Geology Reports⌕ Search

Geology topics

Thaddeus S. Dyman

Publications and source records attributed to Thaddeus S. Dyman.

9 recordsLinked to original sources
USGS2008

Geologic controls on the growth of petroleum reserves

The geologic characteristics of selected siliciclastic (largely sandstone) and carbonate (limestone and dolomite) reservoirs in North America (largely the continental United States) were investigated to improve our understanding of the role of geology in the growth of petroleum reserves. Reservoirs studied were deposited in (1) eolian environments (Jurassic Norphlet Formation of the Gulf Coast and Pennsylvanian-Permian Minnelusa Formation of the Powder River Basin), (2) interconnected fluvial, deltaic, and shallow marine environments (Oligocene Frio Formation of the Gulf Coast and the Pennsylvanian Morrow Formation of the Anadarko and Denver Basins), (3) deeper marine environments (Mississippian Barnett Shale of the Fort Worth Basin and Devonian-Mississippian Bakken Formation of the Williston Basin), (4) marine carbonate environments (Ordovician Ellenburger Group of the Permian Basin and Jurassic Smackover Formation of the Gulf of Mexico Basin), (5) a submarine fan environment (Permian Spraberry Formation of the Midland Basin), and (6) a fluvial environment (Paleocene-Eocene Wasatch Formation of the Uinta-Piceance Basin). The connection between an oil reservoir's production history and geology was also evaluated by studying production histories of wells in disparate reservoir categories and wells in a single formation containing two reservoir categories. This effort was undertaken to determine, in general, if different reservoir production heterogeneities could be quantified on the basis of gross geologic differences. It appears that reserve growth in existing fields is most predictable for those in which reservoir heterogeneity is low and thus production differs little between wells, probably owing to relatively homogeneous fluid flow. In fields in which reservoirs are highly heterogeneous, prediction of future growth from infill drilling is notably more difficult. In any case, success at linking heterogeneity to reserve growth depends on factors in addition to geology, such as engineering and technological advances and political or cultural or economic influences.

Bulletin↗
USGS2003

Potential for deep basin-centered gas accumulation in Travis Peak (Hosston) Formation, Gulf Coast Basin, U.S.A.

The potential of Lower Cretaceous sandstones of the Travis Peak Formation in the northern Gulf Coast Basin to harbor a basin-centered gas accumulation was evaluated by examining (1) the depositional and diagenetic history and reservoir properties of Travis Peak sandstones, (2) the presence and quality of source rocks for generating gas, (3) the burial and thermal history of source rocks and time of gas generation and migration relative to tectonic development of Travis Peak traps, (4) gas and water recoveries from drill-stem and formation tests, (5) the distribution of abnormal pressures based on shut-in-pressure data, and (6) the presence or absence of gas-water contacts associated with gas accumulations in Travis Peak sandstones. The Travis Peak Formation (and correlative Hosston Formation) is a basinward-thickening wedge of terrigenous clastic sedimentary rocks that underlies the northern Gulf Coast Basin from eastern Texas across northern Louisiana to southern Mississippi. Clastic influx was focused in two main fluvial-deltaic depocenters—one located in northeastern Texas and the other in southeastern Mississippi and northeastern Louisiana. Across the main hydrocarbon-productive trend in eastern Texas and northern Louisiana, the Travis Peak Formation is about 2,000 ft thick. Most Travis Peak hydrocarbon production in eastern Texas comes from drilling depths between 6,000 and 10,000 ft. Significant decrease in porosity and permeability occurs through that depth interval. Above 8,000-ft drilling depth in eastern Texas, Travis Peak sandstone matrix permeabilities often are significantly higher than the 0.1-millidarcy (mD) cutoff that characterizes tight-gas reservoirs. Below 8,000 ft, matrix permeability of Travis Peak sandstones is low because of pervasive quartz cementation, but abundant natural fractures impart significant fracture permeability. Although pressure data within the middle and lower Travis Peak Formation are limited in eastern Texas, overpressured reservoirs caused by thermal generation of gas, typical of basin-centered gas accumulations, are not common in the Travis Peak Formation. Significant overpressure was found in only one Travis Peak sandstone reservoir in 1 of 24 oil and gas fields examined across eastern Texas and northern Louisiana. The presence of gas-water contacts is perhaps the most definitive criterion indicating that a gas accumulation is conventional rather than a “sweet spot” within a basin-centered gas accumulation. Hydrocarbon-water contacts within Travis Peak sandstone reservoirs were documented in 17 fields and probably occur in considerably more fields across the productive Travis Peak trend in eastern Texas and northern Louisiana. All known hydrocarbon-water contacts in Travis Peak reservoirs in eastern Texas, however, occur within sandstones in the upper 500 ft of the formation. Although no gas-water contacts have been reported within the lower three-fourths of the Travis Peak Formation in northeastern Texas, gas production from that interval is limited. The best available data suggest that most middle and lower Travis Peak sandstones are water bearing in northeastern Texas. Insufficient hydrocarbon charge relative to permeability of Travis Peak reservoirs might be responsible for lack of overpressure and basin-centered gas within the Travis Peak Formation. Shales interbedded with Travis Peak sandstones in eastern Texas are primarily oxidized flood-plain deposits with insufficient organic-carbon content to be significant sources of oil and gas. The most likely source rocks for hydrocarbons in Travis Peak reservoirs are two stratigraphically lower units, the Jurassic-age Bossier Shale of the Cotton Valley Group, and laminated, lime mudstones of the Jurassic Smackover Formation. Hydrocarbon charge, therefore, might be sufficient for development of conventional gas accumulations, but it is insufficient for development of basin-centered gas as a result of the absence of proximal source rocks and a lack of effective migration pathways from stratigraphically or geographically distant source rocks.

Louisiana, Mississippi, Texas↗
USGS2002

Is there a basin-centered gas accumulation in Cotton Valley group sandstones, Gulf Coast basin, U.S.A.?

The U.S. Geological Survey (USGS), in cooperation with the U.S. Department of Energy, is reevaluating the resource potential of selected domestic basin-centered gas accumulations. Basin-centered gas accumulations are characterized by presence of gas in extensive low-permeability (tight) reservoirs in which conventional seals and trapping mechanisms are absent, abnormally high or low reservoir pressures exist, and gas-water contacts are absent. In 1995, the USGS assessed one basin-centered gas play and two conventional plays within the trend of Jurassic and Cretaceous Cotton Valley Group fluvial-deltaic and barrier island/strand plain sandstones across the onshore northern Gulf of Mexico Basin. Detailed evaluation of geologic and production data provides new insights into these Cotton Valley plays. Two Cotton Valley sandstone trends are identified based on reservoir properties and gas-production characteristics. Transgressive blanket sandstones across northern Louisiana have relatively high porosity and permeability and do not require fracture stimulation to produce gas at commercial rates. South of this trend, and extending westward into eastern Texas, massive sandstones of the Cotton Valley trend exhibit low porosity and permeability and require fracture stimulation. The high permeability of Cotton Valley blanket sandstones is not conducive to the presence of basin-centered gas, but low permeability massive sandstones provide the type of reservoir in which basin-centered gas accumulations commonly occur. Data on source rocks, including burial and thermal history, are consistent with the interpretation of potential basin centered gas within Cotton Valley sandstones. However, pressure gradients throughout most of the blanket- and massive sandstone trends are normal or nearly normal, which is not characteristic of basin-centered gas accumulations. The presence of gas-water contacts in at least seven fields across the blanket-sandstone trend together with relatively high permeabilities and high gas-production rates without fracture stimulation indicate that fields in this trend are conventional. Within the tight massive-sandstone trend, permeability is sufficiently low that gas-water transition zones are vertically extensive and gas-water contacts either have not been encountered or are poorly defined. With increasing depth through these transition zones, gas saturation decreases and water saturation increases until eventually gas saturations become sufficiently low that, in terms of ultimate cumulative production, wells are noncommercial. Such progressive increase in water saturation with depth suggests that poorly defined gas-water contacts probably are present below the depth at which wells become noncommercial. The interpreted presence of gas-water contacts within the tight, Cotton Valley massive-sandstone trend suggests that gas accumulations in this trend, too, are conventional, and that a basin-centered gas accumulation does not exist within Cotton Valley sandstones in the northern Gulf Basin.

Louisiana, Texas↗
USGS2001

Changing perceptions of United States natural-gas resources as shown by successive U. S. Department of the Interior assessments

Trends in four successive estimates of United States technically recoverable natural gas resources are examined in this report. The effective dates of these assessments were January 1 of 1975, 1980, 1987, and 1994. The 1994 estimate of the U.S. total gas endowment increased significantly over the previous three estimates, indicating that the technically recoverable endowment of gas is not an absolute volume, but rather is a quantity that can increase through time in response to advances in technology and in geologic understanding. Much of this increase was in the category of reserve growth. Reserve growth refers to additions to the estimated ultimate recovery of fields that typically occur as discovered fields are developed and produced. The potential for U.S. reserve growth, rather than being rapidly used up, appears to be sustainable for many years by intensive engineering efforts coupled with improving technology. Potential additions to reserves in continuous (unconventional) accumulations also represent a type of reserve growth, and were estimated (for the first time) in the 1994 assessment at 358 trillion cubic feet of gas. This resource category provides a significant new contribution to the estimated U.S. total gas endowment.

Bulletin↗
USGS2001

Potential for deep basin-centered gas accumulation in Hanna Basin, Wyoming

The potential for a continuous-type basin-centered gas accumulation in the Hanna Basin in Carbon County, Wyoming, is evaluated using geologic and production data including mud-weight, hydrocarbon-show, formation-test, bottom-hole-temperature, and vitrinite reflectance data from 29 exploratory wells. This limited data set supports the presence of a hypothetical basin-centered gas play in the Hanna Basin. Two generalized structural cross sections illustrate our interpretations of possible abnormally pressured compartments. Data indicate that a gas-charged, overpressured interval may occur within the Cretaceous Mowry, Frontier, and Niobrara Formations at depths below 10,000 ft along the southern and western margins of the basin. Overpressuring may also occur near the basin center within the Steele Shale and lower Mesaverde Group section at depths below 18,000 to 20,000 ft. However, the deepest wells drilled to date (12,000 to 15,300 ft) have not encountered over-pressure in the basin center. This overpressured zone is likely to be relatively small (probably 20 to 25 miles in diameter) and is probably depleted of gas near major basement reverse faults and outcrops where gas may have escaped. Water may have invaded reservoirs through outcrops and fracture zones along the basin margins, creating an extensive normally pressured zone. A zone of subnormal pressure also may exist below the water-saturated, normal-pressure zone and above the central zone of overpressure. Subnormal pressures have been interpreted in the center of the Hanna Basin at depths ranging from 10,000 to 25,000 ft based on indirect evidence including lost-circulation zones. Three wells on the south side of the basin, where the top of the subnormally pressured zone is interpreted to cut across stratigraphic boundaries, tested the Niobrara Formation and recovered gas and oil shows with very low shut-in pressures.

Bulletin↗
USGS1989

Quantitative petrographic analysis of Desmoinesian sandstones from Oklahoma

Desmoinesian sandstones from the northern Oklahoma platform and the Anadarko, Arkoma, and Ardmore basins record a complex interaction between mid-Pennsylvanian source-area tectonism and cyclic sedimentation patterns associated with numerous transgressions and regressions. Framework-grain summaries for 50 thin sections from sandstones of the Krebs, Cabaniss, and Marmaton Groups and their surface and subsurface equivalents were subjected to multivariate statistical analyses to establish regional compositional trends for provenance analysis. R-mode cluster and correspondence analyses were used to determine the contributing effect (total variance) of key framework grains. Fragments of monocrystalline and polycrystalline quartz; potassium and plagioclase feldspar; chert; and metamorphic, limestone, and mudstone-sandstone rock fragments contribute most to the variation in the grain population. Q-mode cluster and correspondence analyses were used to identify four petrofacies and establish the range of compositional variation in Desmoinesian sandstones. Petrofacies I is rich in monocrystalline quartz (78-98%); mica and rock fragments are rare. Petrofacies II is also rich in monocrystalline quartz (60-84%) and averages 12% total rock fragments. Petrofacies III and IV are compositionally heterogeneous and contain variable percentages of monocrystalline and polycrystalline quartz, potassium feldspar, mica, chert, and metamorphic and sedimentary rock fragments. Quantitative analyses indicate that Desmoinesian sandstones were derived from sedimentary, igneous, and metamorphic source areas. Sandstones of petrofacies I and II occur mostly in the lower Desmoinesian and are widely distributed, although they are most abundant in eastern and central Oklahoma; sandstones of petrofacies III and IV are widely distributed and occur primarily in the middle and upper Desmoinesian. The range of compositional variation and the distribution of petrofacies are related to paleotectonics and basin development, sediment recycling, and varying depositional environments.

Oklahoma↗