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At least 55 records · Page 3Linked to original sources
USGS2006

Structural fabrics, mineralization and Lamaride kinematics of the Idaho Springs-Ralston shear zone, Colorado mineral belt and central Front Range uplift

The Idaho Springs and Central City mining districts form the central portion of a structurally controlled hydrothermal precious- and base-metal vein system in the Front Range of the northeast-trending Colorado Mineral Belt. Three new 40Ar/39Ar plateau ages on hydrothermal sericite indicate the veins formed during the Laramide orogeny between 65.4??1.5 - 61.9??1.3 Ma. We compile structural geologic data from surface geological maps, subsurface mine maps, and theses for analysis using modern graphical methods and integration into models of formation of economic mineral deposits. Structural data sets, produced in the 1950s and 1960s by the U.S. Geological Survey, are compiled for fabric elements, including metamorphic foliations, fold axial trends, major brittle fault zones, quartz and precious- and base-metal veins and fault veins, Tertiary dikes, and joints. These fabric elements are plotted on equal-area projections and analyzed for mean fabric orientations. Strike-slip fault-vein sets are mostly parallel or sub-parallel, and not conjugate as interpreted by previous work; late-stage, normal-slip fault veins possibly show a pattern indicative of triaxial strain. Fault-slip kinematic analysis was used to model the trend of the Laramide maximum horizontal stress axis, or compression direction, and to determine compatibility of opening and shear motions within a single stress field. The combined-model maximum compression direction for all strike slip fault veins is ???068??, which is consistent with published Laramide compression directions of ???064?? (mean of 23 regional models) and ???072?? for the Front Range uplift. The orientations of fabric elements were analyzed for mechanical and kinematic compatibility with opening, and thus permeability enhancement, in the modeled regional east-northeast, Laramide compression direction. The fabric orientation analysis and paleostress modeling show that structural permeability during mineralization was enhanced along pre-existing metamorphic foliations and fold axial planes. Large orientation dispersion in most fabric elements likely caused myriad potential pathways for permeability. The dominant orientations of opening and shear mode structures are consistent with a sub-parallel network of structures that formed in the Laramide east-northeast compression direction. The results presented demonstrate the importance of using mechanical and kinematic theory integrated with contemporary ideas of permeability structure to better understand the coupled nature of fluid flow, mineral deposition, stress, and strain. Further, the results demonstrate that there is significant internal strain within this basement-cored uplift that was localized by optimally oriented pre-existing structures in a regional stress field.

Mountain Geologist↗
USGS2007

Upper cretaceous microbial petroleum systems in north-central Montana

Cenomanian to Campanian rocks of north-central Montana contain shallow economic accumulations of dry natural gas derived from microbial methanogenesis. The methanogens utilized carbon dioxide derived from organic matter in the marginal marine sediments and hydrogen from in situ pore water to generate methane. The most recent USGS assessment of the shallow gas resources of eastern Montana used a petroleum systems approach, identifying the critical components of a petroleum system (source rock, reservoir rock, seal rock, and trap) and their temporal relationships. As a part of this effort, geochemical data from natural gas wells and associated formation waters were used to identify two microbial gas systems and the timing of methanogenesis. Two microbial gas families are identified in north-central Montana based on stable carbon isotope and gas composition. The Montana Group gas family has heavier δ 13 C methane values, slightly lighter δD methane values, and a lower carbon dioxide and nitrogen content than the Colorado Group gas family. The two gas families may reflect, in part, the source rock depositional environments, with the Colorado Group rocks representing a more offshore marine depositional environment and the Montana Group rocks representing proximal marine, deltaic and nonmarine depositional environments. Assuming the gas families reflect only source rock characteristics, two microbial petroleum systems can be defined. The first petroleum system, called the Colorado Group microbial gas system, consists of Colorado Group rocks with the shales in the Belle Fourche Formation, Greenhorn Formation, and the Carlile Shale as the presumed source rocks and the interbedded Phillips and Bowdoin sandstones and the Greenhorn Formation limestones as reservoirs. The second petroleum system, called the Montana Group microbial gas system, consists of the Montana Group rocks that include the Gammon Shale and possibly the Claggett Shale as source rocks and the Eagle Sandstone and the Judith River Formation as reservoirs. The Niobrara Formation is tentatively placed in the former system. The geographic extent of the two microbial systems is much larger than the study area and includes an area at least from the Alberta basin to the northwest to the Powder River basin to the southeast. Upper Cretaceous microbial gas accumulations have been recognized along these basin margins at burial depths less than 3000 ft, but have not been recognized within the deeper parts of the basins because subsequent charge of thermogenic oil and gas masks the preexisting microbial gas accumulations. Methanogenesis began soon after the deposition (early-stage methanogenesis) of the Cenomanian to Campanian source sediments, and was either sustained or rejuvenated by episodic meteoric water influx until sometime in the Paleogene. Methanogenesis probably continued until CO 2 and hydrogen were depleted or the pore size was compacted to below tolerance levels of the methanogens. The composition of the Montana and Colorado Group gases and coproduced formation water precludes a scenario of late-stage methanogenesis like the Antrim gas system in the Michigan basin. Some portion of the methane charge was originally dissolved in the pore waters, and subsequent reduction in hydrostatic pressure caused the methane to exsolve and migrate into local stratigraphic and structural traps. The critical moment of the microbial gas systems is this timing of exsolution rather than the time of generation (methanogenesis). Other studies suggest that the reduction in hydrostatic pressure may have been caused by multiple geologic events including the lowering of sea level in the Late Cretaceous, and subsequent uplift and erosion events, the youngest of which began about 5 Ma.

Montana↗
USGS2009

On the palynomorph-based biozones in paleogene strata of rocky mountain basins

In a paper published in this journal, and in five previous papers published elsewhere, Lillegraven and McKenna (2008) criticize the research of Nichols and Ott (1978) and Nichols and Flores (2006). They attempt to cast doubt on the validity of the palynomorph-based biozones (the "P- zone" system) applied in strata of Paleocene age throughout the Rocky Mountain region. Their conclusions are without merit.

Mountain Geologist↗
USGS2013

Review of oil families and their petroleum systems of the Williston Basin

The petroleum system concept was first applied in 1974 (Dow/Williams) to identify three oil systems in the Williston Basin, and recent studies have expanded the number to at least nine. This paper reviews the petroleum geochemistry, oil-oil, and oil-source correlations of the oil systems of the Williston Basin, providing a new perspective and some new findings. Petroleum systems with a known source (documented oil-source correlation) include the Red River (Ordovician), Winnipegosis (Devonian), Bakken (Devonian-Mississippian), Madison (Mississippian), and Tyler (Pennsylvanian) systems. Petroleum systems with an identified source rock but no documented oil-source correlation are considered hypothetical and include the Winnipeg (Ordovician), Duperow (Devonian), and Birdbear (Devonian). The Deadwood (Cambrian-Ordovician) petroleum system is speculative because a good oil-prone source rock has not been identified. The stratigraphic distribution of the oil families from each system is generally limited to the same formation from which they were sourced due to efficient seals and a paucity of vertical migration pathways, but some notable exceptions do occur. Oil bulk properties such as API gravity, sulfur content, and pour point are much underutilized in the recent geochemical literature and are found to be useful here in differentiating oil families. The Red River petroleum system has two oil families that can be differentiated based on pour point. The oils in the Madison petroleum system can be divided into two families based on API gravity-sulfur content relationships, with one family derived from Type II-S kerogen and the other family derived from Type II kerogen with medium sulfur content. The Tyler petroleum system of the Williston Basin may be distinguished from the Heath-Tyler petroleum system in central Montana based on differences in geology and petroleum geochemistry, with Tyler petroleum system oils having a higher pour point and lower sulfur content.

Williston Basin↗
USGS2010

Geology and undiscovered oil and gas resources in the Madison Group, Williston Basin, North Dakota and Montana

Two of the total petroleum systems (TPS) defined as part of the U.S. Geological Survey (USGS) assessment of the Williston Basin contain Mississippian Madison Group strata: 1) the Bakken-Lodgepole TPS, which includes the Lodgepole Formation; and 2) the Madison TPS, which includes the Mission Canyon, Charles, and Spearfish formations. The Bakken-Lodgepole TPS is defined as the area in which oil generated from the upper and lower shales of the Upper Devonian-Lower Mississippian Bakken Formation has accumulated in reservoirs in the Three Forks, Bakken, and Lodgepole formations. Two conventional assessment units (AU) have been identified within the Bakken-Lodgepole TPS, including one in the Bakken Formation and another in the Waulsortian mound reservoirs of the lower Lodgepole Formation. Lodgepole Formation Waulsortian mound oil production has been restricted to a small part of Stark County, North Dakota. Reservoirs are sealed by middle and upper Lodgepole Formation tight argillaceous limestones. Several nonproductive mounds and mound-like structures have also been identified in the Lodgepole Formation. Productivity correlates closely with the oil window of the Bakken Formation shales, and also indicates the likelihood of limited lateral migration of Bakken Formation oil into Lodgepole Formation reservoirs in North Dakota and Montana. Such considerations limit the estimated mean of undiscovered, technically recoverable resources to 8 million barrels of oil (MMBO) for the Lodgepole Formation conventional reservoirs. The Madison TPS is defined as the area where oil generated from Mission Canyon and Charles formation source rocks has accumulated in reservoirs of the Mission Canyon and Charles formations and in reservoirs within the Triassic Spearfish Formation. One continuous reservoir AU, the Mission Canyon-Charles AU, was defined within the Madison TPS; its boundary coincides with the TPS boundary. There is extensive conventional production throughout the AU on major structures and in stratigraphic-structural traps. The largest fields are on the Little Knife, Billings Nose, and Nesson anticlines. Recent studies show that Madison Group oils were generated from organic-rich Mission Canyon Formation and Ratcliffe Interval carbonates adjacent to the reservoirs. Seals were formed by overlying or lateral evaporites or tight carbonates. Based on available geologic and production data, the undiscovered oil resources for conventional reservoirs in the Mission Canyon-Charles AU were estimated to have a mean of 45 MMBO.

Mountain Geologist↗
USGS1980

Mineralogy and diagenesis of low-permeability sandstones of Late Cretaceous age, Piceance Creek Basin, northwestern Colorado

This report presents preliminary results of a mineralogic and diagenetic study of some low-permeability sandstones from measured surface sections and cores obtained from drill holes in the Piceance Creek Basin of northwestern Colorado. A documentation of the mineralogy and diagenetic history will aid in the exploration for natural gas and in the development of recovery technology in these low-permability sandstones. These sandstones are in the nonmarine upper part of the Mesaverde Formation (or Group) of Late Cretaceous age and are separated from overlying lower Tertiary rocks by a major regional unconformity. Attention is focused on the sandstone units of the Ohio Creek Member, which directly underlies the unconformity; however, comparisons between the mineralogy of the Ohio Creek strata and that of the underlying sandstone units are made whenever possible. The Ohio Creek is a member of the Hunter Canyon Formation (Mesaverde Group) in the southwestern part of the basin, and the Mesaverde Formation in the southern and central parts of the basin. The detrital mineralogy is fairly constant throughout all of these nonrnarine Cretaceous sandstone units; however, in the southeastern part of the basin, there is an increase in percentage of feldspar, quartzite, and igneous rock fragments in sandstones of the Ohio Creek Member directly underlying the unconformity. In the southwestern part of the basin, sandstones of the Ohio Creek Member are very weathered and are almost-entirely comprised of quartz, chert, and kaolinite. A complex diagenetic history, partly related to the overlying unconformity, appears to be responsible for transforming these sandstones into potential gas reservoirs. The general diagenetic sequence for the entire Upper Cretaceous interval studied is interpreted to be (early to late): early(?) calcite cement, chlorite, quartz overgrowths, calcite cement, secondary porosity, analcime (surface only), kaolinite and illite, and late carbonate cements. Authigenic high-iron chlorite, which occurs on grain rims and in pore throats, is primarily responsible for the low-permeability of the subsurface sandstones of the Ohio Creek Member in the center of the basin. Kaolinite is the most abundant pore-filling authigenic clay in these sandstones, from the southwestern part of the basin and is responsible for their distinctive white-weathering color in outcrop. In the sandstones below the Ohio Creek Member, however, chlorite and kaolinite occur locally, and authigenic calcite and illite are more abundant. The occurrence and distribution of secondary porosity is one of the most important aspects of the diagenetic history of these sandstones. It is present as moldic intra- and intergranular porosity, as well as microporosity among authigenic clay pariicles. Although present locally in most sandstone units, secondary porosity is particularly common in the uppermost sandstone units and is interpreted to have formed primarily asa result ofweathering during the time represented by the Cretaceous-Tertiary unconformity.

Colorado↗
USGS2014

Geology and total petroleum systems of the Paradox Basin, Utah, Colorado, New Mexico, and Arizona

The geological model for the development of the Total Petroleum Systems (TPSs) within the Paradox Basin formed the foundation of the recent U.S. Geological Survey assessment of undiscovered, technically recoverable resources in the basin. Five TPSs were defined, of which three have known production and two are hypothetical. These TPSs are based on geologic elements of the basin and the potential development of Precambrian, Devonian, Pennsylvanian, Permian-Mississippian, and Cretaceous source rock intervals. The most studied source intervals are the Pennsylvanian black shales that were deposited during relative high stands in an otherwise evaporitic basin. These black shales are the source for most of the discovered hydrocarbons in the Paradox Basin. A second oil type can be traced to either a Mississippian or Permian source rock to the west, and therefore requires long-distance migration to explain its presence in the basin. Upper Cretaceous continental to nearshore-marine sandstones are interbedded with coal beds that have recognized coalbed methane potential. Precambrian and Devonian TPSs are considered hypothetical, as both are known to have organic-rich intervals, but no discovered hydrocarbons have been definitively typed back to either of these units.

Arizona, Colorado, New Mexico, Utah↗
USGS2016

Stratigraphic architecture of a fluvial-lacustrine basin-fill succession at Desolation Canyon, Uinta Basin, Utah: Reference to Walthers’ Law and implications for the petroleum industry

A continuous window into the fluvial-lacustrine basin-fill succession of the Uinta Basin is exposed along a 48-mile (77-kilometer) transect up the modern Green River from Three Fords to Sand Wash in Desolation Canyon, Utah. In ascending order the stratigraphic units are: 1) Flagstaff Limestone, 2) lower Wasatch member of the Wasatch Formation, 3) middle Wasatch member of the Wasatch Formation, 4) upper Wasatch member of the Wasatch Formation, 5) Uteland Butte member of the lower Green River Formation, 6) lower Green River Formation, 7) Renegade Tongue of the lower Green River Formation, 8) middle Green River Formation, and 9) the Mahogany oil shale zone marking the boundary between the middle and upper Green River Formations. This article uses regional field mapping, geologic maps, photographs, and descriptions of the stratigraphic unit including: 1) bounding surfaces, 2) key upward stratigraphic characteristics within the unit, and 3) longitudinal changes along the river transect. This information is used to create a north-south cross section through the basin-fill succession and a detailed geologic map of Desolation Canyon. The cross section documents stratigraphic relationships previously unreported and contrasts with earlier interpretations in two ways: 1) abrupt upward shifts in the stratigraphy documented herein, contrast with the gradual interfingering relationships proposed by Ryder et al., (1976) and Fouch et al., (1994) , 2) we document fluvial deposits of the lower and middle Wasatch to be distinct and more widespread than previously recognized. In addition, we document that the Uteland Butte member of the lower Green River Formation was deposited in a lacustrine environment in Desolation Canyon. Two large-scale (member-scale) upward patterns are noted: Waltherian, and non-Waltherian. The upward successions in Waltherian progressions record progradation or retrogradation of a linked fluvial-lacustrine system across the area; whereas the upward successions in non-Waltherian progressions record large-scale changes in the depositional system that are not related to progradation or retrogradation of the ancient lacustrine shoreline. Four Waltherian progressions are noted: 1) the Flagstaff Limestone to lower Wasatch Formation member records the upward transition from lacustrine to fluvial—or shallowing-upward succession; 2) the upper Wasatch to Uteland Butte records the upward transition from fluvial to lacustrine—or a deepening upward succession; 3) the Uteland Butte to Renegade Tongue records the upward transition from lacustrine to fluvial—a shallowing-upward succession; and 4) the Renegade Tongue to Mahogany oil shale interval records the upward transition from fluvial to lacustrine—a deepening upward succession. The two non-Waltherian progressions in the study area are: 1) the lower to middle Wasatch, which records the abrupt shift from low to high net-sand content fluvial system, and 2) the middle to upper Wasatch, which records the abrupt shift from high to intermediate net-sand content fluvial system.

Utah↗
USGS2016

Field guide to Laramide basin evolution and drilling activity in North Park and Middle Park, Colorado

Overview of the geologic history of the North Park–Middle Park area and its past and recent drilling activity. Field trip stops highlight basin formation and the consequences of geologic configuration on oil and gas plays and development. The starting point is the west flank of the Denver Basin to compare and contrast the latest Cretaceous through Eocene basin fill on both flanks of the Front Range, before exploring sediments of the same age in the North Park – Middle Park intermontane basin.

Colorado↗
USGS2017

Characterization and origin of brines from the Bakken-Three Forks petroleum system in the Williston Basin, USA

Brine (also referred to as ‘produced water’) samples were collected from 28 wells producing oil from the Late Devonian-Early Mississippian Bakken and Three Forks Formations in the Williston Basin of eastern Montana and western North Dakota. The samples were analyzed for major ions, trace metals, stable isotopes, and strontium isotopes. The brines in these formations are highly saline with total dissolved solids averaging 308 g/L, almost ten times the salinity of modern seawater. Relative to modern seawater, the brines are enriched approximately 10 to 20 times in [Na], [K], [Cl], and [Br]. Greater enrichments of 100 to 400 times in [Li], [B], [Sr] and [Rb], and 2,000 to 10,000 times in [Cs] and [Ba] are probably due to water-rock interaction (WRI). WRI is further indicated by 87Sr/86Sr values typically between 0.710 and 0.711—considerably larger than marine values of 0.7081 to 0.7083 during this depositional interval. Bakken Formation sediments were deposited in a stratified water column with salinity increasing with depth. The deeper water may have been saturated in calcium carbonate and possibly gypsum, but there is no evidence that halite saturation had been attained. Therefore, brines may have been introduced into the Bakken Formation from the underlying Devonian Prairie Formation or from the overlying Charles Formation before these brines were diluted or replaced by meteoric water. Alternatively, salinity of the native pore water was increased by membrane filtration driven by overpressuring within the Bakken Formation.

Mountain Geologist↗
USGS2013

4D petroleum system model of the Mississippian System in the Anadarko Basin Province, Oklahoma, Kansas, Texas, and Colorado, U.S.A.

The Upper Devonian and Lower Mississippian Woodford Shale is an important petroleum source rock for Mississippian reservoirs in the Anadarko Basin Province of Oklahoma, Kansas, Texas, and Colorado, based on results from a 4D petroleum system model of the basin. The Woodford Shale underlies Mississippian strata over most of the Anadarko Basin portions of Oklahoma and northeastern Texas. The Kansas and Colorado portions of the province are almost entirely thermally immature for oil generation from the Woodford Shale or potential Mississippian source rocks, based mainly on measured vitrinite reflectance and modeled thermal maturation. Thermal maturities of the Woodford Shale range from mature for oil to overmature for gas generation at present-day depths of about 5,000 to 20,000 ft. Oil generation began at burial depths of about 6,000 to 6,500 ft. Modeled onset of Woodford Shale oil generation was about 330 million years ago (Ma); peak oil generation was from 300 to 220 Ma. Mississippian production, including horizontal wells of the informal Mississippi limestone, is concentrated within and north of the Sooner Trend area in the northeast Oklahoma portion of the basin. This large pod of oil and gas production is within the area modeled as thermally mature for oil generation from the Woodford Shale. The southern boundary of the trend approximates the 99% transformation ratio of the Woodford Shale, which marks the end of oil generation. Because most of the Sooner Trend area is thermally mature for oil generation from the Woodford Shale, the trend probably includes short- and longer-distance vertical and lateral migration. The Woodford Shale is absent in the Mocane-Laverne Field area of the eastern Oklahoma panhandle; because of this, associated oil migrated from the south into the field. If the Springer Formation or deeper Mississippian strata generated oil, then the southern field area is within the oil window for associated petroleum source rocks. Mississippian fields along the western boundary of the study area were supplied by oil that flowed northward from the Panhandle Field area and westward from the deep basin.

Colorado, Kansas, New Mexico, Oklahoma, Texas↗