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Philip H. Nelson

Publications and source records attributed to Philip H. Nelson.

At least 37 records · Page 2Linked to original sources
USGS2009

Development of a probabilistic assessment methodology for evaluation of carbon dioxide storage

This report describes a probabilistic assessment methodology developed by the U.S. Geological Survey (USGS) for evaluation of the resource potential for storage of carbon dioxide (CO 2 ) in the subsurface of the United States as authorized by the Energy Independence and Security Act (Public Law 110-140, 2007). The methodology is based on USGS assessment methodologies for oil and gas resources created and refined over the last 30 years. The resource that is evaluated is the volume of pore space in the subsurface in the depth range of 3,000 to 13,000 feet that can be described within a geologically defined storage assessment unit consisting of a storage formation and an enclosing seal formation. Storage assessment units are divided into physical traps (PTs), which in most cases are oil and gas reservoirs, and the surrounding saline formation (SF), which encompasses the remainder of the storage formation. The storage resource is determined separately for these two types of storage. Monte Carlo simulation methods are used to calculate a distribution of the potential storage size for individual PTs and the SF. To estimate the aggregate storage resource of all PTs, a second Monte Carlo simulation step is used to sample the size and number of PTs. The probability of successful storage for individual PTs or the entire SF, defined in this methodology by the likelihood that the amount of CO 2 stored will be greater than a prescribed minimum, is based on an estimate of the probability of containment using present-day geologic knowledge. The report concludes with a brief discussion of needed research data that could be used to refine assessment methodologies for CO 2 sequestration.

Open-File Report↗
USGS2009

Gas, water, and oil production from the Wasatch Formation, Greater Natural Buttes Field, Uinta Basin, Utah

Gas, oil, and water production data were compiled from 38 wells with production commencing during the 1980s from the Wasatch Formation in the Greater Natural Buttes field, Uinta Basin, Utah. This study is one of a series of reports examining fluid production from tight gas reservoirs, which are characterized by low permeability, low porosity, and the presence of clay minerals in pore space. The general ranges of production rates after 2 years are 100-1,000 mscf/day for gas, 0.35-3.4 barrel per day for oil, and less than 1 barrel per day for water. The water:gas ratio ranges from 0.1 to10 barrel per million standard cubic feet, indicating that free water is produced along with water dissolved in gas in the reservoir. The oil:gas ratios are typical of a wet gas system. Neither gas nor water rates show dependence upon the number of perforations, although for low gas-flow rates there is some dependence upon the number of sandstone intervals that were perforated. Over a 5-year time span, gas and water may either increase or decrease in a given well, but the changes in production rate do not exhibit any dependence upon well proximity or well location.

Open-File Report↗
USGS2009

Gas, Oil, and Water Production in the Wind River Basin, Wyoming

Gas, oil, and water production data were collected from the Fuller Reservoir, Cooper Reservoir, Frenchie Draw, Cave Gulch, and Madden fields in the Wind River Basin, Wyoming. These fields produce from the Mississippian Madison Limestone, the Upper Cretaceous Cody Shale and Mesaverde Formation, and the Paleocene lower unnamed member and Shotgun Member of the Fort Union Formation. Diagrams of water and gas production from tight gas accumulations in three formations in the Madden field show that (1) water production either increased or decreased with time in all three formations, (2) increases and decreases in water production were greater in the Cody Shale than in either the Mesaverde Formation or the lower unnamed member of the Fort Union Formation, (3) the gas production rate declined more slowly in the lower part of the Fort Union Formation than in the Cody Shale or the Mesaverde Formation, (4) changes in gas and water production were not related to their initial production rates, and (5) there appears to be no relation between well location and the magnitudes or trends of gas and water production. To explain the apparent independence of gas and water production in the Cody Shale and Mesaverde Formation, a two-step scenario is proposed: gas was generated and emplaced under the compressive stress regime resulting from Laramide tectonism; then, fractures formed during a subsequent period of stress relaxation and extension. Gas is produced from the pore and fracture system near the wellbore, whereas water is produced from a larger scale system of extension fractures. The distribution of gas and water in the lower Fort Union resulted from a similar scenario, but continued generation of gas during post-Laramide extension may have allowed its more widespread distribution.

Scientific Investigations Report↗
USGS2007

Distribution of fluids and pressures in the Wind River Basin, Wyoming: Chapter 7 in Petroleum systems and geologic assessment of oil and gas resources in the Wind River Basin Province, Wyoming

To examine the state of hydrocarbons and water in the Wind River Basin of Wyoming, the following data types are compiled and presented at the basin scale: fluid type, pressure, and temperature from drillstem tests; watersalinity and cumulative hydrocarbon production from oil and gas wells; vitrinite reflectance data; and sonic well logs. The spatial distribution of produced fluids shows the nearly ubiquitous presence of mobile water, even in highly productive gas-charged formations. Sonic logs record a basin wide velocity decrease in the Lower Cretaceous Thermopolis Shale through the Upper Cretaceous Cody Shale that is attributed to a combination of paleo-overpressuring and present-day overpressuring. Pressure-elevation plots and mud weights reveal the presence of two large pressure compartments in the Madden area, one above the Waltman Shale Member of the Paleocene Fort Union Formation and the other below it. Temperature data reveal hot and cold spots around structures in the marginal parts of the basin where the Waltman Shale Member of the Fort Union Formation is absent. The highest temperature gradients are in the upper pressure compartment in the Madden area. Vitrinite reflectance data record little change with increasing depth throughout much of the geologic section in shallow parts of the basin and a steady increase of log (R o ) with depth in the deep parts of the basin. The varied distribution of fluids, pressure, and temperature reflect the complex history of subsidence, thrusting, hydrocarbon generation, water migration, and uplift in and marginal to this large, asymmetric intermontane basin.

Wyoming↗
USGS2007

Evaluation of Potash Grade with Gamma-ray Logs

Potassium is an emitter of gamma-ray radiation, consequently deposits of potash can be detected and evaluated using gamma-ray logs. A method originally designed to evaluate uranium deposits in boreholes can also be applied to potash deposits. The method equates the depth-integral of a gamma-ray log to the grade-thickness product of a potash-bearing bed or series of beds. The average grade of a bed is then determined by dividing by the overall bed thickness, which can also be obtained from the gamma-ray log. The method was tested using gamma-ray logs and potash assays from boreholes near Carlsbad, New Mexico.

Open-File Report↗
USGS2006

Potential tight gas resources in a frontier province - Jurassic through Tertiary strata beneath the Brooks Range foothills, Arctic Alaska

Beneath the foothills of the Brooks Range, rocks of the Lower Cretaceous-Tertiary Brookian and Jurassic-Lower Cretaceous Beaufortian megasequences have been deeply buried and exhumed, and now exhibit characteristics of 'tight gas sandstones'. The data recovered from drilling, well tests, and cores exhibit the potential for substantial gas reserves over a large area. These data include recovery of gas from drillstem tests, indications of overpressure from well tests and mud weights, low porosity and permeability in sandstones, and vitrinite reflectance values ranging from 1.0 to 2.0 percent throughout substantial depth intervals.

Open-File Report↗
USGS2003

A catalog of porosity and permeability from core plugs in siliciclastic rocks

Porosity and permeability measurements on cored samples from siliciclastic formations are presented for 70 data sets, taken from published data and descriptions. Data sets generally represent specific formations, usually from a limited number of wells. Each data set is represented by a written summary, a plot of permeability versus porosity, and a digital file of the data. The summaries include a publication reference, the geologic age of the formation, location, well names, depth range, various geologic descriptions, and core measurement conditions. Attributes such as grain size or depositional environment are identified by symbols on the plots. An index lists the authors and date, geologic age, formation name, sandstone classification, location, basin or structural province, and field name.

Open-File Report↗
USGS2003

Sandstone and shale compaction curves derived from sonic and gamma ray logs in offshore wells, North Slope, Alaska– Parameters for basin modeling

Representative compaction curves for the principle lithologies are essential input for reliable models of basin history. Compaction curves influence estimates of maximum burial and erosion. Different compaction curves may produce significantly different thermal histories. Default compaction curves provided by basin modeling packages may or may not be a good proxy for the compaction properties in a given area. Compaction curves in the published literature span a wide range, even within one lithology, e.g., sandstone (see Panel 3). An abundance of geophysical well data for the North Slope, from both government and private sources, provides us with an unusually good opportunity to develop compaction curves for the Cretaceous-Tertiary Brookian sandstones, siltstones, and shales. We examined the sonic and gamma ray logs from 19 offshore wells (see map), where significant erosion is least likely to have occurred. Our data are primarily from the Cretaceous-Tertiary Brookian sequence and are less complete for older sequences. For each well, the fraction of shale (Vsh) at a given depth was estimated from the gamma ray log, and porosity was computed from sonic travel time. By compositing porosities for the near-pure sand (Vsh<1%) and shale (Vsh>99%)from many individual wells we obtained data over sufficient depth intervals to define sandstone and shale 'master' compaction curves. A siltstone curve was defined using the sonic-derived porosities for Vsh values of 50%. These compaction curves generally match most of the sonic porosities with an error of 5% or less. Onshore, the curves are used to estimate the depth of maximum burial at the end of Brookian sedimentation. The depth of sonic-derived porosity profiles is adjusted to give the best match with the 'master' compaction curves. The amount of the depth adjustment is the erosion estimate. Using our compaction curves, erosion estimates on the North Slope range from zero in much of the offshore, to as much as 1500 ft along the coast, and to more than 10,000 ft in the foothills (Panel 3). Compaction curves provide an alternative to vitrinite reflectance for estimating erosion. Vitrinite reflectance data are often very sparse in contrast to well log data and are subject to inconsistencies when measurements are made by different labs. The phenomenon of 'recycling' can also make the reflectance values of dispersed vitrinite problematic for quantifying erosion. Recycling is suspected in dispersed vitrinite in North Slope rocks, particularly in the younger, Cretaceous-Tertiary section. The compaction curves defined here are being integrated into our burial history and thermal models to determine the timing of source rock maturation. An example on Panel 3 shows the results of calculating the maturity of the Shublik Fm. at the Tulaga well using two different sets of shale and siltstone compaction curves. Finally, accurate compaction curves improve a model's ability to realistically simulate the pressure regime during burial, including overpressures.

Alaska↗
USGS2002

A digital atlas of hydrocarbon accumulations within and adjacent to the National Petroleum Reserve-Alaska (NPRA)

The United States Geological Survey (USGS) has initiated a project to reassess the hydrocarbon potential of the NPRA. Although exploration for hydrocarbons in the NPRA was initiated in 1944, it has taken fifty years for the first commercial discovery to be made. That discovery, the Alpine field (projected recoverable reserves of 430 million barrels), was made in 1994 along the eastern boundary of the NPRA. This field produces from a formation heretofore considered to be mostly a source rock. The Alpine discovery made such a reassessment necessary. As part of this assessment, we have compiled stratigraphic, structural, petrophysical, and seismic data related to nineteen accumulations within and nearby the NPRA. The goal is to provide basic documentation and a set of analog accumulations for the new assessment. The first two displays of this atlas consist of a location map and a stratigraphic column showing the stratigraphic settings for the primary reservoir and source rocks for these accumulations. The third display is a table listing each accumulation and providing the hydrocarbon fluid type, reservoir, operator, status, and discovery well and date for each. Compilation of basic information for each individual accumulation follows these displays. A typical compilation includes a structurecontour map on or near the reservoir horizon, a log display of the discovery well with reservoir characteristics along with figures for recoverable volumes, and one or two seismic lines across or near the accumulation.

Alaska↗
USGS2000

Stratigraphy, correlation, depositional setting, and geophysical characteristics of the Oligocene Snowshoe Mountain Tuff and Creede Formation in two cored boreholes

Core descriptions and geophysical logs from two boreholes (CCM-1 and CCM-2) in the Oligocene Snowshoe Mountain Tuff and Creede Formation, south-central Colorado, are used to interpret sedimentary and volcanic facies associations and their physical properties. The seven facies association include a mixed sequence of intracaldera ash-flow tuffs and breccias, alluvial and lake margin deposits, and tuffaceous lake beds. These deposits represent volcanic units related to caldera collapse and emplacement of the Snowshoe Mountain Tuff, and sediments and pyroclastic material deposited in the newly formed caldera basin, Early sedimentation is interpreted to have been rapid, and to have occurred in volcaniclastic fan environments at CCM-1 and in a variery of volcaniclastic fan, braided stream shallow lacustrine, and mudflat environments at CCM-2. After an initial period of lake-level rise, suspension settling, turbidite, and debris-flow sedimentation occurred in lacustrine slope and basin environments below wave base. Carbonate sedimentation was initially sporadic, but more continuous in the latter part of the recorded lake history (after the H fallout tuff). Sublacustrine-fan deposition occurred at CCM-1 after a pronounced lake-level fall and subsequent rise that preceded the H tuff. Variations in density, neutron, gamma-ray, sonic, and electrical properties of deposits penetrated oin the two holes reflect variations in lithology, porosity, and alteration. Trends in the geophysical properties of the lacustrine strata are linked to downhole changes in authigenic mineralology and a decrease in porosity interpreted to have resulted primarily from diagenesis. Lithological and geophysical characteristics provide a basis for correlation of the cores; however, mineralogical methods of correlation are hampered by the degree of diagenesis and alteration.

Colorado↗
USGS1998

Application of well data in oil and gas assessment - Arctic National Wildlife Refuge

A current assessment of oil and gas resources in the Arctic National Wildlife Refuge 1002 area by the U.S. Geological Survey relies upon seismic data, geological mapping of exposures south and west of the assessment area and exploratory wells. Well data assembled for the 41 wells include: well logs, core descriptions and measurements, formation tops, biostratigraphic boundaries, drill-stem tests, casing points, fission-track age dates, vitrinite reflectance, and organic-carbon content. These data are used in the synthesis of all available data and presentation on a well-by-well basis, and extraction of volumetric parameters that are used to assess undiscovered accumulations.

Conference Paper↗