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Centered on Fort Morgan, Colorado, this study is intended to build from previous work by adding a three-dimensional (3D) view of the subsurface to better understand the depositional history of Quaternary deposits. A 1:100,000 scale geologic map was made by combining previous geologic maps, regional soil maps, and recent field investigations. In addition to the geologic mapping, drill hole lithologic data from water wells and oil and gas exploration were compiled and lithologic units simplified to best represent the stratigraphy of the Quaternary deposits. From these subsurface data, a 3D subsurface model was constructed, trimmed at the surface by a digital elevation model, and a bedrock surface foundation gridded from drill hole data was added. The surface of the 3D model was then compared visually to the surficial geologic map. Cross sections were constructed from the 3D model and compared to site-specific drilling that was done as part of this project. Finally, the model was examined in detail to reconstruct the depositional history of the subsurface alluvial and eolian units. Alluvial and fluvial drainage basins exposed in the subsurface have a greater areal extent than the present-day narrow drainages. Older eolian sand in the subsurface tends to be interbedded with loess indicating coeval deposition. Holocene sand, both eroded from bedrock exposed at the surface north of the study area and reworked from the South Platte River, buries most of the interbedded older sand and loess.
This chapter is a re-release of U.S. Geological Survey Scientific Investigations Map 2916, of the same title, by Ryder (2006).
This chapter is a re-release of U.S. Geological Survey Scientific Investigations Map 2916, of the same title, by Ryder (2006).
This chapter is a re-release of U.S. Geological Survey Geologic Investigations Series Map I–2810, of the same title, by Ryder (2004).
This report gives the results of geologic investigations made in 1948 and 1949 in the eastern part of the Centralia-Chehalis coal district of southwest Washington. Detailed geologic mapping and stratigraphic studies were supplemented by core drilling. The core drilling tested the thickness and physical character of the individual coal beds and aided in determining the continuity of the beds. It is hoped that the information on coal resources thus obtained will provide basic data useful in the development and utilization of the coal, which furnished one of the natural bases for the potential industrial growth of this region. Exploratory drilling for oil and gas has been thus far unsuccessful and suggests that geological conditions in the area mapped are not favorable for the accumulation of petroleum; the geologic information obtained during this investigation may, however, be helpful in delimiting areas in other parts of western Washington that may be favorable for exploratory drilling.
The Wind River Basin in central Wyoming is one of many structural and sedimentary basins that formed in the Rocky Mountain foreland during the Laramide orogeny. The basin is bounded by the Washakie, Owl Creek, and southern Bighorn uplifts on the north, the Casper arch on the east, the Granite Mountains uplift on the south, and Wind River uplift on the west. The first commercial oil well in Wyoming was drilled at Dallas dome near an oil seep along the southwestern edge of the Wind River Basin in 1884. Since then, many important conventional oil and gas fields, that produce from reservoirs ranging in age from Mississippian through Tertiary, have been discovered in this basin. In addition, an extensive unconventional (continuous) overpressured basin-centered gas accumulation has been identified in Cretaceous and Tertiary strata in the deeper parts of the basin. It has been suggested that various Upper Cretaceous marine shales, including the Cody Shale, are the principal hydrocarbon source rocks for many of these accumulations. With recent advances in horizontal drilling and multistage fracture stimulation, there has been an increase in exploration and completion of wells in equivalent marine shales in other Rocky Mountain Laramide basins that were traditionally thought of only as hydrocarbon source rocks. The maps presented in this report were constructed as part of a project carried out by the U.S. Geological Survey to characterize the geologic framework of potential undiscovered continuous (unconventional) oil and gas resources of the Niobrara interval of the Upper Cretaceous Cody Shale in the Wind River Basin in central Wyoming.
Simple, cost-effective techniques are needed for land managers to assess the environmental impacts of oil and gas production activities on public lands, so that sites may be prioritized for remediation or for further, more formal assessment. Field-portable instruments provide real-time data and allow the field investigator to extend an assessment beyond simply locating and mapping obvious disturbances. Field investigators can examine sites for the presence of hydrocarbons in the subsurface using a soil auger and a photoionization detector (PID). The PID measures volatile organic compounds (VOC) in soil gases. This allows detection of hydrocarbons in the shallow subsurface near areas of obvious oil-stained soils, oil in pits, or dead vegetation. Remnants of a condensate release occur in sandy soils at a production site on the Padre Island National Seashore in south Texas. Dead vegetation had been observed by National Park Service personnel in the release area several years prior to our visit. The site is located several miles south of the Malaquite Beach Campground. In early 2001, we sampled soil gases for VOCs in the area believed to have received the condensate. Our purpose in this investigation was: 1) to establish what sampling techniques might be effective in sandy soils with a shallow water and contrast them with techniques used in an earlier study; and 2) delineate the probable area of condensate release. Our field results show that sealing the auger hole with a clear, rigid plastic tube capped at the top end and sampling the soil gas through a small hole in the cap increases the soil VOC gas signature, compared to sampling soil gases in the bottom of an open hole. This sealed-tube sampling method increases the contrast between the VOC levels within a contaminated area and adjacent background areas. The tube allows the PID air pump to draw soil gas from the volume of soil surrounding the open hole below the tube in a zone less influenced by atmospheric air. In an open hole, the VOC readings seem to be strongly dependent on the degree of diffusion and advection of soil gas VOCs into the open hole from the surrounding soil, a process that may vary with soil and wind conditions. Making measurements with the sealed hole does take some additional time (4-7 minutes after the hole is augered) compared to the open-hole technique (1-2 minutes). We used the rigid-plastic tube technique to survey for soil gas VOCs across the entire site, less than ? acre. Condensate has impacted at least 0.28 acres. The impacted area may extend northwest of the surveyed area.
The Maverick Basin of south Texas is currently undergoing active exploration and production of gas and oil from tight sandstone reservoirs. The most productive tight sandstones in the basin are in the Upper Cretaceous San Miguel, Olmos, and Escondido Formations. These units are second only to the Eagle Ford Shale in terms of cumulative production volumes. The structural history of the Maverick Basin, from rifting to subsidence to exhumation, has had a profound effect on the characteristics of these reservoirs and the petroleum resources contained therein. This U.S. Geological Survey review of the production history of these strata reflects a recent shift from conventional production to horizontal drilling (unconventional) that exploits low permeability reservoirs in previously overlooked areas of existing oil and gas fields in southern Texas, typically outside of established field boundaries. To investigate the physical properties of the Maverick Basin hydrocarbon accumulations, this case study compiled American Petroleum Institute (API) gravity measurements and calculated cumulative gas/oil ratios (GOR) for thousands of producing wells from the San Miguel, Olmos, and Escondido Formations. Maps were generated from the compiled well production data to show the spatial heterogeneity of API gravity and GOR values for the three formations within the Maverick Basin and immediately outside the basin to the northeast. Within the Maverick Basin, the spatial patterns of API gravity values indicate lighter oils downdip towards the southern basin edge. GOR values indicative of wet and dry gases within the basin are seen interspersed, with values that correspond to black and heavy oils. Differences in the spatial patterns of the petroleum properties within the Maverick Basin are interpreted as effects of Eocene basin inversion caused by Laramide orogenic deformation, and the resulting reservoir exhumation of basin strata. East of the Maverick Basin, spatial distributions of API gravity and GOR values show progressively heavier oils updip to the northwest, grading to dry gases downdip to the southeast, which correlates to the oil and gas windows of the underlying Eagle Ford Shale. Correlation of API gravity and GOR values from the San Miguel, Olmos, and Escondido Formations with thermal maturity data from the Eagle Ford Shale suggests that the Eagle Ford Shale is the petroleum source, and that petroleum migration was approximately vertical for areas to the east of the Maverick Basin. The discontinuity of API gravity and GOR properties within the Maverick Basin implies a complex petroleum charge history, possibly involving the remigration of petroleum and the addition of petroleum from other source intervals in Mexico, to the southwest. Depressurization of exhumed, overpressured reservoirs of the San Miguel, Olmos, and Escondido Formations can explain the intermittent occurrence of gas production throughout the southern Maverick Basin by exsolution of gas from formation brines and the resulting dry gas flushing of hydrocarbon-charged reservoirs. The introduction of dry gas through flushing can, in turn, explain why the patterns of API gravity and GOR values are so dissimilar in the Maverick Basin. This process has implications for possible future production of unconventional resources from undiscovered tight-gas reservoirs in strata of the San Miguel, Olmos, and Escondido Formations, and a different approach to petroleum exploration may be needed in the Maverick Basin relative to exploration techniques applied in other basins within the northern Gulf of Mexico.
The Bighorn Basin is a large intermontane sedimentary and structural basin that formed during the Laramide orogeny. The first commercial hydrocarbon production in the Bighorn Basin was established in 1906 from Cretaceous reservoirs at Garland field followed by the discovery of Greybull field in 1907. Since then, many important conventional oil and gas resources have been discovered from reservoirs ranging in age from Cambrian to Tertiary. In addition, a potential continuous (unconventional) basin-centered gas accumulation may be present in Cretaceous reservoirs in the deeper parts of the basin. The maps presented in this report were constructed as part of a project carried out by the U.S. Geological Survey to better characterize the geologic framework of potential undiscovered continuous (unconventional) oil and gas resources of the Niobrara interval of the Upper Cretaceous Cody Shale in the Bighorn Basin in north-central Wyoming and south-central Montana.
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Simple, cost-effective techniques are needed for land managers to assess the environmental impacts of oil and gas production activities on public lands so that sites may be prioritized for further, more formal assessment or remediation. These techniques should allow the field investigator to extend the assessment beyond the surface disturbances documented by simple observation and mapping using field-portable instruments and expendable materials that provide real-time data. The principal contaminants of current concern are hydrocarbons, produced water, and naturally occurring radioactive materials (NORM). Field investigators can examine sites for the impacts of hydrocarbon releases using a photoionization detector (PID) and a soil auger. Volatile organic carbon (VOC) in soil gases in an open auger hole or in the head space of a bagged and gently warmed auger soil sample can be measured by the PID. This allows detection of hydrocarbon movement in the shallow subsurface away from areas of obvious oil-stained soils or oil in pits at a production site. Similarly, a field conductivity meter and chloride titration strips can be used to measure salts in water and soil samples at distances well beyond areas of surface salt scarring. Use of a soil auger allows detection of saline subsoils in areas where salts may be flushed from the surface soil layers. Finally, a microRmeter detects the presence of naturally occurring radioactive materials (NORM) in equipment and soils. NORM often goes undetected at many sites although regulations limiting NORM in equipment and soils are being promulgated in several States and are being considered by the USEPA. With each technique, background sampling should be done for comparison with impacted areas. The authors examined sites in the Big South Fork National River and Recreation Area in November of 1999. A pit at one site at the edge of the flood plain of a small stream had received crude oil releases from a nearby tank. Auger holes down gradient from the pit showed the presence of anomalous concentrations of VOCs at depths of 3 feet for a distance of about 50 feet. PID readings at other sites showed 1) one reclaimed site where hydrocarbon biodegradation was incomplete; 2) one reclaimed site where biodegradation had left no traces of VOCS; and 3) two sites where traces of substantial offsite migration of hydrocarbons occurred. Produced water salts at one site have migrated many 100s of feet downvalley from the area of salt scarring and tree death adjacent to the pits. Naturally occurring radioactivity (NORM) at most sites was at background. One site showed anomalous radioactivity related to NORM in a small brine pit. Some of this NORM has moved downslope from the outlet pipe to the pit.
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The history of petroleum exploration in Alaska and the geology of possible petroleum provinces in Alaska are reviewed. Maps showing Alaska's major Mesozoic and Tertiary tectonic elements, possible petroleum provinces, and indications of petrol, are included in this report. Annotated references in Geological Survey publications relating to petroleum and oil shale in Alaska are given at the end of the report. For the purpose of appraising its petroleum possibilities, Alaska is divided into the southern, central, and northern major geologic-physiographic regions. Southern Alaska includes the arcuate mountain chain formed by the Alaska and Aleutian Ranges and the Mentasta- Nutzotin Mountains, the coastal range and valley area to the south, and the southeastern Alaska "panhandle" -- an area of 185,000 square miles. Oil seeps on the west shore of Cook Inlet in southern Alaska were known as early as 1853, and claims were staked in this region in 1882. Drilling began near the oil seeps in the Katalla district about 1901, and this started Alaska's first period of oil activity. From 1902 to 1933 the Katalla field produced 154,000 barrels of oil from fractured shale and sandstone of Tertiary age the- first and only commercial production in Alaska. On the basis of geology, surficial indications of petroleum, and test wells drilled, six possible petroleum provinces are indicated in southern Alaska. They are Heceta Island area, Keku Islands area, Cook Inlet Mesozoic province, Gulf of Alaska Tertiary province, Cook Inlet Tertiary province, and Copper River basin. The exposed rocks in the Heceta Island area include lower Paleozoic graywacke-type sandstone, sandstone, conglomerate, and massive limestones with reeflike structures; igneous rocks are rare or lacking in much of the area. The Kosciusko-Tuxekan-Heceta synclinorium, the main structural feature, is modified by minor folds and faults. Some of the minor folds are reported to be broad and open, with flanks dipping 20°-145°. As far as known, the Heceta Island area has not heretofore been seriously considered as a possible petroleum province. Rocks of Silurian to Cretaceous age are exposed in the Keku Island area and include moderately folded and relatively unaltered limestone and other marine sedimentary rocks. The Cook Inlet Mesozoic province, a land area of approximately 18,500 square miles, includes a great thickness of unmetamorphosed marine sedimentary rocks of Jurassic and Cretaceous age. At least 23 test wells were drilled or started in this province by the end of 1955. Shows of oil and gas were encountered in many of these wells. During 1955 at least ten oil companies were active in this area and by the end of 1955 about 1 1/2 million acres were included in oil and gas leases applied for or granted. The Gulf of Alaska Tertiary province includes about 5,200 square miles in which rocks of Tertiary age are exposed or are believed to underlie Quaternary deposits. Between 1901 and the end of 1955 about 47 wells were drilled or started in this province. The Cook Inlet Tertiary province embraces an area of about 9,500 square miles, of which about 4,100 is covered by the shallow waters of Cook Inlet. Petroleum exploration has been in that part of the area which overlaps the Cook Inlet Mesozoic province. Eocene or younger Tertiary nonmarine sedimentary rocks are believed to underlie much of the province, and marine rocks of Tertiary age may also be present. The Copper River basin is a topographic basin underlain by unconsolidated deposits of Quaternary age. Tertiary rocks favorable for the accumulation of petroleum may underlie part of the basin but this is not believed likely. Except for some leasing activity no petroleum exploration has been recorded in the Copper River Basin to the end of 1955. Central Alaska is a region of about 275,000 square miles and consists of an irregular assemblage of intricately dissected uplands and alluvium-floored lowland basins. Scattered peaks of resistant intrusive igneous rocks surmount most of the upland areas. In the vast region of central Alaska only six test wells are known to have been drilled for the purpose of finding oil and gas. The maximum depth reached was 350 feet and the holes were mostly or entirely in Quaternary deposits. In recent years several oil companies have investigated some parts of the region and large areas in the Yukon-Koyukuk province are now under lease. Oil seeps, gas seeps, and other indications of petroleum have been reported from many localities; samples from two localities have been analyzed and reported to be petroleum. The geology of central Alaska is similar in a general way to that of the area between the Rocky Mountains and Sierra-Cascade belts of the United States. Sedimentary rocks, probably equivalent to the Precambrian Belt series, and rocks of the Cambrian and all younger geologic systems have been recognized in central Alaska. The structure of the region is known to be complex, but except in local mineral districts, it has not been mapped in detail. Based on the limited amount of available information, the region cannot be regarded as distinctly favorable for significant accumulations of petroleum. However, three pre-Cenozoic provinces, the Yukon-Koyukuk, the Kobuk, and the Kandik, and several large Cenozoic basin provinces may be worthy of further investigation. Northern Alaska includes the Brooks Range and all the treeless tundra north to the Arctic Coast, an area of about 125,000 square miles. The presence of oil seeps along the Arctic Coast has been known at least since 1900 and a description of the Cape Simpson oil seeps vas published in 1909. Since then oil and gas seeps have been described from nine localities, and oil shales and oil-bearing sandstones are known from many localities in the Arctic Foothills province. Oil and gas deposits have been discovered and geologic conditions are favorable for oil and gas accumulations in approximately half of the region. In 1923 approximately 37,000 square miles in northern Alaska was reserved by Executive order as Naval Petroleum Reserve No. 4. In 1944 the U. S. Navy began a vast petroleum exploration program which was suspended in 1953. In the years 1945 through 1955, 37 test wells and 45 core tests were drilled on 18 structures. Three oil fields, Umiat, Simpson, and Fish Creek, and two gas fields, South Barrow and Gubik, were discovered. Total reserve estimates for all discoveries of oil to 1955 range from 30 to 100 million barrels, and for gas, from 370 billion to 900 billion cubic feet. All northern Alaska, with the exception of the Brooks Range, can be considered a possible petroleum province, but the region can be subdivided into provinces of somewhat different potentialities. These subdivisions roughly correspond with the geomorphic provinces and sections, which in turn reflect differences in geology. The known oil-bearing beds are of Mesozoic age, primarily Cretaceous, and thus the possible petroleum provinces could be designated as Mesozoic. However, Paleozoic and Cenozoic rocks with favorable reservoir characteristics are exposed in the region and possibly underlie, in favorable structural situations, some of the areas as yet not tested. The Arctic Coastal Plain province includes gently folded and flat-lying Mesozoic beds that overlie a basement complex of Paleozoic and early Mesozoic age. Near the southern edge of this province the basement rocks are at depths of at least 20,000 feet, and to the north these rocks rise to within 2,500 feet of the surface. The Teshukpuk Lake section of the Arctic Coastal plain includes many of the known oil seeps; it is the most accessible to sea transportation, and lies almost completely within NPR 4. Thirteen test wells and 35 core tests have been drilled here; one gas field and two (at present, noncommercial) oil fields have been discovered. The possibility of further discoveries may depend largely on locating porous sandstones in stratigraphic rather than anticlinal traps. The White Hills section is distinguished topographically from the Teshukpruk section by its white-gravel-covered hills and fever lakes, and geologically by the presence of Tertiary rocks, including 2,000 feet of nonmarine beds in the west and at least 7,000 feet of marine beds to the east, in the vicinity of Carter Creek. This section appears to be more complex structurally. No test wells have been drilled in the White Hills section. The Northern Foothills section includes many closed anticlines. Twenty-four test wells and ten core tests have been drilled on 11 structures and two discoveries have been made -the Umiat oil field and the Gubik gas field. All these tests have been drilled in Cretaceous rocks. The Southern Foothills section is structurally similar to the Alberta Foothills and to the northern part of the Brooks Range. Great thicknesses of marine shale of Lover Cretaceous, Jurassic, and Triassic age are exposed. The outcropping Mesozoic sandstones are generally poorly sorted, nonporous, and impermeable. To the south the section is bordered by mountainous exposures of Mississippian limestone, which probably underlie at least part of this section. The rocks that underlie the deeply eroded complex structures of the Brooks Range include schist, slate, argillite, and limestone. Some exposed limestones have a strong petroleum-like odor and contain traces of petroleum residues.
The Virgin Mountains Instant Study Area contains about 30,000 acres (12,000 ha) in southeastern Nevada. In accordance with the Federal Land Policy and Management Act (P.L. 94-579), the U.S. Bureau of Mines examined mines, prospects, and mineralized zones, and the U.S. Geological Survey made regional geologic, geophysical, and geochemical investigations. Tungsten and sheet mica have been produced from the study area, and oil and gas lease applications have been filed on 20,300 acres (8,200 ha). Sixteen mining claims are presently held.
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The potential for economic development of energy-related or metallic mineral resources in the King Range and Chemise Mountain Instant Study Areas is low to moderate as indicated by geologic, geophysical, and geochemical investigations. No oil or gas seeps or coal seams were detected within the King Range or Chemise Mountain Study Area. The low porosity and permeability of the Franciscan sandstones that underlie these areas indicate a very low potential for oil or gas. The geothermal resource potential of these areas also is low. Minor manganese resources occur adjacent to the southeast corner of the King Range Instant Study Area near Queen Peak. The manganese forms small stratabound deposits associated with radiolarian chert and pillow basalt. The known deposits are too small and the manganese too low in concentration for further economic exploitation. Similar manganese mineralization may be within the belt of melange in the southeast corner of the King Range area and within the Chemise Mountain Instant Study Area, but economic deposits are unlikely. Although there has been historical base- and precious-metal exploration activity north of the King Range in the Mattole River drainage, our geologic and geochemical field data indicate almost no gold potential and low potentials for lead, zinc, copper, and silver. During this investigation, one high-grade vein and several minor veins containing lead, zinc, copper, and silver were discovered at Point Delgada immediately south of the King Range Instant Study Area. The vein mineralization is Miocene and cuts Cretaceous basalt flows, dikes, flow breccia, and younger overlying sedimentary rocks of the King Range. The vein mineralization at Point Delgada could be remobilized from more extensive unexposed stratabound base-metal mineralization at depth. Traces of lead and zinc detected within the King Range Instant Study Area may have similar stratabound or vein origins, but no resource potential is indicated. Minor copper mineralization with associated lead, zinc, and manganese anomalies within the Chemise Mountain Instant Study Area is of low economic potential because of the shearing, isolation, and lenticularity of the basaltic and cherty rocks within the melange mineralization.