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At least 199 records · Page 11Linked to original sources
USGS1996

Progress report on daily flow-routing simulation for the Carson River, California and Nevada

A physically based flow-routing model using Hydrological Simulation Program-FORTRAN (HSPF) was constructed for modeling streamflow in the Carson River at daily time intervals as part of the Truckee-Carson Program of the U.S. Geological Survey (USGS). Daily streamflow data for water years 1978-92 for the mainstem river, tributaries, and irrigation ditches from the East Fork Carson River near Markleeville and West Fork Carson River at Woodfords down to the mainstem Carson River at Fort Churchill upstream from Lahontan Reservoir were obtained from several agencies and were compiled into a comprehensive data base. No previous physically based flow-routing model of the Carson River has incorporated multi-agency streamflow data into a single data base and simulated flow at a daily time interval. Where streamflow data were unavailable or incomplete, hydrologic techniques were used to estimate some flows. For modeling purposes, the Carson River was divided into six segments, which correspond to those used in the Alpine Decree that governs water rights along the river. Hydraulic characteristics were defined for 48 individual stream reaches based on cross-sectional survey data obtained from field surveys and previous studies. Simulation results from the model were compared with available observed and estimated streamflow data. Model testing demonstrated that hydraulic characteristics of the Carson River are adequately represented in the models for a range of flow regimes. Differences between simulated and observed streamflow result mostly from inadequate data characterizing inflow and outflow from the river. Because irrigation return flows are largely unknown, irrigation return flow percentages were used as a calibration parameter to minimize differences between observed and simulated streamflows. Observed and simulated streamflow were compared for daily periods for the full modeled length of the Carson River and for two major subreaches modeled with more detailed input data. Hydrographs and statistics presented in this report describe these differences. A sensitivity analysis of four estimated components of the hydrologic system evaluated which components were significant in the model. Estimated ungaged tributary streamflow is not a significant component of the model during low runoff, but is significant during high runoff. The sensitivity analysis indicates that changes in the estimated irrigation diversion and estimated return flow creates a noticeable change in the statistics. The modeling for this study is preliminary. Results of the model are constrained by current availability and accuracy of observed hydrologic data. Several inflows and outflows of the Carson River are not described by time-series data and therefore are not represented in the model.

Open-File Report↗
USGS1996

Possible continuous-type (unconventional) gas accumulation in the Lower Silurian "Clinton" sands, Medina Group and Tuscarora Sandstone in the Appalachian Basin; a progress report of the 1995 project activities

INTRODUCTION: In the U.S. Geological Survey's (USGS) 1995 National Assessment of United States oil and gas resources (Gautier and others, 1995), the Appalachian basin was estimated to have, at a mean value, about 61 trillion cubic feet (TCF) of recoverable gas in sandstone and shale reservoirs of Paleozoic age. Approximately one-half of this gas resource is estimated to reside in a regionally extensive, continuous-type gas accumulation whose reservoirs consist of low-permeability sandstone of the Lower Silurian 'Clinton' sands and Medina Group (Gautier and others, 1995; Ryder, 1995). Recognizing the importance of this large regional gas accumulation for future energy considerations, the USGS initiated in January 1995 a multi-year study to evaluate the nature, distribution, and origin of natural gas in the 'Clinton' sands, Medina Group sandstones, and equivalent Tuscarora Sandstone. The project is part of a larger natural gas project, Continuous Gas Accumulations in Sandstones and Carbonates, coordinated in FY1995 by Ben E. Law and Jennie L. Ridgley, USGS, Denver. Approximately 2.6 man years were devoted to the Clinton/Medina project in FY1995. A continuous-type gas accumulation, referred to in the project, is a new term introduced by Schmoker (1995a) to identify those natural gas accumulations whose reservoirs are charged throughout with gas over a large area and whose entrapment does not involve a downdip gas-water contact. Gas in these accumulations is located downdip of the water column and, thus, is the reverse of conventional-type hydrocarbon accumulations. Commonly used industry terms that are more or less synonymous with continuous-type gas accumulations include basin- centered gas accumulation (Rose and others, 1984; Law and Spencer, 1993), tight (low-permeability) gas reservoir (Spencer, 1989; Law and others, 1989; Perry, 1994), and deep basin gas (Masters, 1979, 1984). The realization that undiscovered gas in Lower Silurian sandstone reservoirs of the Appalachian basin probably occurs in a continuous accumulation rather than in conventionally trapped, discrete accumulations represents a significant departure from the 1989 National Assessment (Mast and others, 1989; deWitt, 1993). In 1989, a direct assessment (field-size distributions required for play analysis were unavailable) of the Lower Silurian sandstone play gave, at a mean value, about 1.7 TCF of gas. The 1995 estimate (~30 TCF of gas) is so much greater than the 1989 estimate (~1.7 TCF of gas) because of the interpreted continuous nature of the accumulation and the assessment methodology applied. The methodology for continuous hydrocarbon accumulations assumes that the reservoirs in the accumulation are gas-saturated and takes into account: 1) estimated ultimate recovery (EUR) per well probability distributions, 2) optimum area that a well can drain (spacing), 3) number of untested drill sites having the appropriate spacing area, 4) success ratio of previously drilled holes, and 5) risk (Schmoker, 1995b). Davis (1984), Zagorski (1988, 1991), and Law and Spencer (1993) were among the first petroleum geologists to suggest that gas in the 'Clinton' sands and Medina Group sandstones was trapped in a basin-centered/deep basin accumulation. They recognized many of the earmarks of a basin-centered/deep basin accumulation such as low-permeability reservoirs, abnormally low formation pressure, coalesced gas fields, gas shows or production in most holes drilled, low water yields, and a general lack of structural control on entrapment. Ryder (1995) adopted this interpretation by defining four continuous-type gas plays (6728-6731) in the 'Clinton' sands-Medina Group interval (fig.1). Play 6728 (Clinton/Medina sandstone gas high potential) covers a 17,000 sq mi region of western New York, northwestern Pennsylvania, eastern Ohio, and a small part of westernmost West Virginia that is very favorable for future gas resources (fig.1). Also, this play includes a l

Open-File Report↗
USGS1997

Progress report on sediment analyses at selected faunal monitoring sites in north-central and northeastern Florida Bay

Florida Bay is a shallow, subtropical lagoon at the southern tip of the Florida peninsula. The 2200 square kilometer, triangular-shaped area is the site of modern carbonate sediment formation and deposition. The intricate ecosystem of the bay has undergone significant changes as the result of natural influences and human intervention. The purpose of this study is to investigate carbonate sediment characteristics and distribution in conjunction with faunal and floral to determine the substrate preferences of associated fauna and flora. The modern data provide the proxy data for down-core analyses of sediments, fauna and flora in order to document ecosystem changes in the bay. Selected sediment samples collected during 1996 from 18 sites in the northeastern and central bay were analyzed for insoluble residues, organic content, total carbonate, and percent of silt and clay sized particles. Insoluble residues range from 0.8% of the sediment in a shell lag to 11.5% with an average of 5.1%. Organic content ranged from a minimum of 1.43% of the sediment to 18.05% with an average of 7.6%. The total carbonate content ranged from 72.56% to 97.81%, averaging 87.98%. The percent silt and clay sized particles ranged from 13.75% to 63.62% for the samples analyzed. The insoluble residue content shows a general trend of decreasing insoluble residues from the northeastern bay toward the southwest. Organic content is variable throughout the bay and does not show a regional trend. Several sites show a trend of higher organic content in the samples collected in February as compared to those collected in July. Lithologic examination indicated that, in addition to the carbonate mud (less than 63mm), sample components included whole and fragmented mollusks, foraminifers, bryozoans, ostracods, and organic matter. The insoluble residues consisted of quartz sand and silt, clays and siliceous fossils. A component of the insoluble residues may be dust derived from Africa and transported to southern Florida by the prevailing winds. This report is preliminary and has not been reviewed for conformity with U.S. Geological Survey editorial standards or with the North American Stratigraphic Code. Any use of trade, product, or firm names is for descriptive purposes only and does not imply endorsement by the U.S. Government.

Open-File Report↗