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T. S. Dyman

Publications and source records attributed to T. S. Dyman.

At least 19 recordsLinked to original sources
USGS2008

Stratigraphy and structural setting of Upper Cretaceous Frontier Formation, western Centennial Mountains, southwestern Montana and southeastern Idaho

Stratigraphic, sedimentologic, and palynologic data were used to correlate the Frontier Formation of the western Centennial Mountains with time-equivalent rocks in the Lima Peaks area and other nearby areas in southwestern Montana. The stratigraphic interval studied is in the middle and upper parts (but not uppermost) of the formation based on a comparison of sandstone petrography, palynologic age data, and our interpretation of the structure using a seismic line along the frontal zone of the Centennial Mountains and the adjacent Centennial Valley. The Frontier Formation is comprised of sandstone, siltstone, mudstone, limestone, and silty shale in fluvial and coastal depositional settings. A distinctive characteristic of these strata in the western Centennial Mountains is the absence of conglomerate and conglomeratic sandstone beds. Absence of conglomerate beds may be due to lateral facies changes associated with fluvial systems, a distal fining of grain size, and the absence of both uppermost and lower Frontier rocks in the study area. Palynostratigraphic data indicate a Coniacian age for the Frontier Formation in the western Centennial Mountains. These data are supported by a geochronologic age from the middle part of the Frontier at Lima Peaks indicating a possible late Coniacian-early Santonian age (86.25 ?? 0.38 Ma) for the middle Frontier there. The Frontier Formation in the western Centennial Mountains is comparable in age and thickness to part of the Frontier at Lima Peaks. These rocks represent one of the thickest known sequences of Frontier strata in the Rocky Mountain region. Deposition was from about 95 to 86 Ma (middle Cenomanian to at least early Santonian), during which time, shoreface sandstone of the Telegraph Creek Formation and marine shale of the Cody Shale were deposited to the east in the area now occupied by the Madison Range in southwestern Montana. Frontier strata in the western Centennial Mountains are structurally isolated from other Cretaceous rocks in the region and are part of the Lima thrust sheet that lies at the leading edge of the Sevier-style overthrusting in this part of southwestern Montana and adjacent southeastern Idaho.

Cretaceous Research↗
USGS2006

Chapter 2. Assessment of undiscovered conventional oil and gas resources–Upper Jurassic-Lower Cretaceous Cotton Valley group, Jurassic Smackover interior salt basins total petroleum system, in the East Texas basin and Louisiana-Mississippi salt basins provinces

The Jurassic Smackover Interior Salt Basins Total Petroleum System is defined for this assessment to include (1) Upper Jurassic Smackover Formation carbonates and calcareous shales and (2) Upper Jurassic and Lower Cretaceous Cotton Valley Group organic-rich shales. The Jurassic Smackover Interior Salt Basins Total Petroleum System includes four conventional Cotton Valley assessment units: Cotton Valley Blanket Sandstone Gas (AU 50490201), Cotton Valley Massive Sandstone Gas (AU 50490202), Cotton Valley Updip Oil and Gas (AU 50490203), and Cotton Valley Hypothetical Updip Oil (AU 50490204). Together, these four assessment units are estimated to contain a mean undiscovered conventional resource of 29.81 million barrels of oil, 605.03 billion cubic feet of gas, and 19.00 million barrels of natural gas liquids. The Cotton Valley Group represents the first major influx of clastic sediment into the ancestral Gulf of Mexico. Major depocenters were located in south-central Mississippi, along the Louisiana-Mississippi border, and in northeast Texas. Reservoir properties and production characteristics were used to identify two Cotton Valley Group sandstone trends across northern Louisiana and east Texas: a high-permeability blanket-sandstone trend and a downdip, low-permeability massive-sandstone trend. Pressure gradients throughout most of both trends are normal, which is characteristic of conventional rather than continuous basin-center gas accumulations. Indications that accumulations in this trend are conventional rather than continuous include (1) gas-water contacts in at least seven fields across the blanket-sandstone trend, (2) relatively high reservoir permeabilities, and (3) high gas-production rates without fracture stimulation. Permeability is sufficiently low in the massive-sandstone trend that gas-water transition zones are vertically extensive and gas-water contacts are poorly defined. The interpreted presence of gas-water contacts within the Cotton Valley massive-sandstone trend, however, suggests that accumulations in this trend are also conventional.

Alabama, Arkansas. Florida, Georgia, Louisiana, Mi↗
USGS2006

Chapter 5. Assessment of undiscovered conventional oil and gas resources-Lower Cretaceous Travis Peak and Hosston formations, Jurassic Smackover interior salt basins total petroleum system, in the East Texas basin and Louisiana-Mississippi salt basins provinces

The Lower Cretaceous Travis Peak Formation of east Texas and southern Arkansas (and the correlative Hosston Formation of Louisiana and Mississippi) is a basinward-thickening wedge of terrigenous clastic sedimentary rocks that underlies the northern Gulf of Mexico Basin from east Texas across northern Louisiana to southern Mississippi. Clastic detritus was derived from two main fluvial-deltaic depocenters, one in northeastern Texas and the other extending from southeastern Mississippi northwestward into northeastern Louisiana. Across the main hydrocarbon-productive trend in east Texas and northern Louisiana, the Travis Peak and Hosston Formations are about 2,000 ft thick. The most likely sources for hydrocarbons in Travis Peak and Hosston reservoirs are two stratigraphically lower units, lime mudstones of the Upper Jurassic Smackover Formation and organic-rich shales of the Upper Jurassic Bossier Shale of the Cotton Valley Group. As a result of the absence of proximal source rocks and a lack of effective migration pathways from stratigraphically or geographically distant source rocks, hydrocarbon charge is sufficient for development of conventional gas accumulations but insufficient for development of basin-centered gas. The petroleum assessment of the Travis Peak and Hosston Formations was conducted by using a total petroleum system model. A total petroleum system includes all of the important elements of a hydrocarbon fluid system needed to develop oil and gas accumulations, including source and reservoir rocks, hydrocarbon generation, migration, traps and seals, and undiscovered accumulations. A total petroleum system is mappable and may include one or more assessment units. For each assessment unit, reservoir rocks contain similar geology, exploration characteristics, and risk. The Jurassic Smackover Interior Salt Basins Total Petroleum System is defined for this assessment to include (1) Upper Jurassic Smackover carbonates and calcareous shales and organic-rich shales of the Upper Jurassic Bossier Shale of the Cotton Valley Group and (2) Lower Cretaceous Travis Peak and Hosston Formations. The Jurassic Smackover Interior Salt Basins Total Petroleum System includes three conventional Travis Peak-Hosston assessment units: Travis Peak-Hosston Gas and Oil (AU 50490205), Travis Peak-Hosston Updip Oil (AU 50490206), and Travis Peak-Hosston Hypothetical Updip Oil (AU 50490207). A fourth assessment unit, the Hosston Hypothetical Slope-Basin Gas Assessment Unit, was named and numbered (AU 50490208) but not geologically defined or quantitatively assessed owing to a lack of data. Together, assessment units 50490205 to 50490207 are estimated to contain a mean undiscovered conventional resource of 29 million barrels of oil, 1,136 billion cubic feet of gas, and 22 million barrels of natural gas liquids.

Alabama, Arkansas. Florida, Georgia, Louisiana, Mi↗
USGS2006

Chapter 2: 2003 Geologic Assessment of Undiscovered Conventional Oil and Gas Resources in the Upper Cretaceous Navarro and Taylor Groups, Western Gulf Province, Texas

The Upper Cretaceous Navarro and Taylor Groups in the western part of the Western Gulf Province were assessed for undiscovered oil and gas resources in 2003. The area is part of the Smackover-Austin-Eagle Ford Composite Total Petroleum System. The rocks consist of, from youngest to oldest, the Escondido and Olmos Formations of the Navarro Group and the San Miguel Formation and the Anacacho Limestone of the Taylor Group (as well as the undivided Navarro Group and Taylor Group). Some units of the underlying Austin Group, including the 'Dale Limestone' (a term of local usage that describes a subsurface unit), were also part of the assessment in some areas. Within the total petroleum system, the primary source rocks comprise laminated carbonate mudstones and marine shales of the Upper Jurassic Smackover Formation, mixed carbonate and bioclastic deposits of the Upper Cretaceous Eagle Ford Group, and shelf carbonates of the Upper Cretaceous Austin Group. Possible secondary source rocks comprise the Upper Jurassic Bossier Shale and overlying shales within the Upper Jurassic to Lower Cretaceous Cotton Valley Group, Lower Cretaceous marine rocks, and the Upper Cretaceous Taylor Group. Oil and gas were generated in the total petroleum system at different times because of variations in depth of burial, geothermal gradient, lithology, and organic-matter composition. A burial-history reconstruction, based on data from one well in the eastern part of the study area (Jasper County, Tex.), indicated that (1) the Smackover generated oil from about 117 to 103 million years ago (Ma) and generated gas from about 52 to 41 Ma and (2) the Austin and Eagle Ford Groups generated oil from about 42 to 28 Ma and generated gas from about 14 Ma to the present. From the source rocks, oil and gas migrated upsection and updip along a pervasive system of faults and fractures as well as along bedding planes and within sandstone units. Types of traps include stratigraphic pinchouts, folds, faulted folds, and combinations of these. Seals consist of interbedded shales and mudstones and diagenetic cementation. The area assessed is divided into five assessment units (AUs): (1) Travis Volcanic Mounds Oil (AU 50470201), (2) Uvalde Volcanic Mounds Gas and Oil (AU 50470202), (3) Navarro-Taylor Updip Oil and Gas (AU 50470203), (4) Navarro-Taylor Downdip Gas and Oil (AU 50470204), and (5) Navarro-Taylor Slope-Basin Gas (AU 50470205). Total estimated mean undiscovered conventional resources in the five assessment units combined are 33.22 million barrels of oil, 1,682.80 billion cubic feet of natural gas, and 34.26 million barrels of natural gas liquids.

Data Series↗
USGS2002

Worldwide estimates of deep natural gas resources based on the U.S. Geological Survey World Petroleum Assessment 2000

The U.S. Geological Survey recently assessed undiscovered conventional gas and oil resources in eight regions of the world outside the U.S. The resources assessed were those estimated to have the potential to be added to reserves within the next thirty years. This study is a worldwide analysis of the estimated volumes and distribution of deep (>4.5 km or about 15,000 ft), undiscovered conventional natural gas resources based on this assessment. Two hundred forty-six assessment units in 128 priority geologic provinces, 96 countries, and two jointly held areas were assessed using a probabilistic Total Petroleum System approach. Priority geologic provinces were selected from a ranking of 937 provinces worldwide. The U.S. Geological Survey World Petroleum Assessment Team did not assess undiscovered petroleum resources in the U.S. For this report, mean estimated volumes of deep conventional undiscovered gas resources in the U.S. are taken from estimates of 101 deep plays (out of a total of 550 conventional plays in the U.S.) from the U.S. Geological Survey's 1995 National Assessment of Oil and Gas Resources. A probabilistic method was designed to subdivide gas resources into depth slices using a median-based triangular probability distribution as a model for drilling depth to estimate the percentages of estimated gas resources below various depths. For both the World Petroleum Assessment 2000 and the 1995 National Assessment of Oil and Gas Resources, minimum, median, and maximum depths were assigned to each assessment unit and play; these depths were used in our analysis. Two-hundred seventy-four deep assessment units and plays in 124 petroleum provinces were identified for the U.S. and the world. These assessment units and plays contain a mean undiscovered conventional gas resource of 844 trillion cubic ft (Tcf) occuring at depths below 4.5 km. The deep undiscovered conventional gas resource (844 Tcf) is about 17% of the total world gas resource (4,928 Tcf) based on the provinces assessed and includes a mean estimate of 259 Tcf of U.S. gas from the U.S. 1995 National Assessment. Of the eight regions, the Former Soviet Union (Region 1) contains the largest estimated volume of undiscovered deep gas with a mean resource of343 Tcf.

Natural Resources Research↗
USGS1998

Stratigraphy and depositional environment of nonmarine facies of Frontier Formation, Eastern Pioneer Mountains, southwestern Montana

The Upper Cretaceous Frontier Formation in the eastern Pioneer Mountains of southwestern Montana was deposited in nonmarine environments west of the Western Interior Seaway within the Cordilleran foreland basin. These rocks have been assigned to the Frontier because they contain lithologies typical of the Frontier in the region even though they are entirely nonmarine and are thicker than the correlative marine Frontier to the east. The Frontier in the eastern Pioneer Mountains is underlain by the Vaughn Member of the Blackleaf Formation, but the upper part of the Frontier has been eroded and locally is overlain by rocks of Tertiary age. Geologic mapping was conducted and four sections were measured and described to determine facies, thickness variations, and depositional environments. In the eastern Pioneer Mountains study area, the Frontier ranges in thickness from about 1200 ft (366 m) in the south to more than 3400 ft (1036 m) in the north\. Frontier strata in the study area cannot be readily subdivided into mappable units, but two broadly-defined informal lithic units are described. The lower unit contains yellow-brown weathering siltstone, mudstone, and fine-grained quartz-rich sandstone, and is about 250 ft (76 m) thick. The upper unit is composed of yellow-brown to dark-gray siltstone and mudstone, quartz- and chert-rich sandstone, conglomeratic sandstone, and limestone, and is more than 2100 ft (640 m) thick in one measured section. The lower contact of the Frontier is placed at the top of a porcellanite bed that is associated with maroon mudstone and siltstone, limestone, and calcareous dark-gray shale in the underlying Vaughn Member of the Blackleaf Formation. The porcellanite bed directly overlies the highest maroon mudstone-siltstone bed of the upper Vaughn. The Frontier Formation in the eastern Pioneer Mountains was deposited on a broad delta plain dominated by fine-grained sediments. Sandstones exhibit characteristics of anastomosing fluvial channels, average 5% to 10% of the entire formation, and have width to depth ratios of less than 30. The Frontier in the eastern Pioneer Mountains is lithostratigraphically equivalent to the Frontier to the east in the Gravelly, Greenhorn, and Madison Ranges, but may include strata that are younger in age. Frontier strata to the south at Lima Peaks are the thickest in the region (up to 7000 ft; 2100 m) and include facies that are time-equivalent to the marine Frontier, the overlying Cody Shales, and the Telegraph Creek Formation of the Madison Range to the east. The Frontier in the eastern Pioneer Mountains is in part lithostratigraphically equivalent to the Coberly Formation in the Drummond, Montana area (50 mi [80 km] northwest of Butte, Montana) and the Marias River Shales near Great Falls (150 mi [240 km] northeast of Butte) in west-central Montana.

Mountain Geologist↗
USGS1994

Cretaceous rocks from southwestern Montana to southwestern Minnesota, northern Rocky Mountains, and Great Plains

In Montana, Wyoming, North and South Dakota, and Minnesota, Cretaceous strata are preserved in the asymmetric Western Interior foreland basin. More than 5,200 m (17,000 ft) of Cretaceous strata are present in southwestern Montana, less than 300 m (1,000 ft) in eastern South Dakota. The asymmetry resulted from varying rates of subsidence due to tectonic and sediment loading. The strata consist primarily of sandstone, siltstone, mudstone, and shale. Conglomerate is locally abundant along the western margin, whereas carbonate is present in most areas of the eastern shelf. Sediment was deposited in both marine and nonmarine environments as the shoreline fluctuated during major tectonic and eustatic cycles. A discussion of Cretaceous strata from southwestern to east-central Montana, the Black Hills, eastern South Dakota, and southwestern Minnesota shows regional stratigraphy and facies relations, sequence, boundaries, and biostratigraphic and radiometric correlations. The thick Cretaceous strata in southwestern Montana typify nonmarine facies of the rapidly subsiding westernmost part of the basin. These strata include more than 3,000 m (10,000 ft) of synorogenic conglomerate of the Upper Cretaceous part of the Beaverhead Group. West of the Madison Range, sequence boundaries bracket the Kootenai (Aptian and Albian), the Blackleaf (Albian and Cenomanian), and the Frontier Formations (Cenomanian and Turonian); sequence boundaries are difficult to recognize because the rocks are dominantly non-marine. Cretaceous strata in east-central Montana (about 1,371 m; 4,500 ft thick) lie at the approximate depositional axis of the basin and are mostly marine terrigenous rocks. Chert-pebble zones in these rocks reflect stratigraphic breaks that may correlate with sequence boundaries to the east and west. Cretaceous rocks of the Black Hills region consist of a predominantly marine clastic sequence averaging approximately 1,524 m (5,000 ft) thick. The Cretaceous System in eastern South Dakota (457 to 610 m; 1,500 to 2,000 ft thick) consists of a marine shelf sequence dominated by shale and limestone. Major sequence boundaries in South Dakota are at the base of the Lower Cretaceous Lakota Formation, Fall River Sandstone, and Muddy Sandstone, and bracket the Upper Cretaceous Niobrara Formation.

Book chapter↗