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USGS1979

Alaskan papers and abstracts published in American Association of Petroleum Geologists Bulletin, 1950-1978, indexed by quadrangle

This open—file report lists all papers and abstracts on the geology and mineral resources of Alaska published in the American Association of Petroleum Geologists Bulletin from 1950 through 1978. They are listed by the quadrangles (scale 1:250,000) into which Alaska has been subdivided for topographic mapping (p. 2). Reports that deal with regional tectonic hypotheses, regional syntheses, Alaska as a whole, or with areas that can not be identified with specific quadrangles, and the annual reports of developments in Alaska are listed under Alaska — General. Most abstracts appear in this section because they are so worded that locations can not be determined accurately enough to restrict areas discussed to specific quadrangles. Reports that deal with offshore areas not within quadrangle boundaries are listed under Offshore Areas. The Alaska — General and Offshore Areas lists appear before the alphabetically arranged quadrangle listings.

Alaska↗

USGS2008

Restoration of Circum-Arctic Upper Jurassic source rock paleolatitude based on crude oil geochemistry

Tectonic geochemical paleolatitude (TGP) models were developed to predict the paleolatitude of petroleum source rock from the geochemical composition of crude oil. The results validate studies designed to reconstruct ancient source rock depositional environments using oil chemistry and tectonic reconstruction of paleogeography from coordinates of the present day collection site. TGP models can also be used to corroborate tectonic paleolatitude in cases where the predicted paleogeography conflicts with the depositional setting predicted by the oil chemistry, or to predict paleolatitude when the present day collection locality is far removed from the source rock, as might occur due to long distance subsurface migration or transport of tarballs by ocean currents. Biomarker and stable carbon isotope ratios were measured for 496 crude oil samples inferred to originate from Upper Jurassic source rock in West Siberia, the North Sea and offshore Labrador. First, a unique, multi-tiered chemometric (multivariate statistics) decision tree was used to classify these samples into seven oil families and infer the type of organic matter, lithology and depositional environment of each organofacies of source rock [Peters, K.E., Ramos, L.S., Zumberge, J.E., Valin, Z.C., Scotese, C.R., Gautier, D.L., 2007. Circum-Arctic petroleum systems identified using decision-tree chemometrics. American Association of Petroleum Geologists Bulletin 91, 877-913]. Second, present day geographic locations for each sample were used to restore the tectonic paleolatitude of the source rock during Late Jurassic time (???150 Ma). Third, partial least squares regression (PLSR) was used to construct linear TGP models that relate tectonic and geochemical paleolatitude, where the latter is based on 19 source-related biomarker and isotope ratios for each oil family. The TGP models were calibrated using 70% of the samples in each family and the remaining 30% of samples were used for model validation. Positive relationships exist between tectonic and geochemical paleolatitude for each family. Standard error of prediction for geochemical paleolatitude ranges from 0.9?? to 2.6?? of tectonic paleolatitude, which translates to a relative standard error of prediction in the range 1.5-4.8%. The results suggest that the observed effect of source rock paleolatitude on crude oil composition is caused by (i) stable carbon isotope fractionation during photosynthetic fixation of carbon and (ii) species diversity at different latitudes during Late Jurassic time. ?? 2008 Elsevier Ltd. All rights reserved.

Organic Geochemistry↗

USGS2014

Activities in tectonics of Research Committee of American Association of Petroleum Geologists

During 1945 and 1946, the Research Committee of the American Association of Petroleum Geologists, under the chairmanship of Shepard W. Lowman, has been engaged in “a reconnaissance survey of research in petroleum geology and allied sciences with explicit reference to exploration” in order “to formulate a comprehensive research program which the American Association of Petroleum Geologists may adopt as its recommendation for that research most needed to improve our ability to find oil” [see “References” at end of report, Lowman, 1945]. In order to make this survey, the field was divided among a number of subcommittees, including a Subcommittee on Tectonics, of which the writer was chairman. Preliminary reports, discussing the research possibilities in the various fields covered by the subcommittees, were submitted in January, 1946, and concrete recommendations were formulated by the Research Committee at the Chicago meeting of the Association in April 1946 [Lowman, 1946]. Final reports of the subcommittees will be published later in 1946 in the Bulletin of the American Association of Petroleum Geologists.

Eos, Transactions, American Geophysical Union↗

USGS1999

The search for a source rock for the giant Tar Sand triangle accumulation, southeastern Utah

A large proportion (about 36%) of the worlds oil resource is contained in accumulations of heavy oil or tar. In these large deposits of degraded oil, the oil in place represents only a fraction of what was present at the time of accumulation. In many of these deposits, the source of the oil is unknown, and the oil is thought to have migrated over long distances to the reservoirs. The Tar Sand triangle in southeastern Utah contains the largest tar sand accumulation in the United States, with 6.3 billion bbl of heavy oil estimated to be in place. The deposit is thought to have originally contained 13-16 billion bbl prior to the biodegradation, water washing, and erosion that have taken place since the middle-late Tertiary. The source of the oil is unknown. The tar is primarily contained within the Lower Permian White Rim Sandstone, but extends into permeable parts of overlying and underlying beds. Oil is interpreted to have migrated into the White Rim sometime during the Tertiary when the formation was at a depth of approximately 3500 m. This conclusion is based on integration of fluid inclusion analysis, time-temperature reconstruction, and apatite fission-track modeling for the White Rim Sandstone. Homogenization temperatures cluster around 85-90°C for primary fluid inclusions in authigenic, nonferroan dolomite in the White Rim. The fluid inclusions are associated with fluorescent oil-bearing inclusions, indicating that dolomite precipitation was coeval with oil migration. Burial reconstruction suggests that the White Rim Sand stone reached its maximum burial depth from 60 to 24 Ma, and that maximum burial was followed by unroofing from 24 to 0 Ma. Time-temperature modeling indicates that the formation experienced temperatures of 85-90°C from about 35 to 40 Ma during maximum burial. Maximum formation temperatures of about 105-110°C were reached at about 24 Ma, just prior to unroofing. Thermal modeling is used to examine the history of potential source rocks for the White Rim oil. The most attractive potential sources for White Rim oil include beds within one or more of the following formations: the Proterozoic Chuar Group, which is present in the subsurface southwest of the Tar Sand triangle; the Mississippian Delle Phosphatic Member of the Deseret Limestone and equivalent formations, the Permian Kaibab Limestone, the Sinbad Limestone Member of the Triassic Moenkopi Formation, and the Jurassic Arapien Shale, Twin Creek Limestone, and Carmel Formation, which are present west of the Tar Sand triangle; the Pennsylvanian Paradox Formation in the Paradox basin east of the Tar Sand triangle; and the Permian Park City Formation northwest of the Tar Sand triangle. Each formation has a high total organic carbon content and is distributed over a wide enough geographic area to have provided a huge volume of oil. Source beds in all of the formations reached thermal maturity at times prior to or during the time that migration into the White Rim is interpreted to have occurred. Based on all available data, the most likely source for the Tar Sand triangle appears to be the Mississippian Delle Phosphatic Member of the Deseret Limestone. Secondary migration out of the Delle is interpreted to have occurred during the Cretaceous, during Sevier thrusting. Subsequent tertiary migration into the Tar Sand triangle reservoir is interpreted to have occurred later, during middle Tertiary Laramide deformation.

Utah↗

USGS2008

Flow unit modeling and fine-scale predicted permeability validation in Atokan sandstones: Norcan East Kansas

Characterizing the reservoir interval into flow units is an effective way to subdivide the net-pay zone into layers for reservoir simulation. Commonly used flow unit identification techniques require a reliable estimate of permeability in the net pay on a foot-by-foot basis. Most of the wells do not have cores, and the literature is replete with different kinds of correlations, transforms, and prediction methods for profiling permeability in pay. However, for robust flow unit determination, predicted permeability at noncored wells requires validation and, if necessary, refinement. This study outlines the use o f a spreadsheet-based permeability validation technique to characterize flow units in wells from the Norcan East field, Clark County, Kansas, that produce from Atokan aged fine- to very fine-grained quartzarenite sandstones interpreted to have been deposited in brackish-water, tidally dominated restricted tidal-flat, tidal-channel, tidal-bar, and estuary bay environments within a small incised-valley-fill system. The methodology outlined enables the identification of fieldwide free-water level and validates and refines predicted permeability at 0.5-ft (0.15-m) intervals by iteratively reconciling differences in water saturation calculated from wire-line log and a capillary-pressure formulation that models fine- to very fine-grained sandstone with diagenetic clay and silt or shale laminae. The effectiveness of this methodology was confirmed by successfully matching primary and secondary production histories using a flow unit-based reservoir model of the Norcan East field without permeability modifications. The methodologies discussed should prove useful for robust flow unit characterization of different kinds of reservoirs. Copyright ?? 2008. The American Association of Petroleum Geologists. All rights reserved.

American Association of Petroleum Geologists Bulle↗

USGS2014

Upper Devonian–Mississippian stratigraphic framework of the Arkoma Basin and distribution of potential source-rock facies in the Woodford–Chattanooga and Fayetteville–Caney shale-gas systems

Wireline logs were used to document the stratigraphic framework of Upper Devonian–Mississippian strata in the Arkoma Basin, and maps of high-gamma ray (HGR) log response were used to analyze the spatial distribution of potential source rocks in the Woodford–Chattanooga and Fayetteville–Caney shale-gas systems. The Woodford–Chattanooga shale is a transgressive deposit that accumulated on an arid continental margin influenced by marine upwelling and minimal sediment influx. A broad HGR depocenter along the southwestern margin of the basin includes two areas of higher accommodation containing the thickest HGR concentrations. Basin-wide patterns of HGR likely reflect broad tectonic influence on accommodation. The proportion of chert in the formation increases eastward and southward, likely reflecting latitudinal and bathymetric influence on the accumulation of siliceous ooze. The Lower Mississippian Burlington sequence, which lies between the two shale-gas systems, comprises carbonate ramp and distal shale deposits. Proximal ramp facies form an apron around the southern flank of the Ozark uplift and grade radially basinward into distal facies. An Upper Mississippian succession in the east includes lowstand deposits of the Batesville delta, which onlap the relict Burlington ramp. Basinwide, the succession includes the transgressive Fayetteville–Caney shale overlain by regressive deposits of the proximal Pitkin Limestone and distal upper Fayetteville (Arkansas) and “false” Caney (Oklahoma) shale. The HGR shale is concentrated in an area of intermediate accommodation on the western margin of the Mississippi Embayment and just basinward of the Pitkin Limestone pinchout in Arkansas, and in an area of relatively high accommodation in Oklahoma.

Arkansas, Oklahoma↗

USGS2004

Climate change: Conflict of observational science, theory, and politics

Debate over whether human activity causes Earth climate change obscures the immensity of the dynamic systems that create and maintain climate on the planet. Anthropocentric debate leads people to believe that they can alter these planetary dynamic systems to prevent that they perceive as negative climate impacts on human civilization. Although politicians offer simplistic remedies, such as the Kyoto Protocol, global climate continues to change naturally. Better planning for the inevitable dislocations that have followed natural global climate changes throughout human history requires us to accept the fact that climate will change, and that human society must adapt to the changes. Over the last decade, the scientific literature reported a shift in emphasis from attempting to build theoretical models of putative human impacts on climate to understanding the planetwide dynamic processes that are the natural climate drivers. The current scientific literature is beginning to report the history of past climate change, the extent of natural climate variability, natural system drivers, and the episodicity of many climate changes. The scientific arguments have broadened from focus upon human effects on climate to include the array of natural phenomena that have driven global climate change for eons. However, significant political issues with long-term social consequences continue their advance. This paper summarizes recent scientific progress in climate science and arguments about human influence on climate. ?? 2004. The American Association of Petroleum Geologists. All rights reserved.

American Association of Petroleum Geologists Bulle↗

USGS2006

Evolution of fracture and fault-controlled fluid pathways in carbonates of the Albanides fold-thrust belt

The process of fracture and fault formation in carbonates of the Albanides fold-thrust belt has been systematically documented using hierarchical development of structural elements from hand sample, outcrop, and geologic-map scales. The function of fractures and faults in fluid migration was elucidated using calcite cement and bitumen in these structures as a paleoflow indicator. Two prefolding pressure-solution and vein assemblages were identified: an overburden assemblage and a remote tectonic stress assemblage. Sheared layer-parallel pressure-solution surfaces of the overburden assemblage define mechanical layers. Shearing of mechanical layers associated with folding resulted in the formation of a series of folding assemblage fractures at different orientations, depending on the slip direction of individual mechanical layers. Prefolding- and folding-related fracture assemblages together formed fragmentation zones in mechanical layers and are the sites of incipient fault localization. Further deformation along these sites was accommodated by rotation and translation of fragmented rock, which formed breccia and facilitated fault offset across multiple mechanical layers. Strike-slip faults formed by this process are organized in two sets in an apparent conjugate pattern. Calcite cement and bitumen that accumulated along fractures and faults are evidence of localized fluid flow along fault zones. By systematic identification of fractures and faults, their evolution, and their fluid and bitumen contents, along with subsurface core and well-log data, we identify northeast-southwest-trending strike-slip faults and the associated structures as dominant fluid pathways in the Albanides fold-thrust belt. Copyright ?? 2006. The American Association of Petroleum Geologists. All rights reserved.

American Association of Petroleum Geologists Bulle↗

USGS1981

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 (C 12 + ) 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.

Alaska↗

USGS1981

Lithology, reservoir properties, and burial history of portion of Gammon Shale (Cretaceous), southwestern North Dakota

In the northern Great Plains, large quantities of biogenic methane are contained at shallow depths in Cretaceous marine mudstones. The Gammon Shale and equivalents of the Milk River Formation in Canada, which comprise most sediments deposited offshore during the Eagle-Telegraph Creek regression, are typical of such gas-bearing rocks. At Little Missouri field, southwestern North Dakota, Gammon reservoirs consist of discontinuous lenses and laminae of siltstone, less than 10 mm thick, enclosed by silty clay shale. Large amounts of allogenic clay, including highly expansible mixed-layer illite-smectite cause great water sensitivity and high measured and calculated water-saturation values. Reconstructed burial depths, clay mineralogy, and organic matter maturation studies show that the Gammon has not undergone thermal conditions sufficient for oil or thermal gas generation. Scarce authigenic minerals such as pyrite, siderite, and calcite probably formed as a result of bacterial metabolism early in the burial history. The scarcity of authigenic silicates suggests that diagenesis has been inhibited during much of the burial history by the presence of free methane. Shale layers are practically impermeable whereas siltstone microlenses are porous (30 to 40%) and have permeabilities on the order of 3 to 30 md. Reservoir continuity between siltstone layers is poor and, overall, reservoir permeability is probably less than 0.4 md. Connecting passageways between siltstone lenses are 0.1 µm or less in diameter. Organic matter in the low-permeability reservoirs served as the source of biogenic methane, and capillary forces acted as the trapping mechanism for gas accumulation. At Little Missouri field, reservoirs and non-reservoirs cannot be distinguished on the basis of lithology, and much of the Gammon interval is potentially economic. Future research should be directed toward determining the physical basis of log response in the low-permeability reservoirs and toward the development or application of water-free recovery technology.

North Dakota↗

USGS1981

Paleogeography and sedimentology of Upper Cretaceous turbidites, San Diego, California

Upper Cretaceous (Campanian and Maestrichtian) marine strata of the Rosario Group in the San Diego area include the Point Loma Formation and overlying Cabrillo Formation. These units contain six facies associations: (1) shelf and lagoonal sandstone, (2) slope and basin-plain(?) mudstone, (3) outer-fan lobe sandstone, (4) middle-fan channel-fill sandstone, (5) middle-and inner-fan interchannel and channel-margin thin-bedded turbidites and mudstone, and (6) inner-fan channel-fill conglomerate and sandstone. The facies associations define a deep-sea fan deposited by westward-flowing sediment gravity flows that transported sediments derived chiefly from batholithic and prebatholithic metamorphic rocks of the Peninsular Ranges. The sedimentary basin initially deepened abruptly, partly aided by eustatic sea-level rise. The fan then prograded westward into the basin, with a retrogradational phase recorded in the uppermost part of the sequence, which is erosionally truncated by transgressive lower Eocene conglomerate. The fan was deposited along the eastern edge of a forearc basin similar to that of the Great Valley sequence in northern California. The western part of the fan, which probably contained mostly outer-fan lobe and associated basin-plain deposits, appears to have been truncated by late Cenozoic strike-slip faulting associated with the San Andreas fault system. The fan and remnants of the western part of the basin and associated subduction complex may be present on the northwest in the Channel Islands region or still farther north.

California↗

USGS1981

Determination of organic-matter content of Appalachian Devonian shales from gamma-ray logs

The organic-matter content of the Devonian shale of the Appalachian basin is important for assessing natural-gas resources. In most of the western part of the Appalachian basin the organic-matter content of the Devonian shale can be estimated from gamma-ray wire-line logs. Organic-matter contents estimated using these logs are compared with determinations from direct laboratory analyses of organic carbon for 74 intervals of varying thickness from 12 widely separated wells. The cumulative pool of gamma-ray logs for the Devonian shale forms a large and geographically broad data base. The approach may also be applicable to other formations.-from Author

Appalachian Basin↗

USGS1981

Stratigraphic and economic significance of Mississippian sequence at North Georgetown Canyon, Idaho

The Mississippian sequence exposed at North Georgetown Canyon, Idaho is newly recognised as a facies belt, which adds to knowledge of Mississippian stratigraphy and petroleum geology in the Overthrust belt of Idaho, Wyoming, and Utah. In the newly recognized facies belt in the Aspen Range, the Madison Group is represented by the Lodgepole Limestone and Mission Canyon Limestone. The overlying beds of middle Osagean to middle Chesterian age are a unique combination of deep-basin shallowing upward to peritidal lithofacies (the Aspen Range Formation). An organic-rich phosphatic member at the base of this is a possible petroleum source rock. Westward thinning of the Mission Canyon Limestone suggests a pinch-out that may provide stratigraphic traps for petroleum.-from Authors

Idaho↗

USGS1981

Lithostratigraphy of Shell 272-1 and 273-1 Wells: Implications as to depositional history of the Baltimore Canyon Trough, Mid- Atlantic OCS

Upper Jurassic gray and red-brown shale, sandstone, and coal are the oldest strata penetrated by the Shell 272-1 and 273-1 wells, located approximately 66 mi (106 km) southeast of Atlantic City, New Jersey, in the northwest part of the Baltimore Canyon Trough. The Lower Cretaceous section consists of gray shale that is overlain by a sequence of thick-bedded sandstones interbedded with thin-bedded shales. The Upper Cretaceous section is dominated by slightly calcareous mudstone, but also contains a Coniacian to Campanian sandstone. The Cenozoic section is mainly mudstone and overlying unconsolidated sand. Seven major lithologic units were established and correlated to the COST B-2 and B-3 wells. The depositional environments of the Upper Jurassic rocks range from an upper delta plain facies penetrated in the two Shell wells and the B-2 well to a back-reef facies penetrated in the B-3 well. The Lower Cretaceous strata, in a vertical sequence, consist of upper delta plain, lower delta plain, interdistributary bay and/or marginal marine, and distributary-mouth-bar deposits. A Cenomanian sandstone penetrated in the B-3 well is the youngest indicator of deltaic deposition; marine strata dominate the remainder of the Upper Cretaceous and Cenozoic.

Baltimore Canyon Trough↗

USGS1981

Faulting in outer continental shelf of southern Bering Sea

Synthesis of more than 10 000 line-km of high-resolution seismic data indicates the distribution, types, and trends of faults present on the outer continental shelf of the southern Bering Sea. Faults are classified into three types as to whether they 1) offset the sea floor (surface fault), 2) show less than 5m of displacement (minor fault), of 3) show more than 5m of displacement (major fault). The distribution of surface faults follows the outline of St George basin and suggests that the basin is presently subsiding. Minor faults are concentrated throughout St George and Amak basins but are not common elsewhere in the region. Major faults appear to be associated with the boundary faults of St George and, to a lesser extent, Amak basins. The faulting is probably a result of earthquake-induced energies that reactivate zones of weakness inherited from the collapse of the margin during the late Mesozoic-early Tertiary. -Authors

Alaska↗

USGS1981

Geology of central Lake Michigan

The geology beneath Lake Michigan between 43°00' and 44°00' N and between 86°30' and 87°40' W is interpreted from a synthesis of 1,700 km of continuous seismic reflection profile data, bathymetry, grab samples, and onshore surface and subsurface information. The continuous seismic reflection profiles and bathymetry provided information for maps of unconsolidated sediment thickness and Paleozoic bedrock topography. The map of unconsolidated sediment (primarily Pleistocene) shows thicknesses ranging from 180 m in a steep-walled, northeast-trending valley to less than 10 m over a mid-lake topographic high. This valley and the mid-lake high are the dominant topographic features developed on the gently eastward-dipping Paleozoic rocks along this part of the western flank of the Michigan basin. Two structural-stratigraphic cross sections of the study area were constructed by utilizing a composite subsurface-surface section for eastern Wisconsin and two control wells in western Michigan. The cross sections, grab samples previously described in the literature, the bedrock topographic map, and published maps were used to construct a Paleozoic geologic map for central Lake Michigan. Rocks from Middle Silurian through Early Mississippian age form subcrops beneath the study area, whereas rocks of Early Silurian, Ordovician, and Late Cambrian age are present at greater depth. The Upper Cambrian rocks unconformably overlie Precambrian igneous and metamorphic rocks. The structural-stratigraphic cross sections also allow us to speculate about the petroleum potential beneath Lake Michigan. The possibility of oil occurrences within the Silurian is enhanced by major east-west facies changes, and other horizons with promise are present in Devonian and Ordovician rocks. Although Michigan and Wisconsin laws currently prohibit petroleum exploration in Lake Michigan, it is an area with future potential.

Michigan, Wisconsin↗

USGS1982

Geology of continental shelf, Onslow Bay, North Carolina, as revealed by submarine outcrops

Lithologic and stratigraphic data from rocks dredged from the continental shelf off Onslow Bay, North Carolina, provide surface control for seismic studies of the southeastern United States continental margin and help to explain the distribution of potentially economic phosphate-rich sediments on this shelf. Outcropping Miocene rocks in this area indicate that the region has long been a positive geologic feature and has received relatively little Pliocene and Pleistocene sedimentation. -from Authors

North Carolina↗

USGS1982

Volume of organic-rich Devonian shale in the Appalachian Basin: relating "black" to organic-matter content: Geologic notes

Some estimates of natural-gas resources in the Devonian shale of the Appalachian basin depend on the volume of organic-rich shale in the basin. A map by L. G. Wallace and W. de Witt showing the thickness and extent of Devonian "black" shale facies in the Appalachian basin is widely used as an indicator of organic-rich shale, but the map is derived from subjective evaluations of shale color. Wallace and de Witt's definition of "black" is shown here to correspond to an organic-matter content of approximately 4% or more by volume and a Munsell color value for dry pressed-powder samples of about N5 (medium gray) or darker. The volume of Devonian shale with an organic-matter content greater than 2.0% by volume (a definition of "organic-rich" that is preferred by the writers) a erages 1.44 times that of the "black" shale of Wallace and de Witt, and totals about 2,574 × 10 12 cu ft (72.9 × 10 12 cu m) in the Appalachian basin.

Appalachian Basin↗