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World conventional crude oil and natural gas: Identified reserves, undiscovered resources and futures

This report summarizes, at the petroleum basin level, the United States Geological Survey's World Energy Program 1993 assessment of world conventional oil and gas resources. The maps provided show boundaries of petroleum basins that are referenced by the assessment, as well as, future oil and gas potential. The 'Futures' or future potential of a basin is calculated as the the sum of the Identified Reserves and the modal value assigned to the conventional Undiscovered Resources.

Open-File Report↗

High-resolution seismic reflection/refraction imaging from Interstate 10 to Cherry Valley Boulevard, Cherry Valley, Riverside County, California: Implications for water resources and earthquake hazards

This report is the second of two reports on seismic imaging investigations conducted by the U.S. Geological Survey (USGS) during the summers of 1997 and 1998 in the Cherry Valley area in California (Figure 1a). In the first report (Catchings et al., 1999), data and interpretations were presented for four seismic imaging profiles (CV-1, CV-2, CV-3, and CV-4) acquired during the summer of 1997 . In this report, we present data and interpretations for three additional profiles (CV-5, CV-6, and CV-7) acquired during the summer of 1998 and the combined seismic images for all seven profiles. This report addresses both groundwater resources and earthquake hazards in the San Gorgonio Pass area because the shallow (upper few hundred meters) subsurface stratigraphy and structure affect both issues. The cities of Cherry Valley and Beaumont are located approximately 130 km (~80 miles) east of Los Angeles, California along the southern alluvial fan of the San Bernardino Mountains (see Figure 1b). These cities are two of several small cities that are located within San Gorgonio Pass, a lower-lying area between the San Bernardino and the San Jacinto Mountains. Cherry Valley and Beaumont are desert cities with summer daytime temperatures often well above 100 o F. High water usage in the arid climate taxes the available groundwater supply in the region, increasing the need for efficient management of the groundwater resources. The USGS and the San Gorgonio Water District (SGWD) work cooperatively to evaluate the quantity and quality of groundwater supply in the San Gorgonio Pass region. To better manage the water supplies within the District during wet and dry periods, the SGWD sought to develop a groundwater recharge program, whereby, excess water would be stored in underground aquifers during wet periods (principally winter months) and retrieved during dry periods (principally summer months). The SGWD preferred a surface recharge approach because it could be less expensive than a recharging program based on injection wells. However, at an existing surface recharge site, surface recharge of the aquifer was limited by the presence of clayrich layers that impede the downward percolation of the surface water. In boreholes, these clay-rich layers were found to extend from the near surface to about 50 m depth. If practical, the SGWD desired to relocate the recharge ponds to another location within the Cherry Valley–Beaumont area. This required that sites be found where the clay-rich layers were absent. The SGWD elected to explore for such sites by employing a combination of drilling and seismic techniques. A number of near-surface faults have been suggested in the Cherry Valley-Beaumont area (Figure 1b). However, there may be additional unmapped faults that underlie the alluvial valley of San Gorgonio Pass. Because faults are known to act as barriers to lateral groundwater flow in alluvial groundwater systems, mapped and unmapped subsurface faults in the Cherry Valley-Beaumont area would likely influence groundwater flow and the lateral distribution of recharged water. These same faults may pose a significant hazard to the local desert communities and to greater areas of southern California due to the presence of lifelines (water, electrical, gas, transportation, etc.) that extend through San Gorgonio Pass to larger urban areas. The three principal goals of the seismic investigation presented in this report were to laterally map the subsurface stratigraphic horizons, locate faults that may act as barriers to groundwater flow, and measure velocities of shallow sediments that may give rise to amplified shaking during major earthquakes.

California↗

National coal resource assessment non-proprietary data: Location, stratigraphy, and coal quality for selected tertiary coal in the Northern Rocky Mountains and Great Plains region

One of the objectives of the National Coal Resource Assessment in the Northern Rocky Mountains and Great Plains region was to compile stratigraphic and coal quality-trace-element data on selected and potentially minable coal beds and zones of the Fort Union Formation (Paleocene) and equivalent formations. In order to implement this objective, drill-hole information was compiled from hard-copy and digital files of the: (1) U.S. Bureau of Land Management (BLM) offices in Casper, Rawlins, and Rock Springs, Wyoming, and in Billings, Montana, (2) State geological surveys of Montana, North Dakota, and Wyoming, (3) Wyoming Department of Environmental Quality in Cheyenne, (4) U.S. Office of Surface Mining in Denver, Colorado, (5) U.S. Geological Survey, National Coal Resource Data System (NCRDS) in Reston, Virginia, (6) U.S. Geological Survey coal publications, (7) university theses, and (8) mining companies.

Open-File Report↗

Reconnaissance of the hydrothermal resources of Utah

Geologic factors in the Basin and Range province in Utah are more favorable for the occurrence of geothermal resources than in other areas on the Colorado Plateaus or in the Middle Rocky Mountains. These geologic factors are principally crustal extension and crustal thinning during the last 17 million years. Basalts as young as 10,000 years have been mapped in the area. High-silica volcanic and intru­sive rocks of Quaternary age can be used to locate hydrothermal convection systems. Drilling for hot, high-silica, buried rock bodies is most promising in the areas of recent volcanic activity. Southwestern Utah has more geothermal potential than other parts of the Basin and Range province in Utah. The Roosevelt Hot Springs area, the Cove Fort-Sulphurdale area, and the area to the north as far as 60 kilome­ters from them probably have the best potential for geothermal devel­opment for generation of electricity. Other areas with estimated res­ervoir temperatures greater than 150°C are Thermo, Monroe, Red Hill (in the Monroe-Joseph Known Geothermal Resource Area), Joseph Hot Springs, and the Newcastle area. The rates of heat and water discharge are high at Crater, Meadow, and Hatton Hot Springs, but estimated reservoir temperatures there are less than 150°C. Ad­ditional exploration is needed to define the potential in three ad­ditional areas in the Escalante Desert.

Utah↗

Geology and mineral resources of the Mud Springs Ranch Quadrangle, Sweetwater County, Wyoming

The Mud Springs Ranch quadrangle occupies an area of 56 mF (square miles) on the southeast flank of the Rock Springs uplift in southwestern Wyoming. The climate is arid and windy. The landscape is mostly poorly vegetated and consists of north-trending ridges and valleys that are dissected by dry drainages. Sedimentary rocks exposed in the quadrangle are 5,400 ft (feet) thick and are mostly gray sandstone, siltstone, and shale, gray and brown carbonaceous shale, and thin beds of coal. They compose the Blair, Rock Springs, Ericson, Almond, and Lewis Formations of Cretaceous age and the Fort Union Formation of Paleocene age. The structure is mostly homoclinal, having southeast dips of 5?-12? in the northern part of the quadrangle, but minor plunging folds and one small fault are present in the southern part of the quadrangle. Three coal beds in the Fort Union Formation and 15 coal beds in the Almond Formation exceed 2.5 ft in thickness, are under less than 3,000 ft of overburden, and are potentially minable. Geographic stratigraphic, and resource data are present for each bed of minable coal. The total minable coal resources are estimated to be about 283 million short tons. Nine coal and rock samples from outcrops were analyzed to determine their quality and chemical composition. Four dry oil and gas test wells have been drilled within the quadrangle area, but structurally controlled stratigraphic-trap prospects remain untested.

Professional Paper↗

Water resources and potential hydrologic effects of oil-shale development in the southeastern Uinta Basin, Utah and Colorado

Proposed oil-shale mining in northeastern Utah is expected to impact the water resources of a 3,000-square-mile area. This report summarizes a comprehensive hydrologic investigation of the area which resulted in 13 published reports. Hydrologic information obtained during 1974-80 was used to evaluate the availability of water and to evaluate potential impacts of an oil-shale industry on the water resources. The study area is the southeastern part of the Uinta Basin, Utah and Colorado, where the hydrology is extremely variable. The normal annual precipitation averages 11 inches and varies with altitude. It ranges from less than 8 inches at altitudes below 5,000 feet along the White and Green Rivers to more than 20 inches where altitudes exceed 9,000 feet on the Roan Plateau. The White and Green Rivers are large streams that flow through the area. They convey an average flow of 4.3 million acre-feet per year from outside drainage areas of about 34,000 square miles, which is more than 150 times as much flow as that originating within the area. Streams originating in areas where precipitation is less than 10 inches are ephemeral. Mean annual runoff from the study area is about 28,000 acre-feet and ranges from less than 0.1 to 1.6 inches, depending on the location. At any given site, runoff varies greatly-from year to year and season to season. Potential evapotranspiration is large, exceeding precipitation in all years. Three major aquifers occur in the area. They are alluvial deposits of small areal extent along the major stream valleys; the bird's-nest aquifer of the Parachute Creek Member of the Green River Formation, which is limited to the central part of the study area; and the Douglas Creek aquifer of the Douglas Creek Member of the Green River Formation, which underlies most of the area. Total recoverable water in storage in the three aquifers is about 18 million acre-feet. Yields of individual wells and interference between wells limit the maximum practical withdrawal to about 20,000 acre-feet per year. An oil-shale industry in the southeastern Uinta Basin with a peak production of 400,000 barrels of oil per day would require a water supply of about 70,000 acre-feet per year. Sources of water supply considered for such an industry were: diversion from the natural flow of the White River, a proposed reservoir on the White River, diversion from the White River combined with proposed off-stream storage in Hells Hole Canyon, diversion from the Green River, and conjunctive use of ground and surface water. The proposed reservoir on the White River would trap about 90 percent of the sediment moving in the river and in turn would release almost sediment-free water. Possible impacts are changes in channel gradient in the downstream 18 miles of the White River and changes in bank stability. In some parts of the area, annual sheet-erosion rates are as great as 2.2 acre-feet per square mile but sediment yield to the White River is less than might be expected because the runoff is small. If process water from retort operations or water used in the construction of surface facilities is discharged into a normally dry streambed, increased channel erosion and sediment in tributary streams could result in increased sediment loads in the White River. In addition, sediment yields from retorted-shale piles with minimum slopes could exceed 0.1 acrefoot per square mile during a common storm. Thus, without safeguards, the useful life of any proposed reservoir or holding pond could be decreased considerably. Leachate water from retorted-shale piles has large concentrations of sodium and sulfate, and the chemical composition of retort waters differs considerably from that of the natural waters of the area. The retort waters contain a greater concentration of dissolved solids and more organic carbon and nutrients. Without proper disposal or impoundment of retort and leachate waters, the salinity of downstream waters in the Colorado River Basin would be increased.

Colorado, Utah↗

Coal and petroleum resources in the Appalachian basin: index maps of included studies

This chapter B.1 of U.S. Geological Survey (USGS) Professional Paper 1708 provides index maps for many of the studies described in other chapters of the report. Scientists of the USGS and State geological surveys studied coal and petroleum resources in the central and southern Appalachian structural basins. In the southern Appalachian basin, studies focused on the coal-bearing parts of the Black Warrior basin in Alabama. The scientists used new and existing geologic data sets to create a common spatial geologic framework for the fossil-fuel-bearing strata of the central Appalachian basin and the Black Warrior basin in Alabama. Digital data have been compiled into a geographic information system (GIS) that is included in chapter I.1 (Trippi and others, this volume). Shape files and related metadata for features shown in the index maps of this chapter can be downloaded from chapter I.1. The study area for the Appalachian basin resource framework study includes the fossil-fuel-bearing strata of the following States (listed alphabetically): Alabama, Kentucky, Maryland, New York, Ohio, Pennsylvania, Tennessee, Virginia, and West Virginia. The outline of the study area is shown in figure 1; it differs from the boundary of the Appalachian Basin Province (Province 67) defined for the 1995 National Oil and Gas Assessment (NOGA) by the U.S. Geological Survey (1996a). The difference is that the study area includes regions where the Pennsylvanian coal-bearing strata crop out but does not include all of the oil- and gas-bearing strata of the Black Warrior basin, Alabama. The reasons for providing the index maps in this chapter are to show the locations of different studies, to give an overview of topics covered, and to help the user choose which chapter to read. Figures 1 and 2 show the study area outline and county names. Figure 3 shows oil and gas production in 1995 and 2005. Figure 4 shows locations of Upper Devonian sandstone oil and gas fields. Figure 5 shows major coal regions and coal fields. Figure 6 shows coal production by county. Figure 7 shows the locations of 10 cross sections of regional extent through the subsurface of the Appalachian basin. Figure 8 shows conodont alteration index sample locations and interpreted isograds for Ordovician rocks. Figure 9 shows vitrinite-reflectance data for Pennsylvanian coal in the Appalachian basin. Figure 10 shows the locations of coalbed-methane (CBM) assessment units in the study area, and figure 12 shows counties producing CBM. Figure 12 shows sulfur content of coal delivered to powerplants from coal-producing counties in the Appalachian basin and Black Warrior basin. Figure 13 shows locations of wells in Ohio and Pennsylvania where oil and gas were sampled in Lower Silurian reservoirs. Figure 14 shows the Conasauga-Rome/Conasauga Total Petroleum System and selected wells in the Rome trough in Kentucky and West Virginia having oil and gas production and shows. Figure 15 shows the locations of samples from Silurian reservoirs in Kentucky, New York, Ohio, Pennsylvania, and West Virginia; the samples yielded total organic carbon data. Figure 16 shows the locations of the Ben Hur and Rose Hill oil fields, Virginia, and the Swan Creek oil field, Tennessee. The one index map that is not shown is the areal extent of the shale gas plays in the basin. The extents of the plays can be found in Coleman and others (this volume, chap. G.13).

Appalachian basin↗

Assessment of Appalachian basin oil and gas resources: Devonian gas shales of the Devonian Shale-Middle and Upper Paleozoic Total Petroleum System

This report presents the results of a U.S. Geological Survey (USGS) assessment of the technically recoverable undiscovered natural gas resources in Devonian shale in the Appalachian Basin Petroleum Province of the eastern United States. These results are part of the USGS assessment in 2002 of the technically recoverable undiscovered oil and gas resources of the province. This report does not use the results of a 2011 USGS assessment of the Devonian Marcellus Shale because the area considered in the 2011 assessment is much greater than the area of the Marcellus Shale described in this report. The USGS assessment in 2002 was based on the identification of six total petroleum systems, which include strata that range in age from Cambrian to Pennsylvanian. The Devonian gas shales described in this report are within the Devonian Shale-Middle and Upper Paleozoic Total Petroleum System, which extends generally from New York to Tennessee. This total petroleum system is divided into ten assessment units (plays), four of which are classified as conventional and six as continuous. The Devonian shales described in this report make up four of these continuous assessment units. The assessment results are reported as fully risked fractiles (F95, F50, F5, and the mean); the fractiles indicate the probability of recovery of the assessment amount. The products reported are oil, gas, and natural gas liquids. The mean estimates for technically recoverable undiscovered hydrocarbons in the four gas shale assessment units are 12,195.53 billion cubic feet (12.20 trillion cubic feet) of gas and 158.91 million barrels of natural gas liquids

Appalachian basin↗

Oil and gas resources of the Arctic Alaska Petroleum Province

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 structural-stratigraphic 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 ft3 of gas, distributed approximately equally between Federal offshore and combined onshore and State offshore areas.

Alaska↗

The 2008 Circum-Arctic Resource Appraisal

Professional Paper 1824 comprises 30 chapters by various U.S. Geological Survey authors, including introduction and methodology chapters, which together provide documentation of the geological basis and methodology of the 2008 Circum-Arctic Resource Appraisal, results of which were first released in August 2008. Twenty-eight chapters summarize the petroleum geology and resource potential of individual, geologically defined provinces north of the Arctic Circle, including those of northern Alaska, northern Canada, east and west Greenland, and most of Arctic Russia, as well as certain offshore areas of the north Atlantic Basin and the Polar Sea. Appendixes tabulate the input and output information used during the assessment.

Professional Paper↗

Introduction to the 2008 Circum-Arctic Resource Appraisal (CARA) professional paper

The amount of yet-to-find oil and gas in the high northern latitudes is one of the great uncertainties of future energy supply. The possibility of extensive new petroleum developments in the Arctic Ocean is of interest to the Arctic nations, to petroleum companies, and to those concerned with the delicate and changing Arctic environment. The U.S. Geological Survey (USGS) 2008 Circum-Arctic Resource Appraisal (CARA) had the express purpose of conducting a geologically based assessment of undiscovered petroleum north of the Arctic Circle, thereby providing an initial evaluation of resource potential.

Professional Paper↗

Geology and assessment of undiscovered oil and gas resources of the Lomonosov-Makarov Province, 2008

The Lomonosov-Makarov Province lies in the central Arctic Ocean and encompasses the northern part of the oceanic Amerasia Basin (Makarov and Podvodnikov Basins) and the adjoining Lomonosov Ridge and Siberian continental margins. The Amerasia Basin is thought to have been created in the Jurassic and Early Cretaceous by rotational rifting of the Alaska-Siberia margin away from the Canada margin about a pivot point in the Mackenzie Delta and an associated continental-scale transform fault along the Lomonosov Ridge. The province is bounded on the south by the Cretaceous Alpha-Mendeleev Ridge, an undersea ridge composed of plume-type volcanic rocks that obliquely crosses the Amerasia Basin, dividing it into northern and southern parts. The thickest passive-margin succession in the province lies along the Siberian margin, where sediments thin from a maximum thickness along the continental margin to less than 2 km in the basin. The northern part of the province consists of the Lomonosov Ridge, which was rifted away from the Eurasia Plate in the Paleocene during formation of the oceanic Eurasia Basin, creating an isolated, narrow, submerged, but high-standing microcontinent. This part of the province contains sediments that were shed from the Eurasia Plate in the Mesozoic and covered by pelagic and hemipelagic sediments in the Cenozoic, creating depositional successions with thicknesses ranging from about 1 to more than 5 km. This tectonic framework provides the basis for division of the province into four assessment units (AUs), including (1) Lomonosov Ridge AU, (2) Makarov Basin Margin AU, (3) Siberian Passive Margin AU, and (4) Makarov Basin AU. The Lomonosov Ridge and Makarov Basin Margin AUs compose a displaced part of the Cretaceous shelf and slope, respectively, of the Eurasia continental margin with a covering drape of pelagic Cenozoic sediments. The Siberian Passive Margin and Makarov Basin AUs represent the slope of the Siberian continental margin and adjoining basin plain deposits, respectively, deposited on oceanic crust of the northern Amerasia Basin. All of the AUs are entirely submarine and covered by the polar icecap, and consequently have not been explored for petroleum. Petroleum source rock units considered in the assessment of the province are mostly hypothetical, and include Triassic and Jurassic platformal marine shale units on the Lomonosov Ridge, and province-wide Lower Cretaceous synrift, Lower and Upper Cretaceous postrift, and Paleogene organic-rich shale intervals. The most prospective reservoirs and traps are envisioned to include base-of-slope turbidite-fan complexes, slope channels and basins, extensional and growth fault structures, and other stratigraphic, structural, and composite trap features typically present on clastic-dominated continental passive margins. Because of concerns about reservoir quality in the Makarov Basin AU and the detrimental effect of Paleocene rifting in the Lomonosov Ridge AU, these units were not quantitatively assessed, as they were judged to have less than 10 percent probability of containing at least one accumulation of hydrocarbons equal to or greater than 50 million barrels of oil equivalent (MMBOE). The mean volumes of undiscovered resources for the Makarov Basin Margin AU are estimated to be 0.12 billion barrels of oil and 0.74 trillion cubic feet of nonassociated gas, whereas the undiscovered resources for the Siberian Passive Margin AU are estimated to be ~1 billion barrels of oil and 4.7 trillion cubic feet of nonassociated gas.

Professional Paper↗

Geology and assessment of undiscovered oil and gas resources of the Eurasia Basin Province, 2008

The Eurasia Basin Petroleum Province comprises the younger, eastern half of the Arctic Ocean, including the Eurasia Basin and the outboard part of the continental margin of northern Europe in the Barents and Kara Seas. The province includes the slope and rise sedimentary prism of the Lena Delta, the north-facing outer shelf, slope, and rise of the European passive margin, and sedimentary accumulations in the deep Nansen and Amundsen Basins. The entire province lies north of the Arctic Circle beneath the polar ice cap and includes the North Pole. The province is divided into four assessment units (AUs). The Lena Prodelta AU in the eastern part of the province consists of the deep-marine part of the Lena Delta, which has been deposited across the Gakkel Ridge, an ultraslow spreading ridge. The Nansen Basin Margin AU in the southern part of the province comprises the Cenozoic passive margin sequence of the rift margin of the western (European) part of the Eurasian plate. This AU spans the continent-ocean boundary and includes prerift strata along the outer continental margin. The Nansen Basin and Amundsen Basin AUs encompass the deep abyssal plains of the Eurasia Basin. Lying south of the Gakkel Ridge spreading center, the sedimentary fill of Nansen Basin AU consists of the distal clinoform deposits shed from the western Eurasia passive margin. North of the Gakkel Ridge, Amundsen Basin AU consists of a nascent distal passive-margin sequence derived from the adjacent Lomonosov Ridge and overlying flat-lying deep marine strata shed from distant source areas in Siberia and Greenland after the Lomonosov Ridge subsided below sea level at about 50 Ma. The primary petroleum system thought to be present is sourced in ~50–44 Ma (early to middle Eocene) condensed pelagic deposits that could be widespread in the province. Mean estimates of undiscovered, technically recoverable petroleum resources include <1 billion barrels of oil (BBO) and about 1.4 trillion cubic feet (TCF) of nonassociated gas in Lena Prodelta AU, and < 0.4 BBO and 3.4 TCF nonassociated gas in the Nansen Basin Margin AU. Quantities of natural gas liquids and associated natural gas also are assessed in each of these AUs. The Nansen Basin and Amundsen Basin AUs were not quantitatively assessed because they were judged to have less than 10 percent probability of containing at least one accumulation of 50 MMBOE (million barrels of oil equivalent), the minimum probability required for evaluation in the U.S. Geological Survey Circum-Arctic Resource Appraisal.

Professional Paper↗

Geology and assessment of undiscovered oil and gas resources of the Arctic Alaska Province, 2008

The Arctic Alaska Province encompasses all lands and adjacent continental shelf areas north of the Brooks Range-Herald Arch tectonic belts and south of the northern (outboard) margin of the Alaska rift shoulder. Even though only a small part is thoroughly explored, it is one of the most prolific petroleum provinces in North America, with total known resources (cumulative production plus proved reserves) of about 28 billion barrels of oil equivalent. For assessment purposes, the province is divided into a platform assessment unit, comprising the Alaska rift shoulder and its relatively undeformed flanks, and a fold-and-thrust belt assessment unit, comprising the deformed area north of the Brooks Range and Herald Arch tectonic belts. Mean estimates of undiscovered, technically recoverable resources include nearly 28 billion barrels of oil and 122 trillion cubic feet of nonassociated gas in the platform assessment unit and 2 billion barrels of oil and 59 trillion cubic feet of nonassociated gas in the fold-and-thrust belt assessment unit.

Alaska, Yukon↗

Geology and assessment of undiscovered oil and gas resources of the Franklinian Shelf Province, Arctic Canada and North Greenland, 2008

In 2008, the U.S. Geological Survey assessed the potential for undiscovered oil and gas resources of the Franklinian Shelf Province of northern Canada and Greenland as part of the U.S. Geological Survey Circum-Arctic Resource Appraisal Program. The Franklinian Shelf Province lies along the northernmost edge of the North American craton in Greenland and Canada. It encompasses a Cambrian through Middle Devonian passive margin sequence deposited on the margin of an ocean formed by rifting and seafloor spreading that began in latest Precambrian time and continued into Ordovician time. In the Canadian part of the province, the passive margin sequence is overlain by a thick succession of Devonian clastic strata shed from uplifts produced by the Caledonian collision between Laurentia and Baltica that closed Iapetus Ocean. The late Silurian to Early Devonian Boothia-Cornwallis uplifts within the region, apparently a distal effect of earlier phases of the Caledonian collision, were local sources of clastic wedges within the predominantly carbonate shelf sequence. Much of the northern part of the province was subjected to folding and thrusting during Late Devonian to earliest Carboniferous Ellesmerian deformation, followed by a prolonged period of erosion. The eastern part of the province again experienced transpressive and compressive deformation as Greenland converged with North America during the early Tertiary Eurekan orogeny. Potential source rocks include Ordovician to Lower Devonian shales that contain abundant oil-prone organic matter, deposited on the outer continental shelf and slope. The most likely source rocks are Silurian strata, deposited as the continental shelf was drowned by a marine transgression caused by regional subsidence most likely associated with thrust loading. Potential source rocks in Greenland also may include organic-rich Cambrian shales deposited on the continental shelf. Rapid burial by thick Caledonian-derived strata in Late Devonian time abruptly matured the source rocks and generated oil; continued rapid burial may have cracked much of the accumulated oil to gas. In North Greenland, oil generation may have resulted from burial by now-eroded Devonian strata or from burial by Ellesmerian thrust sheets. Widespread bitumen in outcrops and in exploration wells appears to confirm that oil was indeed generated. Potential reservoirs include Cambrian nearshore clastic strata, Cambrian to Silurian carbonate bank strata, and Silurian to Middle Devonian reef buildups on the drowned shelf. Because Ellesmerian deformation postdated migration, only stratigraphic traps are likely, except in the area of the Boothia-Cornwallis uplift, a north-trending, structurally elevated zone, where structural traps formed by late Silurian to Early Devonian deformation are possible. It is unlikely that any large accumulations survived subsequent deformation or uplift and erosion. Three assessment units were defined: the Western Franklinian Shelf, the Boothia-Cornwallis Uplift, and the Eastern Franklinian Shelf Assessment Units. These assessment units were not quantitatively assessed, mostly because of the high risk to timing and preservation.

Franklinian Shelf Province↗

Geology and assessment of undiscovered oil and gas resources of the East Greenland Rift Basins Province, 2008

In 2007 the U.S. Geological Survey (USGS) completed an assessment of undiscovered, technically recoverable oil and gas resources in the East Greenland Rift Basins Province of Northeast Greenland. The province was selected as the prototype for the U.S. Geological Survey Circum-Arctic Resource Appraisal (CARA). In collaboration with the Geological Survey of Denmark and Greenland (GEUS), the province was subdivided into nine geologically distinctive areas. Seven of these were defined as Assessment Units (AUs), of which five were quantitatively assessed. These are: North Danmarkshavn Salt Basin, South Danmarkshavn Basin, Thetis Basin, Northeast Greenland Volcanic Province, and Liverpool Land Basin. Jameson Land Basin and the Jameson Land Basin Subvolcanic Extension were defined as AUs but were not quantitatively assessed. Onshore studies by GEUS and other organizations suggest that at least four stratigraphic intervals may contain potential source rocks for petroleum. The geological history of related areas in western Norway and burial history modeling suggest that Upper Jurassic strata are most likely to contain petroleum source rocks. A wide variety of possible trapping mechanisms are expected within the province. Potential traps in the North Danmarkshavn Salt Basin AU are dominated by structures formed through salt tectonics; those in the South Danmarkshavn Basin and the Northeast Greenland Volcanic Province are characterized by extensional structures and by stratigraphic traps in submarine fan complexes. Prospective inversion structures of Tertiary age are present along the western margin of South Danmarkshavn Basin AU, and the large horst block structures that separate the Danmarkshavn and Thetis Basins may provide numerous opportunities for traps in fault blocks and along various facies-related permeability barriers. Possible reservoirs include shallow marine to nonmarine sandstones of Middle Jurassic age, sandstones in Upper Jurassic synrift deposits, Cretaceous sandstones in submarine fan complexes, sandstones in Paleogene progradational sequences, and in Upper Carboniferous to Lower Permian warm-water carbonate sequences, especially in northern Danmarkshavn Basin. Marine shales are expected to provide the main sealing lithologies in most AUs. Most of the undiscovered oil, gas, and natural gas liquids are likely to be in the offshore areas of the province and are inferred to belong to an Upper Jurassic Composite Total Petroleum System. The USGS estimated that the East Greenland Rift Basins Province contains approximately (mean) 31,400 million barrels oil equivalent (MMBOE) of oil, natural gas, and natural gas liquids. Of the five assessed AUs, North Danmarkshavn Salt Basin and the South Danmarkshavn Basin are estimated to contain most of the undiscovered petroleum.

Professional Paper↗

Geology and assessment of undiscovered oil and gas resources of the East Siberian Sea Basin Province, 2008

The East Siberian Sea Basin, which lies beneath the continental shelf east of the New Siberian Islands, is one of the better-known basins in a series of postorogenic (successor) basins in the East Siberian-Chukchi Sea region because of a reconnaissance network of seismic-reflection profiles and outcrops on nearby islands. In spite of the seismic coverage, the basin’s petroleum potential is poorly known. It is considered a separate petroleum province for the purposes of the Circum-Arctic Resource Appraisal. The probability that the East Siberian Sea Basin contains at least one undiscovered accumulation >50 million barrels of oil equivalent (MMBOE) is considered to be ~22 percent. A single assessment unit was defined and studied, resulting in mean estimates of technically recoverable conventional undiscovered resources of ~20 million barrels of oil (MMBO) and 580 billion cubic feet of gas (BCFG), nonassociated.

Professional Paper↗

Conditions and processes affecting sand resources at archeological sites in the Colorado River corridor below Glen Canyon Dam, Arizona

This study examined links among fluvial, aeolian, and hillslope geomorphic processes that affect archeological sites and surrounding landscapes in the Colorado River corridor downstream from Glen Canyon Dam, Arizona. We assessed the potential for Colorado River sediment to enhance the preservation of river-corridor archeological resources through aeolian sand deposition or mitigation of gully erosion. By identifying locally prevailing wind directions, locations of modern sandbars, and likely aeolian-transport barriers, we determined that relatively few archeological sites are now ideally situated to receive aeolian sand supply from sandbars deposited by recent controlled floods. Whereas three-fourths of the 358 river-corridor archeological sites we examined include Colorado River sediment as an integral component of their geomorphic context, only 32 sites currently appear to have a high degree of connectivity (coupled interactions) between modern fluvial sandbars and sand-dominated landscapes downwind. This represents a substantial decrease from past decades, as determined by aerial-photograph analysis. Thus, we infer that recent controlled floods have had a limited, and declining, influence on archeological-site preservation. Within the study area, overland-flow (gully) erosion is less severe in sand landscapes with active aeolian sand than in landscapes that lack aeolian transport; gullies terminate more commonly in active sand (sand that is mobile by wind rather than stabilized by biologic soil crust). We infer that these characteristics largely result from aeolian sand transport being an effective gully-limiting and gully-annealing mechanism. Aeolian sand activity in the river corridor varies substantially as a function of reach morphology and dominant wind direction relative to the river-corridor orientation, factors that control accommodation space for river-derived sand and the modern sand supply to aeolian dunes. These attributes, together with an inverse correlation between aeolian sand activity and gully occurrence, define varying degrees of net long-term gully-erosion risk for sediment deposits and associated archeological sites in different regions of the river corridor. Over most of the river corridor, including some of the archeologically richest regions, sand is too inactive with respect to aeolian transport to anneal gullies effectively. At eight selected archeological sites that we studied with high-resolution terrestrial lidar scans for more than a year, sand loss by overland flow (gully erosion) and aeolian deflation generally exceeded deposition, such that erosion dominated over most monitoring intervals&mdash;even at four sites with strong connectivity to modern sand supply. The Glen Canyon reach of the river corridor appears especially vulnerable to gully erosion. Among the sites that we monitored in detail, erosion generally dominated over deposition to a greater degree at four Glen Canyon sites with no modern sand supply than at four Marble&ndash;Grand Canyon sites with aeolian sand supply from controlled-flood sandbars. Although gross annual-scale erosion rates were similar among the Glen Canyon sites and among the Marble&ndash;Grand Canyon sites, a relative lack of depositional processes led to greater net erosion at the Glen Canyon sites. Having found no differences in weather patterns to suggest greater erosive forcing in Glen Canyon, and no conclusively influential differences in the slope or watershed area contributing to gully formation, we attribute the greater erosion at the Glen Canyon sites to a combination of inherent geomorphic context (high terraces that do not receive modern sediment supply) and pronounced effects of postdam sediment-supply limitation. We conclude that most of the river-corridor archeological sites are at elevated risk of net erosion under present dam operations. In the present flow regime, controlled floods do not simulate the magnitude or frequency of natural floods, and are not large enough to deposit sand at elevations that were flooded at annual to decadal intervals in predam time. For archeological sites that depend upon river-derived sand, we infer elevated erosion risk owing to a combination of reduced sand supply (both fluvial and aeolian) through (1) the lower-than-natural flood magnitude, frequency, and sediment supply of the controlled-flooding protocol; (2) reduction of open, dry sand area available for wind redistribution under current normal (nonflood) dam operations, which do not include flows as low as natural seasonal low flows and do include substantial daily flow fluctuations; and (3) impeded aeolian sand entrainment and transport owing to increased riparian vegetation growth in the absence of larger, more-frequent floods. If dam operations were to increase the supply of sand available for windblown transport&mdash;for example, through larger floods, sediment augmentation, or increased fluvial sandbar exposure by low flows&mdash;and also decrease riparian vegetation, the prevalence of active aeolian sand could increase over time, and the propensity for unmitigated gully erosion could decrease. Although the evolution of river-corridor landscapes and archeological sites has been altered fundamentally by the lack of large, sediment-rich floods (flows on the order of 5,000 m 3 /s), some combination of sediment-rich flows above 1,270 m 3 /s, seasonal flows below 226 m 3 /s, and riparian-vegetation removal might increase the preservation potential for sand-dependent archeological resources in the Colorado River corridor.

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