2015 года». Амбиции финансового ведомства на 27,5% ниже прошлогодних, когда перед Роснедрами стояла планка в 58 млрд руб.

Если исключить из списка «Роснефть» и «Газпром», которым лицензии на шельфовые месторождения доставались без всяких конкурсов, то видно, что активнее всего в торгах участвовали «Газпром нефть», ЛУКОЙЛ и «Башнефть».

В случае «Башнефти» это объясняется стремлением укрепить позиции в Ямало-Ненецком АО — в окрестностях принадлежащих ей месторождений им.Требса и им.Титова, считает аналитик «Уралсиб Кэпитал» Алексей Кокин. По его мнению, это позволит компании рационально использовать инфраструктуру региона.

Крупные компании все же предпочитают не размениваться по мелочам. ЛУКОЙЛ уже стал обладателем одной из самых дорогих лицензий этого года и теперь ждет торгов по стратегическому Имилорскому месторождению, где сейчас проводит доразведку. «Мы заинтересованы прежде всего в «сквозных» лицензиях, потому что непонятно, как будут возмещаться затраты компании на разведку, если кому-то другому потом отдадут этот участок. Слишком много рисков», — заключил представитель ЛУКОЙЛа.

Возобновился спрос и на маленькие месторождения, которые нефтяники называют «лужицами». Причем если раньше цель приобретения небольших участков была скорее спекулятивная, то сейчас средний бизнес заинтересован в самостоятельной разработке месторождений. «Мы понимаем, что в регионе растет спрос на газомоторное топливо. Мы давно вынашивали идею собственного нефтегазодобывающего бизнеса с перспективой заниматься газопереработкой. Ждали только подходящего месторождения», — рассказывает РБК daily директор «Окагаза» Станислав Питьев. Эта компания приобрела Спортивный участок в Саратовской области за 7,7 млн руб.

http://www.rbcdaily.ru/2012/08/22/tek/562949984564764

eia.gov: Gulf of Mexico Fact Sheet

http://www.eia.gov/special/gulf_of_mexico/data.cfm

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);

Petrohawk Energy: новости и годовой отчет 2011

26.08.2011
BHP Billiton завершила сделку по покупке производителя сланцевого газа Petrohawk Energy за $12,1 млрд.

Горнорудный гигант BHP Billiton договорился о приобретении за $12,1 миллиарда американской газовой компании Petrohawk Energy Corp, занимающейся перспективным сланцевым газом. Цена представляет собой премию в 65 процентов к последней цене акций Petrohawk. После завершения сделки BHP планирует потратить свыше $40 миллиардов на разработку трех месторождений Petrohawk, расположенных в Техасе и Луизиане, добыча на которых в этом году может составить 158.000 баррелей нефтяного эквивалента в сутки.
http://www.rusenergy.com/ru/news/news.php?id=53474

23.04.2012
Крупнейшая в мире горнодобывающая компания BHP Billiton может объявить об убытках по проектам в области добычи сланцевого газа на сумму около
$5 млрд.
http://lenta.ru/news/2012/04/23/bhp/

По словам аналитика Liberum Capital Ричарда Найтса, 5 млрд долларов убытков означают снижение стоимости сланцевых активов на 25%, и это достаточно оптимистичный вариант, верхняя граница прогноза. Вполне возможно, что оценка стоимости активов BHP в этом сегменте секторе будет сокращена наполовину.
http://www.ukrrudprom.ua/news/BHP_Billiton_terpit_ubitki_po_slantsevim_proektam.html

PETROHAWK ENERGY CORP
10-K
Annual report pursuant to section 13 and 15(d)
Filed on 02/28/2012
Filed Period 12/31/2011

http://www.petrohawk.com/About-Petrohawk/sec-filings.aspx

При цене компании Petrohawk в $12.1 млрд.
и чистой прибыли в год $ 174 млн.
Вложения окупятся через 69.5 лет

eia.gov: Caribbean

The islands of the Caribbean basin are predominantly net energy importers, with the exception of Trinidad and Tobago, which is a major exporter of liquefied natural gas (LNG). Venezuela provides a sizable amount of crude oil and refined products to its Caribbean neighbors at below-market prices and with favorable financing terms under the Petrocaribe initiative. Some islands are important centers for oil refining and storage, due to their proximity to the U.S. market.

Oil Production

Trinidad and Tobago contains the majority of the Caribbean’s oil production. Most of the oil production and exploration is focused offshore, but the government has been encouraging field development onshore as well. In 2011, the country produced 135,000 barrels per day (bbl/d) of oil, of which 92,000 bbl/d was crude oil including lease condensate and the remainder mostly consisted of natural gas liquids (NGLs). Oil production had been falling in the 1980s and 1990s, but was bolstered a decade later when BHP Billiton’s offshore Angostura oil and gas field came online in January 2005. Large oil producers include the state-owned Petroleum Company of Trinidad and Tobago (Petrotrin), BP Trinidad and Tobago and BHP Billiton.
For the past five years oil production has been steadily declining.

Oil consumption in the country is moderate, allowing the country to export a sizable amount of its production. EIA data shows that the United States has been the primary destination, with 76,000 bbl/d of crude oil and refined products exported to the United States in 2011.

Cuba produced about 55,000 bbl/d of oil in 2011, while consuming just over 170,000 bbl/d, making the island a net oil importer. Most of this comes from Venezuela via its Energy Agreement with Cuba, signed in October 2000. Cuba’s oil production has increased in the past two decades, from 13,000 bbl/d in 1988. Most of Cuba’s oil production occurs in the northern Matanzas province, producing a heavy, sour crude that requires specific processing. Much of this production occurs onshore, though there is some offshore production in shallow coastal waters. Cuba’s oil production seems to have largely stabilized in the near term, with any additional increases in production dependent upon the discovery of substantial new reserves (see below).

Offshore Exploration
There has been considerable interest in exploration activities in Cuba’s offshore basins, especially in the Gulf of Mexico. The U.S. Geological Survey (USGS) mean estimate for undiscovered oil reserves in the North Cuba Basin (the basin north and west of the island in the Gulf of Mexico) is 4.6 billion barrels. Cubapetroleo, or Cupet (Cuba’s state-owned petroleum company) estimates that all of Cuba’s offshore basins could contain in excess of 20 billion barrels of undiscovered oil reserves. However, actual exploratory drilling in the area has been, to date, quite limited. In 2011, companies operating in Cuba reported that they plan to drill five exploration wells in ultra-deep waters of the exclusive economic zone (EEZ) in the Gulf of Mexico. Early this year, Repsol began drilling an exploration well located on Block N26 in Cuba’s EEZ.

According to estimates from Bloomberg and Oil and Gas Journal (OGJ), the Caribbean region has a combined 1.6 million bbl/d of nominal nameplate refining capacity. Smaller refineries mostly produce petroleum products for local demand, whereas the larger facilities are geared towards exports to the United States and other markets. Recently, major refineries in the region have found it difficult to compete with new refineries in emerging markets and U.S. refineries powered by cheaper domestically produced natural gas. As a result, two of the largest refineries have shut down in 2012, reducing actual operating capacity by almost 40 percent to about 1 million bbl/d.

The Caribbean is also an important storage location, particularly for crude oil brought in from outside the region. The region has been traditionally viewed as an advantageous storage site since the islands rest between the Americas and sites are in close proximity to transport and refining centers.

Major Oil Storage Centers in the Caribbean

Exports to U.S.

Natural Gas

Trinidad and Tobago
In the early 1990s, the hydrocarbon sector in Trinidad and Tobago transitioned from being oil dominant to a predominantly natural gas-based sector. Natural gas production currently accounts for just over 85 percent of the country’s natural resource base. The construction of the country’s first LNG train in the 1990s and its completion in 1999 facilitated the increase in natural gas production.

Since the Train I LNG facility began to operate in 1999, natural gas production in Trinidad and Tobago has climbed dramatically. In 2010, the country produced 1.5 trillion cubic feet (Tcf) of natural gas, over three times the level seen in 2000. Domestic consumption of natural gas has steadily increased as well, as domestic demand is supported by government subsidies. Consumption grew to 780 billion cubic feet (Bcf) in 2010, just over double the level at the start of the decade.

The country has benefited from substantial foreign investments, with BP Trinidad and Tobago (BPTT) accounting for almost 60 percent of the country’s natural gas production. British Gas is the second leading player in the industry, operating nearly a quarter of the natural gas production in the country. National companies participate in the sector as small shareholders in operations.

Despite the sector’s recent success, the lack of new discoveries coupled with rapid production has led to a sharp decline in proven reserves. In the span of only five years, proven natural gas reserves have declined sharply by over 50 percent, from 25.9 Tcf in 2006 to 14.4 Tcf in 2011, according to Oil & Gas Journal as of January 1, 2012. According to PFC Energy, the country may not be able to sustain current output levels through the end of the decade.

Liquefied Natural Gas

Trinidad and Tobago is the largest supplier of LNG to the United States, and the fifth largest exporter in the world after Qatar, Indonesia, Malaysia, and Australia, according to FACTS Global Energy 2010 figures. EIA data shows that Trinidad and Tobago exported 129 Bcf of natural gas to the United States in 2011, about 37 percent of total U.S. LNG net imports, but less than 1 percent of total U.S. natural gas supply. In the last five years, U.S. LNG imports from Trindad and Tobago have declined by almost one-third, which reflects the general decline in total U.S. LNG imports.

The Atlantic LNG Company, a consortium led by BP, BG, GDF Suez, and the former Repsol-YPF, operates four LNG trains at Point Fortin, on the south-western coast of Trinidad. The first LNG train was completed in March 1999, with subsequent trains completed in 2002, 2003, and 2006. The four trains have capacity to produce a combined 14.8 million metric tons (Mmt) of LNG per year (775 Bcf of re-gasified natural gas).
Trinidad and Tobago also has a substantial petrochemical industry to further monetize natural gas reserves.

http://www.eia.gov/countries/regions-topics.cfm?fips=CR&trk=c
http://www.eia.gov/EMEU/cabs/Caribbean/pdf.pdf

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

Нефть и газ Украины (2005)

Исторические заметки
В начале XIX в. житель села Нагуевичи Дрогобычского района Львовской области Байтала первым в Западной Украине применил дистилляцию нефти. Он сумел кустарным способом (в металлической посудине с приделанным стволом ружья) очистить нефть и получить керосин. Более десятилетия доморощенный химик продавал керосин едва ли не по всей Галиции, чем зарабатывал себе на жизнь. Затем этот метод освоил львовский аптекарь.

Согласно некоторым источникам, старейшими нефтедобывающими районами Предкарпатья являются родина знаменитого украинского писателя И. Франко с. Нагуевичи и окрестности г. Коломыи, где нефть известна с конца XVIII века, а в Старой Соли её добывали в начале 1800-х годов. Развитие капитализма в Австро-Венгерской империи, освоение нового сырья, глубокого бурения (с 1884 г. буровые скважины достигали глубины до 500-600 м) и относительно неглубокое залегание нефтеносных горизонтов способствовали расширению нефтедобычи в Предкарпатье.
Во второй половине XIX и начале ХХ вв. Дрогобыч был одним из центров по переработке озокерита, парафина и нефти. Здесь (и в соседнем Бориславе) в 1900-1910 гг. добывалось около 90% всей нефти Галиции. После присоединения западно-украинских земель к СССР, Дрогобыч на протяжении двух десятилетий (1939-1959 гг.) был столицей одноименной области, со временем объединённой с Львовской.

В 1864 г. на всех прикарпатских промыслах добыто 2 тыс. тонн нефти, в 1886 г. — 29,1 тыс. тонн, а наивысшего уровня добычи нефти Восточная Галиция достигла в 1909 г. — более 2 млн. тонн. По тем временам эти объёмы составляли около 5% мировой добычи жидкого топлива. Освоение нефтедобычи и переработки привела к бурному развитию региона и постепенно перешла под контроль иностранных (преимущественно французских и американских) предпринимателей. Им также принадлежал сопутствующий промысел — добыча и переработка озокерита (спутника нефти), широко используемого для изготовления тогда актуальных свечей и в лечебных целях. В последующие годы добыча нефти и озокерита в Предкарпатье сокращалась.

Днепровско-Донецкая впадина является крупнейшей нефтегазоносной областью Украины. Она заполнена многокилометровыми преимущественно осадочными отложениями девонского (мощность более 4000 м), карбонового (3700 м), пермского (1900 м), триасового (450 м), юрского (650 м), мелового (650 м), палеогенового (250 м) и неогенового (30 м) периодов истории развития Земли. Месторождения нефти и газа здесь приурочены к палеозойским (девонским, карбоновым и пермским) и мезозойским (триасовым) породам, образовавшимся 410-245 млн. лет тому назад.
Предкарпатские месторождения углеводородного сырья несколько моложе — они сформировались на рубеже мезозойской и кайнозойской эр. На протяжении мелового и палеогенового периодов (135-24 млн. лет тому назад) в этом районе накапливались многокилометровые толщи так называемых флишевых пород (созданных слоями песчаников, глин, мергелей и туфовых пород), из которых нефть и газ добывают уже более двух веков

Карта-схема основных нефтегазовых месторождений Украины.

Месторождения нефти: 1 — Старосамборское, 2 — Бориславское, 3 — Долинское, 4 — Прилукское, 5 — Ниновское, 6 — Бургуватовское, 7 — Козиевское, 8 — Решетняковское, 9 — Восточно-Саратское;

Месторождения газа: 10 — Залужанское, 11 — Гриневское, 12 — Косовское, 13 — Солотвинское, 14 — Абазовское, 15 — Семенцовское, 16 — Руденковское, 17 — Перещепинское, 18 — Ефремовское, 19 — Шебелинское, 20 — Приазовское, 21 — Стрелковое, 22 — Джанкойское, 23 — Задорненское, 24 — Глебовское, 25 — Голицынское, 26 — Штормовое.

Нефтегазовые месторождения: 27 — Надворнянское, 28 — Талалаевское, 29 — Гнидинцовское, 30 — Анастасьевское, 31 — Качановское, 32 — Радченковское, 33 — Опошнянское, 34 — Дружелюбовское.

Нефть Украины
Днепровско-Донецкий нефтегазоносный регион сформировался на Левобережье Украины, где в Сумской, Полтавской, Черниговской и Харьковской областях разведаны и эксплуатируются месторождения высокока-чественной нефти. Некоторые из них содержат значительное количество сопутствующего природного газа, используемого для газификации окружающих городов и сёл. В 1970-х годах нефть Левобережной Украины начали добывать с глубины около 3000 м преимущественно фонтанным способом, когда нефть из земных глубин поднимается под давлением нефтяных газов. Нефтегазодобывающие управления функционируют в Сумской (Ахтырское и Качановское месторождения), Черниговской (Гнидинцовское, Прилукское месторождения и др.) и Полтавской (Сагайдацкое, Зачепиловское, Радченковское месторождения и др.) областях.

Нефтегазовые месторождения
В Карпатском нефтегазоносном регионе нефть добывают более двух веков, и её запасы здесь значительно истощены. В 1950-х годах были открыты новые месторождения, которые некоторое время поддерживали относительно высокий уровень добычи «чёрного золота». В настоящее время нефтепромыслы эксплуатируются в районах городов Борислава (Львовская область), Долины и Надворной (Ивано-Франковская область). Масштабы добычи нефти здесь незначительны и в связи с существенным сокращением запасов в последние годы не расширяются.

В Причерноморско-Крымском нефтегазоносном регионе, расположенном на юге страны, разведаны относительно небольшие месторождения нефти. Некоторые специалисты отмечают сходство геологического строения шельфа Чёрного и Азовского морей с богатыми нефтью регионами Персидского залива и Каспийского моря и даже предрекают в недалёком будущем возможность открытия здесь нефтяных запасов мирового значения.

В настоящее время Украина не обеспечивает своих нужд в нефти и нефтепродуктах за счёт собственных ресурсов. Большая их часть поступает из Российской Федерации (Западная Сибирь, Поволжье и др.). Потенциал украинских нефтеперерабатывающих заводов (Лисичанского, Кременчугского, Херсонского, Надворнянского, Дрогобычского, Львовского и Бердянского), ориентированных в том числе и на привозное сырьё, уже много лет не используется на полную мощность.

Газ Украины
В отличие от нефти масштабы запасов и добычи природного газа в Украине значительно крупнее. Газовая промышленностьУкраины зародилась на Прикарпатье в 1920-е годы. В 1940 г. в Предкарпатье сосредоточивалось 87% добычи газа всего Советского Союза. Основными газовыми промыслами были Угерско-Бильче-Волицкий (здесь в середине 1960-х годов добывалось почти 60%прикарпатского газа), Рудковско-Ходовицкий, Опарский, Дашавский, Калушский и Косовский участки (расположенные на территории Львовской и Ивано-Франковской областей). Здесь была создана система газопроводов, наиболее протяжённые из которых — Дашава — Киев — Москва, Рудки — Минск — Вильнюс — Рига и др.
Постепенно участие западно-украинского региона в газодобыче сокращалась, за счёт быстрого освоения углеводородных месторождений, расположенных в центральной и восточной части СССР. В 1951 г. в Предкарпатье добывали 42,2%, в 1957 г. — 26,4%, в 1965 г. — около 10% газа Советского Союза. В 1965 г. добыча газового топлива на западе Украины составлял около 19 млрд. м3. Современная добыча газа в Предкарпатье, сосредоточенная на месторождениях Ивано-Франковской области, незначительна и составляет менее 20% всей газодобычи Украины.

В 1960-е годы газовая промышленность начала интенсивно развиваться в пределах Днепровско-Донецкой впадины. Основные месторождения газа сосредоточены здесь в Полтавской и Харьковской областях. Наиболее известное из них — Шебелинское, откуда в своё время в разных направлениях были проложены газопроводы: Шебелинка — Харьков, Шебелинка — Полтава — Киев, Шебелинка — Днепропетровск — Кривой Рог — Одесса — Кишинев,Шебелинка — Белгород — Курск — Брянск — Москва.

Значительные месторождения природного газа открыты на юге страны, в равнинной части Крымского полуострова и прилегающих к ней участках шельфа Чёрного и Азовского морей.Сооружён газопровод Глебовка — Симферополь — Севастополь с ответвлением к Ялте, Евпатории и Сакам.

По мнению ряда специалистов, Украина имеет большие перспективные площади, где возможно открытие месторождений углеводородного сырья (особенно газа) мирового масштаба. Прежде всего, такие предположения и надежды (о наибольших в мире запасах природного газа) относятся к северной (украинской) части шельфа Чёрного моря. В качестве одного из аргументов приводится факт, что Чёрное море — это единственный морской водоём в мире, где толща воды от дна до глубин 150-50 м заполнена сероводородом. Высказываются догадки, что под дном моря накопилось огромное количество природного газа, который по разломам проходит к воде и насыщает её и дело лишь за малым — научиться его оттуда извлекать.
http://neftegaz.ru/analisis/view/7677/
http://www.photoukraine.com/russian/articles?id=111

Usgs assessment: Undiscovered Oil Resources in the Bakken Formation, Williston Basin Province, 2008

Assessment of Undiscovered Oil Resources in the Devonian-Mississippian Bakken Formation, Williston Basin Province, Montana and North Dakota, 2008

Using a geology-based assessment methodology, the U.S. Geological Survey estimated mean undiscovered volumes of 3.65 billion barrels of oil, 1.85 trillion cubic feet of associated/dissolved natural gas, and 148 million barrels of natural gas liquids in the Bakken Formation of the Williston Basin Province, Montana and North Dakota.

Introduction
The U.S. Geological Survey (USGS) completed an assessment of the undiscovered oil and associated gas resources of the Upper Devonian–Lower Mississippian Bakken Formation in the U.S. portion of the Williston Basin of Montana and North Dakota and within the Williston Basin Province (fig. 1). The assessment is based on geologic elements of a total petroleum system (TPS) that include (1) source-rock distribution, thickness, organic richness, maturation, petroleum generation, and
migration; (2) reservoir-rock type (conventional or continuous), distribution, and quality; and (3) character of traps and time of formation with respect to petroleum generation and migration.
Detailed framework studies in stratigraphy and structural geology and the modeling of petroleum geochemistry, combined with historical exploration and production analyses, were used to aid in the estimation of the undiscovered, technically recoverable oil and associated gas resources of the Bakken Formation in the United States. Using this framework, the USGS defined a Bakken-Lodgepole TPS (fig. 1) and seven assessment units (AU) within the TPS. For the Bakken Formation, the undiscovered oil and associated gas resources within six of these assessment units were quantitatively estimated (fig. 2, table 1). A conventional AU within the Lodgepole Formation was not assessed.

Bakken Formation and Bakken-Lodgepole Total Petroleum System
The Upper Devonian–Lower Mississippian Bakken Formation is a thin but widespread unit within the central and deeper portions of the Williston Basin in Montana, North Dakota, and the Canadian Provinces of Saskatchewan and Manitoba. The formation consists of three members: (1) lower shale member, (2) middle sandstone member, and (3) upper shale member. Each succeeding member is of greater geographic extent than the underlying member. Both the upper and lower shale members are organic-rich marine shale of fairly consistent lithology; they are the petroleum source rocks and part of the continuous reservoir for hydrocarbons produced from the Bakken Formation. The middle sandstone member varies in thickness, lithology, and petrophysical properties, and local development of matrix porosity enhances oil production in both continuous and conventional Bakken reservoirs. Within the Bakken-Lodgepole TPS, the upper and lower shale members of the Bakken Formation are also the source for oil produced from reservoirs of the Mississippian Lodgepole Formation.

Geologic Model and Assessment Units
The geologic model used to define AUs and to assess the Bakken Formation resources generally involves thermal maturity of the Bakken shale source rocks, petrophysical character of the middle sandstone member, and structural complexity of the basin. Most important to the Bakken-Lodgepole TPS and the continuous AUs within it are (1) the geographic extent of the Bakken Formation oil generation window (fig. 2), (2) the occurrence and distribution of vertical and horizontal fractures, and (3) the matrix porosity within the middle sandstone member. The area of the oil generation window for the Bakken continuous reservoir was determined by contouring both hydrogen index and well-log resistivity values of the upper shale member, which is youngest and of greatest areal extent.

The area of the oil generation window for the Bakken Formation was divided into five continuous AUs: (1) Elm Coulee–Billings Nose AU, (2) Central Basin–Poplar Dome AU, (3) Nesson–Little Knife Structural AU, (4) Eastern Expulsion Threshold AU, and (5) Northwest Expulsion Threshold AU. A sixth hypothetical conventional AU, a Middle Sandstone Member AU, was defined external to the area of oil generation.

Resource Summary
The USGS assessed undiscovered oil and associated gas resources in five continuous (unconventional) AUs and one conventional AU for the Bakken Formation (fig. 2; table 1). For continuous oil resources, the USGS estimated a total mean resource of 3.65 billion barrels of oil, which combines means of 410 million barrels in the Elm Coulee–Billings Nose AU, 485 million barrels in the Central Basin–Poplar Dome AU, 909 million barrels in the Nesson–Little Knife Structural AU, 973 million barrels in the Eastern Expulsion Threshold AU, and 868 million barrels in the Northwest Expulsion Threshold AU. A mean resource of 4 million barrels was estimated for the conventional Middle Sandstone Member AU. The assessment of the Bakken Formation indicates that most of the undiscovered oil resides within a continuous composite reservoir that is distributed across the entire area of the oil generation window (fig. 2) and includes all members of the Bakken Formation. At the time of this assessment, only a limited number of wells have produced from the Bakken continuous reservoir in the Central Basin–Poplar Dome AU, the Eastern Expulsion Threshold AU, and the Northwest Expulsion Threshold AU. Therefore, there is significant geologic uncertainty in these estimates, which is reflected in the range of estimates for oil (table 1).

http://pubs.usgs.gov/fs/2008/3021/
http://pubs.usgs.gov/fs/2008/3021/pdf/FS08-3021_508.pdf

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