MLA-SEM analyses can quantitatively define the modal mineralogy of detrital components in a variety of sample material including offshore well cuttings such that the possible source(s) of the detrital material might be ascertained. The MLA data can be queried for combinations of detrital minerals that might reflect a specific source terrane (e.g., igneous suite, metamorphic complex, etc .). In some cases, minerals may be identified that might have a unique sediment source region. The MLA data can also be examined to evaluate whether trends of changing detrital mineral compositions through time (i.e., stratigraphically) can be documented that may reflect regional changes in the level of tectonism, potential unroofing a given sediment source area, and/or shifts between sediment source areas. The MLA analyses can be used to produce maps of radiometrically dateable mineral phases within a given sample, that might be used to derive radiometric dates.

Permafrost in Arctic is one of the most important factors when exploration and production of gas and gas condensate fields due to its sensitivity to any technogenic (humane-made) impact or climatic change. Exploration and production procedures in the areas with instable permafrost cause such processes like thermokarst, thermoerosion, flooding, frost heave, surface subsidence, shallow gas blowouts et al. These processes require their forecast and prevention when gas field development designing. However permafrost sometimes is very different in its properties even within area of one production well cluster, so careful study of permafrost behavior is needed before and during gas production. Russian experience of gas field development at complicated permafrost (geocryologic) conditions of Yamal peninsula (Kara Sea shore) is presented.

Canada has vast oil shale resources (estimated at 180 billion barrels proved recoverable oil shale reserve) similar to the estimated Canadian oil reserve of 179 billion barrels. These deposits consist of various oil shale types deposited in terrestrial, lake, and marine environments. These Canadian oil shale deposits are assessed under auspices of Canada/Israel Industrial Research and Development Program and Geological Survey of Canada for their possible use for extraction of hydrocarbon. The organic rich oil shale deposit with thickness of >60m are suitable for this purpose. This paper reviews the oil shale deposits of Arctic Canada from Ordovician to Carboniferous age. Ordovician shale of Baffin Island, Southampton Island, and Akpatok Islands consist of organic lean, calcareous deposits with variable thickness. The Devonian cannel and canneloid deposit of Melville Island, Arctic Canada are liptinitic rich, but are thin and therefore have low mining potential. The Lower Carboniferous Emma Fjord oil shale deposit is the only promising deposit for in-situ extraction of hydrocarbon from Arctic Canada at present.

The Arctic is said to contain an unexplored potential corresponding to about 13% and 30% of the remaining unexplored oil and gas resources according to the USGS Arctic study in [ 2 ], and USGS indicates that 80% of this will come from offshore. The potential is indisputably there, however the survey does not address the current industry activity or likely investment levels over time required to explore and develop offshore Arctic fields. In this paper we will discuss a method systematically combining facts and modelling results to derive likely discovered volumes year by year, and the current and future exploration activity required to unlock the arctic resources. We will briefly describe a set of steps in this approach: Introduction to how we can systematically collect information about discoveries, acreage positions and intelligence about likely exploration wells. How systematic methods for data collection can be combined with sensible models or analytical guesswork to allow decision makers to see a clear trend improving their near time industry decisions. Based on collected data we will make a review of the players and their exploration acreage positions and look at likely exploration wells and activities in the near future. Via GIS system and sedimentary basin maps the results will be broken down according to sedimentary basins or geographies like countries and provinces. We have integrated all the above data into a comprehensive database allowing us to analyze various aspects of the results. Several analyses of the data will be shown and results will be discussed. The resulting database is core for the many types of strategy analysis that Rystad Energy can provide, which all are originating from consistently collecting and organizing data. There is much interest in the oil and gas opportunities in the Arctic. However, not too much is actually happening and there are challenges to overcome. Any activities must be driven by companies and their interests. The only way to get a realistic picture of how and when Arctic will develop is to follow closely which plans the companies commit to, and extract from this the likely activities.

Extended Abstract Three significant source rocks are present beneath much of the Alaska NorthSlope (Fig. 1), the Triassic Shublik Formation, the lower part of theJurassic-Lower Cretaceous Kingak Shale, and the " Brookian shale" that includesthe Cretaceous pebble shale unit and Cretaceous-Lower Tertiary Hue Shale. Although these source rocks are known to have generated oil and gas thatmigrated into conventional accumulations, including the super-giant Prudhoe Bayfield, the first attempt to produce hydrocarbons directly from the three sourcerocks was initiated in 2012. The Shublik Formation contains a mixture of Type I and IIS kerogen, and oilin conventional accumulations sourced from the Shublik is of relatively lowgravity (23-39° API) and high sulfur (more than 1.5 percent). In contrast, theKingak and Brookian source rocks contain a mixture of Type II and III kerogen, and oil in conventional accumulations sourced from those rocks is of relativelyhigh gravity (35-42° API) and low sulfur (less than 0.3 percent). These threesource rocks occur at depths that range from less than 3,000 feet along theBarrow Arch to more than 20,000 feet in the Brooks Range foothills. Over thatrange of depth, thermal maturity of the source rocks grades from the onset ofoil generation along the Barrow Arch, through the oil window, and well into thedry gas window in the south (Fig. 1). Shale-oil and shale-gas assessment units (AUs) - areas where organic richfacies are inferred to be in the oil or gas window, respectively - weredelineated for each source rock (Figs. 2, 3, 4) based on empirical thermalmaturity data and regional modeling (Houseknecht et al., 2012a). Both Shublikand Brookian source rocks include rock types that are brittle and in whichnatural fractures are common. Brittle lithologies include limestone, phosphaticlimestone, sandstone, siltstone, and chert in the Shublik and very-fine-grainedsandstone, siltstone, concretionary carbonate, and silicified tuff in theBrookian. In contrast, the Kingak source rock is mostly clay shale that deformsplastically, and brittle lithologies generally are absent. These petroleumsystem elements (organic matter content, thermal maturity, and brittlelithology) were among the factors considered in estimating the probability thatoil and gas can be technically recovered from the source rocks, with results of95 percent probability for the Shublik, 90 percent for the Brookian, and 40percent for the Kingak (Houseknecht et al., 2012b). Maps of petroleum system elements were used to evaluate spatial variabilityin source rock character. A map of mostly transgressive facies in the ShublikFormation (Fig. 2) delineates areas that may contain highest organic content, based on published relations between transgressive facies and total organiccarbon (TOC) in the formation (Hulm, 1999; Robison and Dawson, 2001; Peters etal., 2006; Kelly et al., 2007). The Shublik is absent owing to non-depositionat Pt. Barrow and transgressive facies in the formation thicken basinward in aradial pattern, reaching maximum values greater than 200 ft in northeastern andwestern NPRA (Fig. 2). East of NPRA, the Shublik thins depositionally towardsPrudhoe Bay, and is truncated completely farther east beneath the LowerCretaceous unconformity (Fig. 2). In northcentral NPRA, Shublik transgressivefacies are not only relatively thin (less than 100 ft) but also containgenerally low organic carbon content (Fig. 2) and low values of interpretedoriginal hydrogen index (Peters et al., 2006). Both the TOC content (Fig. 2)and interpreted original hydrogen index (HI) increase abruptly in the vicinityof Teshekpuk Lake in northeastern NPRA, and both parameters are relatively higheastward to the Shublik truncation edge beneath the eastern North Slope(Peterset al., 2006). We infer that the best oil potential in the Shublik occurswithin the shale-oil AU (defined by thermal maturity) from Teshekpuk Lakeeastward (Fig. 2). We infer good gas potential in the Shublik in the shale-gasAU across much of the North Slope (Fig. 2). The Kingak Shale is divided into three map areas (Fig. 3) on the basis ofseismic and well-log character (Houseknecht and Bird, 2004). A broad area innorth-central NPRA contains a series of progradational shelf sequences, withinwhich Kingak source-rock facies are mostly limited to thin transgressivedeposits characterized by low values of TOC and HI. To the east and southeast, shelf deposits are absent and the lower Kingak comprises basinal condensedshale that has higher values of TOC and HI (Houseknecht and Bird, 2004; Peterset al., 2006). The Kingak is poorly known beneath the southwestern North Slopebecause of an absence of well penetrations (Fig. 3). We infer that the best oiland gas potential in the Kingak occurs within the shale-oil and shale-gas AUs, respectively, and basinward from the shelf sequences in north-central NPRA(Fig. 3). However, the paucity of brittle facies in the lower Kingak Shale maylimit its reservoir quality everywhere. A map of the Brookian sequence showing thickness of net high gamma-ray (HGR)log response (cumulative thickness of gamma-ray response greater than 150 API)in the oil window (based on thermal maturity) delineates thermally mature areasthat may contain higher organic content (e.g., Schmoker, 1981). The map of netHGR displays complex patterns that reflect regional accommodation, localerosion beneath sequence-bounding unconformities, and thermal maturitypatterns. In general, net HGR thickens to the east (Fig. 4); this regionaltrend is consistent with patterns of TOC and interpreted original HI (Peters etal., 2006). Brittle facies closely associated with HGR intervals in theBrookian are more common east of NPRA. We therefore infer that the best oilpotential in the Brookian shale occurs in areas that contain more than 100 ftof HGR in the oil window, east of NPRA and west of ANWR (Fig. 4). The best gaspotential likely occurs within the shale-gas AU, in areas adjacent to the TransAlaska Pipeline System where the largest thickness of HGR is observed (Fig. 4). The USGS in 2012 completed the first-ever assessment of technicallyrecoverable shale-oil and shale-gas resources in northern Alaska. Aggregateestimates for all three source rocks range from 0 to 2 billion barrels of oiland 0 to 80 trillion cubic feet of gas (TCFG), with the ranges representing a95- to 5-percent probability of occurrence (Houseknecht et al., 2012b). Estimates for each source rock system include 0 to 928 million barrels of oil(MMBO) and 0 to 72 TCFG for the Shublik, 0 to 955 MMBO and 0 to 4 TCFG for theBrookian, and 0 to 117 MMBO for the Kingak (gas was not quantitatively assessedfor the Kingak). In all cases, the zero value at the 95-percent probabilityreflects the application of play-level risk. The Shublik is estimated tocontain the greatest oil and gas resource potential per unit area, with valuesthat rank among the top few source-rock systems in the United States.

Introduction Arctic oil and gas have been E&P targets for several decades. However, the petroleum potential of this region is far from being fully understood. Assessments of undiscovered petroleum of the Arctic indicates that it holds asignificant amount of the world's undiscovered gas and oil (Gautier et al.,2009) and recent assessments also indicate the potential of shale resourceplays for oil and gas, for example on the Alaska North Slope (Houseknecht,2012). In this paper we will present workflows for efficient petroleumexploration risk and resource assessments for both conventional andunconventional resources in the Arctic, and we will also present a recentsuccessful exploration campaign which resulted in the first technically provenshale oil play on the Alaska North Slope. This will demonstrate the value of applying the same approach to otherArctic petroleum provinces, resulting in a) increased understanding of existingand hypothetical petroleum systems, b) more accurate assessments of theremaining potential hydrocarbon resources on a regional scale, c) more accuratescreening of exploration opportunities and assessments of exploration risk, andd) provide an efficient, geology based and auditable approach to petroleumexploration risk and resource assessments. Petroleum Systems Modeling Using all of the available G&G data to create multi-dimensionalpetroleum systems models is the only technology that can integrate andprocess all of the available geologic data in order to enable a completeassessment of the potential value of the hydrocarbon resources. The reason isthat it adds the results of a geologic process based analysis to the existingG&G data to provide critical additional information. For example, it is theonly method that enables hydrocarbon properties and oil vs. gas distributionsto be understood and predicted, which is a critical issue for thedifferentiation of shale resource plays into oil and gas prone targets. Petroleum systems modeling enables the dynamics of sedimentary basins andtheir associated fluids to be evaluated to see if past conditions were suitablefor generation of hydrocarbons to fill potential reservoirs and to bepreserved. Applications include predictions of the extent and timing ofpetroleum generation from source rocks, reconstructions of basin architecture, migration pathways, locations of potential traps and accumulations, andanalysis of risk based on various geologic, geochemical, or fluid-flowassumptions (Magoon and Dow, 1994; Peters et al., 2009). The technology usesdeterministic computations to forward simulate (i.e. from the geologic past tothe present) the thermal history of a basin and the associated generation, migration, and accumulation of petroleum (Hantschel and Kauerauf, 2009; Peters,2009). These results are then combined with statistical assessments to enableimproved assessments of the petroleum resources, therefore enabling the entiresequence of analyses from petroleum exploration risk to resource assessments tobe supported.

Abstract Among the greatest uncertainties in future energy supply is the amount of oil and gas yet to be found in the Arctic. Using a probabilistic geology-based methodology, the U.S. Geological Survey has assessed the area north of the Arctic Circle. The Circum-Arctic Resource Appraisal (CARA) consists of three parts: Mapping the sedimentary sequences of the Arctic (Grantz and others 2009), Geologically based estimation of undiscovered technically recoverable petroleum (Gautier and others 2009, discussed in this presentation) and Economic appraisal of the cost of delivering the undiscovered resources to major markets (also reported at this conference by White and others). We estimate that about 30% of the world's undiscovered gas and about 13% of the world's undiscovered oil may be present in the Arctic, mostly offshore under less than 500m of water. Billion BOE-plus accumulations of gas and oil are predicted at a 50% probability in the Kara Sea, Barents Sea, offshore East and West Greenland, Canada, and Alaska. On a BOE basis, undiscovered natural gas is three times more abundant than oil in the Arctic and is concentrated in Russian territory. Oil resources, while critically important to the interests of Arctic countries, are probably not sufficient to significantly shift the current geographic patterns of world oil production. Introduction The U.S. Geological Survey (USGS) has completed an assessment of the yet-to-find, technically recoverable petroleum in the Arctic. The Circum-Arctic Resource Appraisal (CARA) provides probabilistic estimates of the numbers, sizes, and aggregate volumes of oil, gas, and natural gas liquids in undiscovered accumulations (Gautier et al. 2009). Most discoveries will probably be made on the continental shelves, under less than 500 meters of water. The CARA is a geologically study of the potential for new discoveries of conventional oil and/or gas in accumulations larger than 50 million barrels of oil or 300 billion cubic feet of natural gas north of the Arctic Circle. So-called unconventional resources such as coal bed methane, heavy oil and bitumen, and gas hydrates were not included in the study. Before the assessment could be conducted, it was necessary to compile a consistent map of the sedimentary basins of the Arctic, delineated according to geologic age, tectonic history, thickness of sedimentary strata, and structural style (Grantz et al. 2009). Using the new map, the Arctic was subdivided into 69 geologically defined subsets called Assessment Units (AUs); the AU boundaries are available as digital shape files online (USGS 2009).

Abstract The Shtokman Gas Condensate Field (SGCF) is located 610 km from Murmansk in the Barents Sea. The water depth at location is around 340 m. The offshore facilities of the SGCF Phase 1 development will include ice-resistant ship shape disconnectable turret moored floating platform (FP). The design of the hull has been driven to be inherently safe, to resist the environmental condition, and minimize risk of repair over the 50 years operating duration. Introduction The SGCF is located 610km from Murmansk in the Barents Sea, around 73º latitude North and 44º longitude East. The water depth at location is around 340 m and the reservoir is 2000 m below the mudline. The field reserves are estimated to be 3700 GSm3. The gas reservoir covers a geographical area of approximately 1 400 km2, and is approximately 48 km long by 35 km wide. The field will be developed in three phases, the expected daily production of each phase being around 70 million Sm3 per day. SDAG owned by Gazprom (51%), Total (25%) and Statoil (24%) will operate the development of the First Phase of the SGCF. The area is a harsh Arctic environment that can be covered by sea ice and is also known for its icebergs and experiences long periods of darkness during the winter months. Facilities in this region can be exposed to very low ambient air temperatures (including wind chill), snow and icing that require winterisation measures to be taken. The offshore development of Phase 1 of the Shtokman Gas Condensate Field development consists of the following main elements (see Fig. 1): The Floating Platform, including hull, mooring, accommodation, process (oil, gas, water as needed), gas export facilities (compression and metering) and associated control systems. The Subsea Production System (referred to as the SPS). The Umbilicals, Flowlines and Risers (UFR) to gather production from SPS and transport it to the Floating Platform and to connect the Floating Platform to pipeline to shore. The Export Trunklines. After various conceptual initial studies, Shtokman Development AG has concluded to design the floating platform as a turret moored disconnectable and ice resistant ship shaped floating platform. The FP design operating life is 50 years. The present paper describes the main principles of design of the hull that form the frame for further optimization by contractors.