Chapter 7 Hydrocarbon finds in the Arctic basins: discovery history, discovered resources and petroleum systems (original) (raw)
Related papers
Chapter 1 An overview of the petroleum geology of the Arctic
Geological Society, London, Memoirs, 2011
Nine main petroleum provinces containing recoverable resources totalling 61 Bbbl liquids+269 Bbbloe of gas are known in the Arctic. The three best known major provinces are: West Siberia–South Kara, Arctic Alaska and Timan–Pechora. They have been sourced principally from, respectively, Upper Jurassic, Triassic and Devonian marine source rocks and their hydrocarbons are reservoired principally in Cretaceous sandstones, Triassic sandstones and Palaeozoic carbonates. The remaining six provinces except for the Upper Cretaceous–Palaeogene petroleum system in the Mackenzie Delta have predominantly Mesozoic sources and Jurassic reservoirs. There are discoveries in 15% of the total area of sedimentary basins (c.8×106km2), dry wells in 10% of the area, seismic but no wells in 50% and no seismic in 25%. The United States Geological Survey estimate yet-to-find resources to total 90 Bbbl liquids+279 Bbbloe gas, with four regions – South Kara Sea, Alaska, East Barents Sea, East Greenland – domin...
Preliminary Geospatial Analysis of Arctic Ocean Hydrocarbon Resources
2008
Ice over the Arctic Ocean is predicted to become thinner and to cover less area with time (NASA, 2005). The combination of more ice-free waters for exploration and navigation, along with increasing demand for hydrocarbons and improvements in technologies for the discovery and exploitation of new hydrocarbon resources have focused attention on the hydrocarbon potential of the Arctic Basin and its margins. The purpose of this document is to 1) summarize results of a review of published hydrocarbon resources in the Arctic, including both conventional oil and gas and methane hydrates and 2) develop a set of digital maps of the hydrocarbon potential of the Arctic Ocean. These maps can be combined with predictions of ice-free areas to enable estimates of the likely regions and sequence of hydrocarbon production development in the Arctic. In this report, conventional oil and gas resources are explicitly linked with potential gas hydrate resources. This has not been attempted previously and is particularly powerful as the likelihood of gas production from marine gas hydrates increases. Available or planned infrastructure, such as pipelines, combined with the geospatial distribution of hydrocarbons is a very strong determinant of the temporalspatial development of Arctic hydrocarbon resources. Significant unknowns decrease the certainty of predictions for development of hydrocarbon resources. These include: 1) Areas in the Russian Arctic that are poorly mapped, 2) Disputed ownership: primarily the Lomonosov Ridge, 3) Lack of detailed information on gas hydrate distribution, and 4) Technical risk associated with the ability to extract methane gas from gas hydrates. Logistics may control areas of exploration more than hydrocarbon potential. Accessibility, established ownership, and leasing of exploration blocks may trump quality of source rock, reservoir, and size of target. With this in mind, the main areas that are likely to be explored first are the Bering Strait and Chukchi Sea, in spite of the fact that these areas do not have highest potential for future hydrocarbon reserves. Opportunities for improving the mapping and assessment of Arctic hydrocarbon resources include: 1) refining hydrocarbon potential on a basin-by-basin basis, 2) developing more realistic and detailed distribution of gas hydrate, and 3) assessing the likely future scenarios for development of infrastructure and their interaction with hydrocarbon potential. It would also be useful to develop a more sophisticated approach to merging conventional and gas hydrate resource potential that considers the technical uncertainty associated with exploitation of gas hydrate resources. Taken together, additional work in these areas could significantly improve our understanding of the exploitation of Arctic hydrocarbons as ice-free areas increase in the future. iv Key Findings Overall conclusions from this study are as follows: • Geographic areas with the highest hydrocarbon potential are Arctic Alaska, eastern Greenland, the East and West Barents basins in Norway and Russia, and the South Kara/Yamal basins of Russia. • Global interest in Arctic hydrocarbon resources is dynamic, increasing dramatically as global demand for hydrocarbon resources increases. • The Arctic contains ~13% of global undiscovered oil, ~30% of global undiscovered conventional natural gas, and as much as one third of global gas hydrate. • Geospatial analysis of marine Arctic hydrocarbon resources can be linked to progressively icefree areas enabling estimation of possible development areas. • The rate and location of future hydrocarbon exploration activities will depend not only on richness of hydrocarbon potential, Arctic ice, and potential for supporting infrastructure, but also on the opening of areas by various governments for industry exploration.
In the last 20 years, over a hundred HC fields were discovered which reserves exceed 500 million barrels of oil equivalent. Almost half of the gas reserves were discovered at shallow sea depths. Large gas reserves were found on the shelf of Iran and Indo-nesia. Oil giants were mainly discovered in the basins on the passive margins of West Africa, the Gulf of Mexico, Brazil, and the Caspian Sea. It is assumed that about 100 billion tons of hydrocarbons in oil equivalent are concentrated on the continental shelf of the Russian Federation (Kaminsky et al., 2006). However, the share of oil accounts for about 13%; the rest are gas resources. The main oil-and-gas resources are recorded on the largest Arctic shelf with major sedimentary basins containing oil and gas; this is about 80% of the total resources of the shelf. Generally , the geological and geophysical exploration maturity of the Russian shelf is low compared to the developed oil-and gas-producing areas of the world and is highly irregular. Seismic and drilling exploration maturity of the Russian shelf is tens and hundreds of times lower than the exploration maturity of the foreign water areas in the USA, Norway, and the United Kingdom. On the entire vast shelf of Russia with an area of about 6.5 million km 2 , by 2010, there were only 1,345,000 line km of seismic surveying , that is, the density is 0.2 km/km 2. For comparison, in the North Sea, the density of seismic surveying exceeds 4 km/km 2. Overall, on the Russian shelf, 252 wells were drilled including the parametric and wildcat wells. The best studied shelf areas are the southern seas, the shelf of Sakhalin, and the southern Barents and Kara Seas. The northern Barents and Kara Seas and the entire East Arctic shelf were not covered by the orientation-parametric drilling (Laptev, East Siberian, and Chukchi Seas). There the network of the seismic lines is rare or almost absent, and the general level of the geological and geophysical exploration maturity is rather low. The East Siberian Sea is the least-studied sea in the Russian Arctic. The specific feature of this area with a shallow depth and a thick ice cover is the necessity of using special under-ice equipment for its development. The geological structure of a number of shelf basins in the Arctic seas of Russia is in many respects similar to that of the passive margins of the Atlantic Ocean or the
Oil and gas resources of the Arctic Alaska Petroleum Province
Professional Paper
The Arctic Alaska Petroleum Province, encompassing all the lands and adjacent Continental Shelf areas north of the Brooks Range-Herald arch, is one of the most petroleum-productive areas in the United States, having produced about 15 billion bbl of oil. Seven unitized oil fields currently contribute to production, and three additional oil fields have been unitized but are not yet producing. Most known petroleum accumulations involve structural or combination structuralstratigraphic traps related to closure along the Barrow arch, a regional basement high, which has focused regional hydrocarbon migration since Early Cretaceous time. Several oil accumulations in stratigraphic traps have been developed in recent years. In addition to three small gas fields producing for local consumption, more than 20 additional oil and gas discoveries remain undeveloped. This geologically complex region includes prospective strata within passive-margin, rift, and foreland-basin sequences. Oil and gas were generated from multiple source rocks throughout the region. Although some reservoired oils appear to be derived from a single source rock, evidence for significant mixing of hydrocarbons from multiple source rocks indicates a composite petroleum system. Both extensional and contractional tectonic structures provide ample exploration targets, and recent emphasis on stratigraphic traps has demonstrated a significant resource potential in shelf and turbidite sequences of Jurassic through Tertiary age. Recent estimates of the total mean volume of undiscovered resources in the Arctic Alaska Petroleum Province by the U.S. Geological Survey and U.S. Minerals Management Service are more than 50 billion bbl of oil and natural-gas liquids and 227 trillion ft 3 of gas, distributed approximately equally between Federal offshore and combined onshore and State offshore areas.
Resources, 2021
The Timan–Pechora oil and gas province (TPP), despite the good geological and geophysical knowledge of its central and southern regions, remains poorly studied in the extreme northwestern part within the north of the Izhma–Pechora depression and the Malozemelsk–Kolguev monocline, and in the extreme northeast within the Predpaikhoisky depression. Assessing the oil and gas potential of the Lower Paleozoic part of the section is urgently required in the northwestern part of the TPP, the productivity of which has been proven at the border and in the more eastern regions of the province (Pechora–Kolva, Khoreyverskaya, Varandei–Adzva regions), that have been evaluated ambiguously. A comprehensive interpretation of the seismic exploration of regional works was carried out, with the wells significantly clarifying the structural basis and the boundaries of the distribution of the main seismic facies’ complexes. The capabilities of potentially oil- and gas-producing strata in the Silurian–Low...
Meso-Neoproterozoic petroleum systems of the Eastern Siberian sedimentary basins
Precambrian Research, 2015
The elements of the petroleum systems of the Siberian platform have been formed in the course of geological evolution in Meso-and Neoproterozoic time and correspond to the supercontinent stage from assembly of Paleo-Mesoproterozoic Columbia to break-up of Neoproteorzoic Rodinia. Several large sedimentary basins were established within the Siberian craton during the Riphean. A number of passive continental margin basins (the Turukhansk, Cis-Patom basins and others) developed on the southern, western, and, probably, northern craton peripheries. Several other basins, such as the Irkineeva-Vanavara, Kotuy, Anabar-Kureika, and Udzha basins, were entirely intracratonic. The structural patterns of these basins and their petroleum systems were essentially affected by Baikalian orogeny events with intensive dislocations and erosion of Riphean series, especially along the margins of the continent. As a result, hydrocarbon accumulations formed by the source rocks, which have realized their potential in Riphean within the margin basins, were, most likely, completely destroyed. Vendian and Lower Cambrian deposits were the main source for present day oil fields of the central and northern parts of the Nepa-Botuoba Anteclise and the Turukhansk Uplift. The Upper Riphean source rocks of the intracratonic basins, on the contrary, are unlikely to be affected by the significant pre-Vendian erosion and, thus, could be a source for the oil fields of the Yurubchen-Tokhomo Zone and the Katanga Saddle. Such difference in petroleum system evolution for different basins is also supported by results of oil-source rock correlations based on biomarker studies. A new mega-cycle of formation of the sedimentary cover started on the Siberian platform in the Vendian (Ediacaran). The initial fabric of all the main structural elements of the platform was established at this time. The large Vendian depressions (the "prototypes" of Paleozoic Kureika and Cis-Sayan-Yenisei syneclises and Cis-Patom Trough) were areas of mainly marine sedimentation where the high potential hydrocarbon source series could be deposited. Large elevated areas served as a terrigenous provenance in the Early Vendian resulting in a large amount of clastic material deposited along their flanks. The most promising areas for new discoveries of hydrocarbon fields are in the slopes of the Baikit, Nepa-Botuoba and Anabar anticlises faced towards the Kureika Syneclise.
Petroleum potential in western Sverdrup Basin, Canadian Arctic Archipelago
Bulletin of Canadian Petroleum Geology, 2000
One hundred nineteen wells drilled in the Mesozoic structural play of western Sverdrup Basin resulted in one of the technically most successful Canadian petroleum exploration efforts discovering 19 major petroleum fields, including 8 crude oil and 25 natural gas pools. The total original in-place reserve of 294 x 10 6 m 3 crude oil and 500 x 10 9 m 3 natural gas at standard conditions is about equivalent to 10% and 23%, respectively, of the remaining national reserves of conventional crude oil and natural gas. Using and comparing both discovery process and volumetric petroleum assessment methods the petroleum resource can be confidently estimated to be between 540 x 10 6 m 3 and 882 x 10 6 m 3 original in-place crude oil, and 1242 x 10 9 m 3 to 1423 x 10 9 m 3 original in-place natural gas at standard conditions. The total resource is expected to occur in approximately 93 fields, containing about 25 crude oil pools and 117 natural gas pools larger than or equal to the smallest oil and gas pools discovered. Both exploration data and resource assessment results suggest that the largest natural gas pools were found efficiently, and that 9 of the 17 largest gas pools are now discovered. The two largest natural gas pools are believed to have been discovered in the Drake and Hecla fields. There remain undiscovered 17 or 18 natural gas pools larger than or equal to 10 x 10 9 m 3. In contrast, oil pools, of which no significant discoveries were made during the first nine years of exploration, appear to have been found inefficiently, if not randomly. Although five of the ten largest crude oil pools have been discovered, there remain undiscovered between 7 and 9 crude oil pools expected to have individual resources greater than or equal to 10 x 10 6 m 3. Among these is an undiscovered oil pool predicted to be greater than or equal to 100 x 10 6 m 3, similar in size to the largest discovered crude oil pool at Cisco in the Awingak Formation. The ability to compare discovery process and volumetric methods of assessment increases confidence in these results, while illustrating the relative merits of each technique. The Geo-anchored discovery process model analyzes oil and gas pools simultaneous while it independently and objectively estimates numbers of accumulations, without reference to subjective exploratory risk evaluations or efficiencies of geophysical prospecting. This suggests that similar assessments could be improved by: a) the use of the Multivariate Discovery Process Model to obtain unbiased distributions of reservoir volumetric parameters, b) the simultaneous estimation of oil and gas pools numbers using the Geo-anchored method, and c) the validation of assessments by comparing the predictions of different methods.
A reconnaissance study of potential hydrocarbon source rocks of Paleozoic to Cenozoic age from the highly remote New Siberian Islands Archipelago (Russian Arctic) was carried out. 101 samples were collected from outcrops representing the principal Paleozoic-Cenozoic units across the entire archipelago. Organic petrological and geochemical analyses (vitrinite reflectance measurements, Rock-Eval pyrolysis , GC-MS) were undertaken in order to screen the maturity, quality and quantity of the organic matter in the outcrop samples. The lithology varies from continental sedimentary rocks with coal particles to shallow marine carbonates and deep marine black shales. Several organic-rich intervals were identified in the Upper Paleozoic to Lower Cenozoic succession. Lower Devonian shales were found to have the highest source rock potential of all Paleozoic units. Middle Carboniferous-Permian and Triassic units appear to have a good potential for natural gas formation. Late Mesozoic (Cretaceous) and Cenozoic low-rank coals, lignites, and coal-bearing sandstones also display a potential for gas generation. Kerogen type III (humic, gas-prone) dominates in most of the samples, and indicates deposition in lacustrine to coastal paleoenvironments. Most of the samples (except some of Cretaceous and Paleogene age) reached oil window maturities, whereas the Devonian to Carboniferous units shared a maturity mainly within the gas window.