Leslie B. Magoon

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.

Geologic Framework of Lower Cook Inlet, Alaska

Three seismic reflectors are present throughout the lower Cook Inlet basin and can be correlated with onshore geologic features. The reflections come from unconformities at the base of the Tertiary sequence, at the base of Upper Cretaceous rocks, and near the base of Upper Jurassic strata. A contour map of the deepest horizon shows that Mesozoic rocks are formed into a northeast-trending syncline. Along the southeast flank of the basin, the northwest-dipping Mesozoic rocks are truncated at the base of Tertiary rocks. The Augustine-Seldovia arch trends across the basin axis between Augustine Island and Seldovia. Tertiary rocks thin onto the arch from the north and south. Numerous anticlines, smaller in structural relief and breadth than the Augustine-Seldovia arch, trend northeast parallel with the basin, and intersect the arch at oblique angles. The stratigraphic record shows four cycles of sedimentation and tectonism that are bounded by three regional unconformities in lower Cook Inlet and by four thrust faults and the modern Benioff zone in flysch rocks of the Kenai Peninsula and the Gulf of Alaska. The four cycles of sedimentation are, from oldest to youngest, the early Mesozoic, late Mesozoic, early Cenozoic, and late Cenozoic. Data on organic geochemistry of the rocks from one well suggest that Middle Jurassic strata may be a source of hydrocarbons. Seismic data show that structural traps are formed by northeast-trending anticlines and by structures formed at the intersections of these anticlines with the transbasin arch. Stratigraphic traps may be formed beneath the unconformity at the base of Tertiary strata and beneath unconformities within Mesozoic strata.

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 ^dgr13C values ranging from -29.1 to -27.8 parts per thousand (ppt) and ^dgr34S 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 ^dgr13C values of -30.3 to -29.8 ppt and ^dgr34S 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.

Deep Sea Drilling Project, Leg 77, southeastern Gulf of Mexico

In January 1981, R/V Glomar Challenger drilled five holes in the southeastern Gulf of Mexico to provide ground data for extensive seismic surveys and to document the pre-Tertiary history of the Gulf. Holes 535 and 540 were drilled in a basinal terrane for maximum penetration of the Cretaceous-Tertiary sequence. Rhythmic alternations of light bioturbated and dark laminated carbonaceous limestone represent the Early Cretaceous interval. Some of the dark layers are rich but immature oil source rocks. The limestones resemble the Blake-Bahama Formation in the North Atlantic but their stratigraphic age overlaps in part with the Hatteras Shale. Late Cretaceous rocks are almost totally missing in the basin sites and the Cenozoic section consists of chalk and marly carbonate ooze. Holes 536,537, and 538A were drilled on high-standing fault blocks. Hole 537 recovered phyllite that records 40 Ar/ 39 Ar plateau ages of about 500 m.y. and is overlain by an Early Cretaceous deepening sequence of alluvial to littoral elastics and oolitic-oncolitic limestones, capped by a thin sequence of Cretaceous and Cenozoic pelagics. In Hole 538A, basement consists of mylonitic gneiss and amphibolite, intruded by several generations of diabase dikes (that is, “transitional” crust). 40 Ar/ 39 Ar dates of hornblendes and biotite from the regional metamorphic rocks suggest a 500-m.y. (“Pan-African”) age with mild late Paleozoic thermal overprint. 40 Ar/ 39 Ar whole-rock dates from the dikes suggest intrusions between 190 and 160 m.y. ago. Basement is covered by a thin layer of pelagic chalk, followed by Early Cretaceous skeletal-oolitic limestones and, finally, Cretaceous-Tertiary pelagics. The oolitic-oncolitic limestones at both sites represent either parts of a shallow-water carbonate platform or platform talus deposited in deep water. Hole 536 bottomed in shallow-water dolomite (Jurassic or Permian), overlain by middle Cretaceous skeletal limestones with shallow-water biota and intercalations of pelagic chalk, interpreted as Cretaceous talus at the foot of the Campeche Bank. Cretaceous-Tertiary chalk and carbonate ooze cap the sequence. Among the most significant results of the leg are: (1) recovery of “transitional” crust with early Paleozoic (Pan-African) metamorphic rocks, (2) recovery of Early Cretaceous deep-water limestones with immature petroleum source beds, (3) recovery of mid-Cretaceous platform talus resembling the reservoirs in the Poza Rica and probably some of the Reforma fields of Mexico, and (4) discovery of a Late Cretaceous hiatus of 30 m.y. that corresponds approximately to the “mid-Cretaceous unconformity” recognized widely on seismic records in the Gulf of Mexico.

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 x 10/sup 11/m/sup 3/) occur in shallow (less than 2300 m), nonassociated dry gas fields that contain methane with ..delta.. /sup 13/C in the range of -63 t -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 x 10/sup 10/ m/sup 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 ..delta.. /sup 13/C of about -46 per mil. The gases associated with oil in the Hemlock Conglomerate are thermogenic in origin.

Tectonic controls on greenhouse gas flux to the Paleogene atmosphere from the Gulf of Alaska accretionary prism

The late Paleocene to early Eocene (ca. 61-56 Ma) was a period of long-term global warming, perhaps the warmest in the Cenozoic. Recent modeling suggests that methane loading of the atmosphere, and related development ofpolar stratospheric clouds, could have been an important forcing mechanism for this period of warm climate. The Gulf of Alaska accretionary prism contained ∼6 x 10 6 km 3 of siliciclastic sediments deposited in trench and slope settings along Alaskas Maastrichtian and Paleogene continental margin. These sediments underwent complex deformation, accretion, and unusual high heat flow soon after deposition. Accretion processes thermally overmatured the sediments during a time that overlaps the 61-56 Ma period of long-term global warming. Assuming a modest average organic carbon content of 0.3 wt% in these sediments, an estimated 8.35 x 10 1 5 kg of methane were generated in the accretionary prism over an ∼5 m.y. period. This methane was not effectively trapped, and migration pathways to the atmosphere were developed through complexly deformed and emergent continental borderlands. The Gulf of Alaska accretionary prism is a possible source of the atmospheric methane needed to force Paleocene and early Eocene global warming and an example of how tectonic processes can significantly recycle carbon from the geosphere.

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

Abstract 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 [C1/(C2+ C 3)] ratio of about 7000 and an average methane δ13C 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 C1/(C2 +C3) ratios are lower (700) and the methane δ13C 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.

Chemometric differentiation of crude oil families in the San Joaquin Basin, California

Chemometric analyses of geochemical data for 165 crude oil samples from the San Joaquin Basin identify genetically distinct oil families and their inferred source rocks and provide insight into migration pathways, reservoir compartments, and filling histories. In the first part of the study, 17 source-related biomarker and stable carbon-isotope ratios were evaluated using a chemometric decision tree (CDT) to identify families. In the second part, ascendant hierarchical clustering was applied to terpane mass chromatograms for the samples to compare with the CDT results. The results from the two methods are remarkably similar despite differing data input and assumptions. Recognized source rocks for the oil families include the (1) Eocene Kreyenhagen Formation, (2) Eocene Tumey Formation, (3–4) upper and lower parts of the Miocene Monterey Formation (Buttonwillow depocenter), and (5–6) upper and lower parts of the Miocene Monterey Formation (Tejon depocenter). Ascendant hierarchical clustering identifies 22 oil families in the basin as corroborated by independent data, such as carbon-isotope ratios, sample location, reservoir unit, and thermal maturity maps from a three-dimensional basin and petroleum system model. Five families originated from the Eocene Kreyenhagen Formation source rock, and three families came from the overlying Eocene Tumey Formation. Fourteen families migrated from the upper and lower parts of the Miocene Monterey Formation source rocks within the Buttonwillow and Tejon depocenters north and south of the Bakersfield arch. The Eocene and Miocene families show little cross-stratigraphic migration because of seals within and between the source rocks. The data do not exclude the possibility that some families described as originating from the Monterey Formation actually came from source rock in the Temblor Formation.

Petroleum Geology of Cook Inlet Basin -- An Exploration Model

Oil exploration commenced onshore adjacent to lower Cook Inlet on the Iniskin Peninsula in 1900, shifted with considerable success to upper Cook Inlet from 1957 through 1965, then returned to lower Cook Inlet in 1977 with the COST well and Federal OCS sale. Lower Cook Inlet COST No. 1 well, drilled to a total depth of 3,775.6 m, penetrated basinwide unconformities at the tops of Upper Cretaceous, Lower Cretaceous, and Upper Jurassic strata at 797.1, 1,540.8, and 2,112.3 m, respectively. Sandstone of potential reservoir quality is present in the Cretaceous and lower Tertiary rocks. All siltstones and shales analyzed are low (0 to 0.5 wt. %) in oil-prone organic matter, and only coals are high in humic organic matter. At total depth, vitrinite readings reached a maximum ave age reflectance of 0.65. Several indications of hydrocarbons were present. Oil analyses suggest that oils from the major fields of the Cook Inlet region, most of which produce from the Tertiary Hemlock Conglomerate, have a common source. More detailed work on stable carbon isotope ratios and the distribution of gasoline-range and heavy (C12+) hydrocarbons confirms this genetic relation among the major fields. In addition, oils from Jurassic rocks under the Iniskin Peninsula and from the Hemlock Conglomerate at the southwestern tip of the Kenai lowland are members of the same or a very similar oil family. The Middle Jurassic strata of the Iniskin Peninsula are moderately rich in organic carbon (0.5 to 1.5 wt. %) and yield shows of oil and of gas in wells and in surface seeps. Extractable hydrocarbons from this strata are similar in chemi al and isotopic composition to the Cook Inlet oils. Organic matter in Cretaceous and Tertiary rocks is thermally immature in all wells analyzed. Oil reservoirs in the major producing fields are of Tertiary age and unconformably overlie Jurassic rocks; the pre-Tertiary unconformity may be significant in exploration for new oil reserves. The unconformable relation between reservoir rocks and likely Middle Jurassic source rocks also implies a delay in the generation and expulsion of oil from Jurassic until late Tertiary when localized basin subsidence and thick sedimentary fill brought older, deeper rocks to the temperature required for petroleum generation. Reservoir porosities, crude oil properties, the type of oil field traps, and the tectonic framework of the oil fields on the west flank of the basin provide evidence used to reconstruct an oil migration route. The route is inferred to commence deep in the truncated Middle Jur ssic rocks and pass through the porous West Foreland Formation in the McArthur River field area to a stratigraphic trap in the Oligocene Hemlock Conglomerate and the Oligocene part of the Tyonek Formation at the end of Miocene time. Pliocene deformation shut off this route and created localized structural traps, into which the oil moved by secondary migration to form the Middle Ground Shoal, McArthur River, and Trading Bay oil fields. Oil generation continued into the Pliocene, but this higher API gravity oil migrated along a different route to the Granite Point field.

Petroleum System Modeling of Northern Alaska

Northern Alaska is a prolific oil and gas province estimated to contain a significant proportion of the undiscovered oil and gas of the circum-Arctic. A three-dimensional petroleum system model was constructed with the aim of significantly improving the understanding of the generation, migration, accumulation, and loss of hydrocarbons in the region. This study provides a unique geologic perspective that will reduce exploration risk and assess the remaining potential hydrocarbon resources in this remote province. The present-day geometry is based on newly interpreted seismic data and a database of more than 400 wells. A key aspect of this model is an improved reconstruction of the progradation of the time-transgressive Cretaceous–Tertiary Brookian sequence and multiple erosion events in the Tertiary. The deposition of these overburden rocks controlled the timing of hydrocarbon generation in underlying source rocks and their principal migration from the Colville Basin northward to the Barrow Arch. The model provides a reconstruction of the complex and dynamic interplay of diachronous deposition and erosion and allows assessment of variations in migration behavior and prediction of the present-day petroleum distribution.