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L. B. Magoon

Publications and source records attributed to L. B. Magoon.

18 recordsLinked to original sources
USGS2006

North Slope, Alaska: Source rock distribution, richness, thermal maturity, and petroleum charge

Four key marine petroleum source rock units were identified, characterized, and mapped in the subsurface to better understand the origin and distribution of petroleum on the North Slope of Alaska. These marine source rocks, from oldest to youngest, include four intervals: (1) Middle-Upper Triassic Shublik Formation, (2) basal condensed section in the Jurassic-Lower Cretaceous Kingak Shale, (3) Cretaceous pebble shale unit, and (4) Cretaceous Hue Shale. Well logs for more than 60 wells and total organic carbon (TOC) and Rock-Eval pyrolysis analyses for 1183 samples in 125 well penetrations of the source rocks were used to map the present-day thickness of each source rock and the quantity (TOC), quality (hydrogen index), and thermal maturity (Tmax) of the organic matter. Based on assumptions related to carbon mass balance and regional distributions of TOC, the present-day source rock quantity and quality maps were used to determine the extent of fractional conversion of the kerogen to petroleum and to map the original TOC (TOCo) and the original hydrogen index (HIo) prior to thermal maturation. The quantity and quality of oil-prone organic matter in Shublik Formation source rock generally exceeded that of the other units prior to thermal maturation (commonly TOCo > 4 wt.% and HIo > 600 mg hydrocarbon/g TOC), although all are likely sources for at least some petroleum on the North Slope. We used Rock-Eval and hydrous pyrolysis methods to calculate expulsion factors and petroleum charge for each of the four source rocks in the study area. Without attempting to identify the correct methods, we conclude that calculations based on Rock-Eval pyrolysis overestimate expulsion factors and petroleum charge because low pressure and rapid removal of thermally cracked products by the carrier gas retards cross-linking and pyrobitumen formation that is otherwise favored by natural burial maturation. Expulsion factors and petroleum charge based on hydrous pyrolysis may also be high compared to nature for a similar reason. Copyright ?? 2006. The American Association of Petroleum Geologists. All rights reserved.

American Association of Petroleum Geologists Bulle↗
USGS2005

Egret-Hibernia(!), a significant petroleum system, northern Grand Banks area, offshore eastern Canada

Egret-Hibernia(!) is a well-explored petroleum system (3.25 billion barrels oil equivalent [BOE]) located in the Jeanne d'Arc Basin on the Labrador - Newfoundland shelf. Rifting and sediment fill began in the Late Triassic. Egret source rock was deposited in the Late Jurassic at about 153 Ma. After this time, alternating reservoir rock and seal rock were deposited with some syndepositional faulting. By the end of the Early Cretaceous, faults and folds had formed numerous structural traps. For the next 100 m.y., overburden rock thermally matured the source rock when it reached almost 4 km (2.5 mi) burial depth. For 2 km (1.25 mi) below this depth, oil and gas were expelled, until the source was depleted. The expelled petroleum migrated updip to nearby faulted, anticlinal traps, where much of it migrated across faults and upsection to the Hibernia Formation (44% recoverable oil) and Avalon Formation (28%). Accumulation size decreased, and gas content increased from west to east, independent of trap size. These changes correspond to a decrease in source rock richness and quality from west to east. Almost all (96%) of the discovered petroleum resides in the Lower Cretaceous or older reservoir rock units. All accumulations found to date are normally pressured in structural traps. Fifty-two exploration wells found eighteen discoveries. Their size ranges from 1.2 to 0.01 billion BOE. Most discoveries were made between 1979 and 1991. The discovery cycle began with larger accumulations and progressed to smaller accumulations. The estimated sizes of the larger accumulations have grown since 1990. Estimated mean value for undiscovered hydrocarbons is 3.8 billion BOE, thereby raising the ultimate size of Egret-Hibernia(!) to 6.19 billion BOE. Copyright ?? 2005. The American Association of Petroleum Geologists. All rights reserved.

American Association of Petroleum Geologists Bulle↗
USGS2003

Petroleum systems of the Alaskan North Slope: a numerical journey from source to trap

The complex petroleum province of the Alaskan North Slope contains six petroleum systems (Magoon and others, this session). Source rocks for four of these systems include the Hue-gamma ray zone (Hue-GRZ), pebble shale unit, Kingak Shale, and Shublik Formation. Geochemical data for these source rocks are investigated in greater detail and provide the basis for numerical petroleum migration models.

Alaska↗
USGS2003

Distribution, richness, quality, and thermal maturity of source rock units on the North Slope of Alaska

Four source rock units on the North Slope were identified, characterized, and mapped to better understand the origin of petroleum in the area: Hue-gamma ray zone (Hue-GRZ), pebble shale unit, Kingak Shale, and Shublik Formation. Rock-Eval pyrolysis, total organic carbon analysis, and well logs were used to map the present-day thickness, organic quantity (TOC), quality (hydrogen index, HI), and thermal maturity (Tmax) of each unit. To map these units, we screened all available geochemical data for wells in the study area and assumed that the top and bottom of the oil window occur at Tmax of ~440° and 470°C, respectively. Based on several assumptions related to carbon mass balance and regional distributions of TOC, the present-day source rock quantity and quality maps were used to determine the extent of fractional conversion of the kerogen to petroleum and to map the original organic richness prior to thermal maturation.

Alaska↗
USGS2003

Alaskan North Slope petroleum systems

Six North Slope petroleum systems are identified, described, and mapped using oil-to-oil and oil-to-source rock correlations, pods of active source rock, and overburden rock packages. To map these systems, we assumed that: a) petroleum source rocks contain 3.2 wt. % organic carbon (TOC); b) immature oil-prone source rocks have hydrogen indices (HI) >300 (mg HC/gm TOC); c) the top and bottom of the petroleum (oil plus gas) window occur at vitrinite reflectance values of 0.6 and 1.0% Ro, respectively; and d) most hydrocarbons are expelled within the petroleum window. The six petroleum systems we have identified and mapped are: a) a southern system involving the Kuna-Lisburne source rock unit that was active during the Late Jurassic and Early Cretaceous; b) two western systems involving source rock in the Kingak-Blankenship, and GRZ-lower Torok source rock units that were active during the Albian; and c) three eastern systems involving the Shublik-Otuk, Hue Shale and Canning source rock units that were active during the Cenozoic. The GRZ-lower Torok in the west is correlative with the Hue Shale to the east. Four overburden rock packages controlled the time of expulsion and gross geometry of migration paths: a) a southern package of Early Cretaceous and older rocks structurally-thickened by early Brooks Range thrusting; b) a western package of Early Cretaceous rocks that filled the western part of the foreland basin; c) an eastern package of Late Cretaceous and Paleogene rocks that filled the eastern part of the foreland basin; and d) an offshore deltaic package of Neogene rocks deposited by the Colville, Canning, and Mackenzie rivers. This petroleum system poster is part of a series of Northern Alaska posters on modeling. The poster in this session by Saltus and Bird present gridded maps for the greater Northern Alaskan onshore and offshore that are used in the 3D modeling poster by Lampe and others. Posters on source rock units are by Keller and Bird as well as Peters and others. Sandstone and shale compaction properties used in sedimentary basin modeling are covered in a poster by Rowan and others. The results of this modeling exercise will be used in our next Northern Alaska oil and gas resource assessment.

Alaska↗
USGS2000

Mapping the petroleum system - An investigative technique to explore the hydrocarbon fluid system

Creating a petroleum system map includes a series of logical steps that require specific information to explain the origin in time and space of discovered hydrocarbon occurrences. If used creatively, this map provides a basis on which to develop complementary plays and prospects. The logical steps include the characterization of a petroleum system (that is, to identify, map, and name the hydrocarbon fluid system) and the summary of these results on a folio sheet. A petroleum system map is based on the understanding that there are several levels of certainty from "guessing" to "knowing" that specific oil and gas accumulations emanated from a particular pod of active source rock. Levels of certainty start with the close geographic proximity of two or more accumulations, continues with the close stratigraphic proximity, followed by the similarities in bulk properties, and then detailed geochemical properties. The highest level of certainty includes the positive geochemical correlation of the hydrocarbon fluid in the accumulations to the extract of the active source rock. A petroleum system map is created when the following logic is implemented. Implementation starts when the oil and gas accumulations of a petroleum province are grouped stratigraphically and geographically. Bulk and geochemical properties are used to further refine the groups through the determination of genetically related oil and gas types. To this basic map, surface seeps and well shows are added. Similarly, the active source rock responsible for these hydrocarbon occurrences are mapped to further define the extent of the system. A folio sheet constructed for a hypothetical case study of the Deer-Boar(.) petroleum system illustrates this methodology.

AAPG Memoir↗
USGS1992

Mineral and energy resource assessment maps of the Mount Katmai, Naknek, and western Afognak quadrangles, Alaska

On the basis of new geologic mapping and exploration geochemical studies, we have provided a mineral and energy resource assessment of the Mount Katmai, Naknek, and western Afognak quadrangles, Alaska. We delineate four tracts of ground that have metallic mineral resources. The mineral deposit types considered in each tract are summarized in table 4. Estimates of the number of undiscovered mineral deposits have been made for porphyry copper and polymetallic vein deposits. We estimate that one undiscovered porphyry copper deposit is present in the Katmai study area at the ten percent probability level. Although the sampling density may be too low to give an accurate estimate of the number of undiscovered polymetallic vein deposits, we suggest that, at a minimum, there is a five percent probability for five or more undiscovered polymetallic vein deposits in the Katmai study area. In addition, several areas have potential for undiscovered porphyry molybdenum, massive sulfide, and epithermal gold and mercury deposits. Several placer gold claims have been filed in the area; one is still active. One claim, on American Creek, produced a small but unknown amount of gold. Several source areas for gold are identified in this study and would provide potential sources for gold in stream placer deposits given the right hydrologic conditions. Many of these sites in the Kulik Lake area have been prospected with only limited success. However, the upper reaches of lkagluik Creek and some areas of the Rainbow River in the central part of Katmai National Park may also contain undiscovered placer gold resources. Berryhill (1963) investigated the titanium-rich black sand beach placers along the coast of Bristol Bay at Egegik Bay and concluded that they did not constitute a resource for either titanium or gold. Sand and gravel deposits are locally abundant (Riehle and Detterman, in press) and are adequate to supply local demand. No cinder resources have been delineated. Energy potential evaluated during the study includes geothermal, oil and gas, and coal resources. A few warm springs were found, but no hot springs areas suitable for geothermal development exist within the study area. Better sites for geothermal resources have been identified on the Alaska Peninsula south of the study area (Smith and Shaw, 1975). The potential for commercial accumulations of oil and gas in the Naknek, Mount Katmai, and western Afognak quadrangles is low. Area E1, in the Naknek quadrangle along Bristol Bay, has low potential for thermogenic oil and gas (Church, Detterman, and Wilson, 1989). In area E2, oil seeps are along the anticlinal structures both north and south of the Katmai study area. Studies by Magoon and Anders (1992) indicate that the oil is from lower Mesozoic sedimentary rocks. Surface exposures of the Naknek Formation have uniformly indicated poor reservoir characteristics where studied, both here and in the adjacent quadrangles, and the shallow depth of burial of the Naknek Formation probably would result in flushing of the reservoir by meteoric water if oil were present. Coal seams as much as several meters in aggregate thickness crop out in Tertiary rocks in the Geographic Harbor area. Since these coal beds occur within withdrawn Federal lands, there has been no incentive to evaluate them as coal resources. Given different land accessibility and a local market, these beds could constitute a small marketable coal resource.

Alaska↗
USGS1990

Characterization of hydrocarbon gas within the stratigraphic interval of gas-hydrate stability on the North Slope of Alaska, U.S.A.

In the Kuparuk River Unit 2D-15 well, on the North Slope of Alaska, a 60 m-thick stratigraphic interval that lies within the theoretical pressure-temperature field of gas-hydrate stability is inferred to contain methane hydrates. This inference is based on interpretations from well logs: (1) release of methane during drilling, as indicated by the mud log, (2) an increase in acoustic velocity on the sonic log, and (3) an increase of electrical resistivity on the electric logs. Our objective was to determine the composition and source of the gas within the shallow gas-hydrate-bearing interval based on analyses of cutting gas. Headspace gas from canned drill cuttings collected from within the gas-hydrate-bearing interval of this well has an average methane to ethane plus propane [C 1 /(C 2 + C 3 )] ratio of about 7000 and an average methane δ 13 C value of −46% (relative to the PDB standard). These compositions are compared with those obtained at one well located to the north of 2D-15 along depositional strike and one down-dip well to the northeast. In the well located on depositional strike (Kuparuk River Unit 3K-9), gas compositions are similar to those found at 2D-15. At the down-dip well (Prudhoe Bay Unit R-1), the C 1 /(C 2 +C 3 ) ratios are lower (700) and the methane δ 13 C is heavier (−33%). We conclude that the methane within the stratigraphic interval of gas hydrate stability comes from two sources— in situ microbial gas and migrated thermogenic gas. The thermal component is greatest at Prudhoe Bay. Up-dip to the west, the thermogenic component decreases, and microbial gas assumes more importance.

Alaska↗
USGS1989

Map showing the depth to the base of the deepest ice-bearing permafrost as determined from well logs, North Slope, Alaska

Because gas hydrates from within a limited temperature range, subsurface equilibrium temperature data are necessary to calculate the depth and thickness of the gas-hydrate stability field. Acquiring these data is difficult because drilling activity often disrupts equilibrium temperatures in the subsurface, and a well mush lie undisturbed until thermal equilibrium is reestablished (Lachenbruch and Brewer, 1959). On the North Slope if Akaska, a series of 46 oil and gas exploratory wells, which were considered to be near thermal equilibrium (Lachenbruch and others, 1982; 1987), were surveyed with high-resolution temperature devices (see table 1). However, several thousand other exploratory and production wells have been drilled on the North Slope, and although they do not include temperature profiles, their geophysical logs often allow descrimination between ice-bearing and non-ice-bearing strata. At the outset of this study, the coincidence of the base of ice-bearing strata being near the same depth as the 0 °C isotherm at Prudhoe Bay (Lachenbruch and others, 1982) appeared to offer an opportunity to quickly and inexpensively expand the size of our subsurface temperature data base merely by using well logs to identify the base of the ice-bearing strata.

Alaska↗
USGS1981

Two oil types on North slope of Alaska: Implications for exploration

Forty oil samples from across the North Slope of Alaska have been analyzed by the U.S. Bureau of Mines and the U.S. Geological Survey. Results of these analyses suggest two separate genetic oil types. The first, the Simpson-Umiat oil type, occurs in reservoir rocks of Cretaceous and Quaternary age and includes oil from seeps in the Skull Cliff, Cape Simpson, Manning Point, and Ungoon Point areas, and oils from Wolf Creek test 3, and the Cape Simpson and Umiat oil fields. These are higher gravity, low-sulfur oils with no, or slight, odd-numbered n-alkane predominance and pristane to phytane ratios greater than 1.5. Also, these oils have ^dgr 13 C values ranging from -29.1 to -27.8 parts per thousand (ppt) and ^dgr 34 S values from -10.3 to -4.9 ppt. The s cond type, the Barrow-Prudhoe oil type, occurs in reservoir rocks of Carboniferous to Cretaceous age and includes oils from South Barrow gas field, Prudhoe Bay oil field, and the Fish Creek test well 1. Physical properties of Barrow-Prudhoe oils are variable, but in general the oils are medium-gravity, high-sulfur oils with slight even-numbered n-alkane predominance and pristane to phytane ratios less than 1.5. Also these oils have ^dgr 13 C values of -30.3 to -29.8 ppt and ^dgr 34 S values from -30.0 to +2.1 ppt. The two types are believed to originate from different source rocks; the Barrow-Prudhoe type may have originated from a carbonate or other iron-deficient source rock, and the Simpson-Umiat type from a siliciclastic source rock. Occurrences of the two oil types when outlined on a map, indicate at least two areas for additional exploration: for the Barrow-Prudhoe type, in stratigraphic traps along and adjacent to the Barrow arch, and for the Simpson-Umiat type, in Cretaceous rocks along the trend between the Simpson and Umiat oil fields and in Cretaceous and Tertiary rocks from Prudhoe Bay field to the William O. Douglas Arctic Wildlife Range.

Alaska↗
USGS1980

Biogenic and thermogenic origins of natural gas in Cook Inlet basin, Alaska.

Two types of natural gas occurrences are present in the Cook Inlet basin. The major reserves (1.8 × 10 11 m 3 ) occur in shallow (less than 2,300 m), nonassociated dry gas fields that contain methane with ^dgr 13 C in the range of -63 to -56 per mil. These gas fields are in sandstones interbedded with coals of the Sterling and Beluga Formations; the gas fields are interpreted as biogenic in origin. Lesser reserves (1.1 × 10 10 m 3 ) of natural gas are associated with oil in the deeper Hemlock Conglomerate at the base of the Tertiary section; associated gas contains methane with ^dgr 13 C of about -46 per mil. The gases associated with oil in the Hemlock Conglomerate are thermogenic in origin.

Alaska↗