William L. Fisher

Edwards Formation (Lower Cretaceous), Texas: Dolomitization in a Carbonate Platform System

The Edwards Formation is characterized by rudist bioherms, carbonate grainstone and mudstone, and evaporites which were deposited on an extensive, shallow-water, marine platform bounded by deeper water basins in which chiefly carbonate muds were deposited. Rudist bioherms were constructed principally along platform edges peripheral to an evaporitic lagoon. Main dolomite deposits are in a concentric belt marginal to the lagoonal facies. Two main types of dolomite are present: (1) stratal dolomite--fine grained, tightly knit fabric, laminated to thin bedded, very slightly porous and permeable, associated with thin-bedded, mud-cracked, stromatolitic carbonate mudstone, ripple-marked carbonate grainstone, and thin evaporite-collapse layers; dolomite units are generally less than 2 ft (0.6 m) thick; magnesium carbonate content ranges irregularly from low to high; and (2) massive dolomite--fine- to coarse-grained loosely knit euhedral crystals, moderately to highly porous and permeable, replacing thick-bedded, fossiliferous carbonate grainstone; dolomite units are commonly more than 10 ft (3 m) thick and underlie prominent evaporite-solution units; magnesium carbonate content is low or high, with few intermediate values. Both stratal and massive dolomites are judged to be products of metasomatic replacement of calcium carbonate which resulted from contact with magnesium-enriched brines. Features of stratal dolomite indicate prelithification replacement of carbonate muds and grains in extensive, low-relief, supratidal and intertidal zones along the southern margin of the lagoon. Massive dolomite was created by postlithification replacement of reef-trend carbonate grainstone along the northern margin of the lagoon as a result of seepage refluxion of lagoon brines. Both dolomitization processes were part of the original depositional system, and type of dolomitization was controlled by specific depositional facies of the system.

Thematic Set: Sequence stratigraphy: common ground after three decades of development

Sequence stratigraphy emphasizes changes in stratal stacking patterns in response to varying accommodation and sediment supply through time. Certain surfaces are designated as sequence or systems tract boundaries to facilitate the construction of realistic and meaningful palaeogeographic interpretations, which, in turn, allows for the prediction of facies and lithologies away from control points. Precisely which surfaces are selected as sequence boundaries varies from one sequence stratigraphic approach to another. In practice, the selection is often a function of which surfaces are best expressed, and mapped, within the context of each case study. This high degree of variability in the expression of sequence stratigraphic units and bounding surfaces requires the adoption of a methodology that is sufficiently flexible to accommodate the wide range of possible scenarios in the rock record. We advocate a model-independent methodology that requires the identification of all sequence stratigraphic units and bounding surfaces, which can be delineated on the basis of facies relationships and stratal stacking patterns using the available data. Construction of this framework ensures the success of the method in terms of its objectives to provide a process-based understanding of the stratigraphic architecture and predict the distribution of reservoir, source-rock, and seal facies.

Can the U.S. Oil and Gas Resource Base Support Sustained Production

Aggressive drilling for oil and gas in the lower 48 states of the United States over the past decade yielded reserve additions sufficient to arrest decline and to stabilize levels of production. Such positive response from a maturely explored and developed oil resource base was unpredicted and largely unanticipated. Two elements of the recent experience—maintenance of stable rates of finding and substantial levels of conventional reserve growth in older fields—indicate that the capability of the resource base to sustain production is yet considerable. The volume of domestic oil and gas production that is necessary in the national interest and the extent to which the resource base should be pursued are the central issues of public energy policy.

Early and middle Miocene depositional history of the Maracaibo Basin, western Venezuela

The uplift of the Sierra de Perij and Mrida Andes and the marine connection with the Falcn Basin ultimately controlled the distribution of shallow-marine, coastal, and nonmarine sedimentary rocks in the Maracaibo Basin during the early and middle Miocene. These rocks contain the most important shale top seal in the basin and nearly three-quarters of the produced plus proven reserves of the supergiant Bolvar coastal fields. The Maracaibo Basin has been isolated from extrabasinal drainage systems since the late Oligocene, and sediments derived from the surrounding highlands were either deposited in the basin or delivered into the neighboring Falcn Basin through a narrow marine passage (the westward extension of the Falcn Channel). Four unconformity-bounded sequences mapped in the northeastern sector of the Maracaibo Basin help recreate its regional paleogeography as it was flooded from the northeast through this passage. In the early Miocene, part of the basin became a semi-enclosed shallow-marine gulf, and wave- and tide-modified deltas prograded across the temporarily inactive Lama-Icotea fault system. As sea level dropped, the shoreline advanced eastward of the Falcn Channel, and valleys were incised and subsequently filled by transgressive estuarine sediments. In the next sea level highstand, tidal-bar complexes of a tide-dominated delta system prograded and filled all available accommodation space. In the middle Miocene, relative sea level dropped into the Falcn Basin, and the Maracaibo area became a mixed-load fluvial drainage basin. By late middle Miocene, the two basins were separated, and the Maracaibo Basin became an intermontane fluvial-lacustrine depression.

Log-derived thickness and porosity of the Barnett Shale, Fort Worth basin, Texas: Implications for assessment of gas shale resources

This study estimates reservoir quality and free-gas storage capacity of the Barnett Shale in the main natural-gas producing area of the Fort Worth basin by mapping log-derived thickness, porosity, and porosity-feet. In the Barnett Shale, the density porosity (DPHI) log curve is a very useful tool to quantitatively assess shale gas resources, and gamma-ray (GR) and neutron porosity log curves are important factors in identifying the shale gas reservoir. The key data were digital logs from 146 wells selected based on the availability of GR and density log curves, log quality, and good spatial distribution. The Barnett Shale pay zone was determined on the basis of (1) DPHI >5%, (2) high GR values (commonly >∼90 API units), (3) no significant intercalated carbonate-rich beds, and (4) individual pay zones being thick enough to be commercially successful for the current design of horizontal wells. In the study area, the Barnett Shale pay zone varies from about 165 ft (50 m) to 420 ft (128 m) in thickness (H). Average DPHI values of individual wells for the pay zone vary from 8.5 to 14.0%. Porosity-feet maps of the pay zone show that areas of high DPHI-H values coincide with areas of high natural gas production, indicating that log-derived porosity-feet maps are a good method for evaluating reservoir quality and assessing natural gas resource in the Barnett Shale play. A limitation to this method is shown in the northwestern corner of the study area, which is located in the liquids-rich window with lower thermal maturity.

Log-derived thickness and porosity of the Barnett Shale, Fort Worth basin, Texas

This study estimates reservoir quality and free-gas storage capacity of the Barnett Shale in the main natural-gas producing area of the Fort Worth basin by mapping log-derived thickness, porosity, and porosity-feet. In the Barnett Shale, the density porosity (DPHI) log curve is a very useful tool to quantitatively assess shale gas resources, and gamma-ray (GR) and neutron porosity log curves are important factors in identifying the shale gas reservoir. The key data were digital logs from 146 wells selected based on the availability of GR and density log curves, log quality, and good spatial distribution. The Barnett Shale pay zone was determined on the basis of (1) DPHI >5%, (2) high GR values (commonly >∼90 API units), (3) no significant intercalated carbonate-rich beds, and (4) individual pay zones being thick enough to be commercially successful for the current design of horizontal wells. In the study area, the Barnett Shale pay zone varies from about 165 ft (50 m) to 420 ft (128 m) in thickness (H). Average DPHI values of individual wells for the pay zone vary from 8.5 to 14.0%. Porosity-feet maps of the pay zone show that areas of high DPHI-H values coincide with areas of high natural gas production, indicating that log-derived porosity-feet maps are a good method for evaluating reservoir quality and assessing natural gas resource in the Barnett Shale play. A limitation to this method is shown in the northwestern corner of the study area, which is located in the liquids-rich window with lower thermal maturity.

Future supply potential of US oil and natural gas

The prospect for long‐term stable supply from United States sources of oil and natural gas is good. It is a prospect quite different from the pervasive view of the 1970s of a rapidly depleting, high‐cost resource base. Gas drilling over the past six years is barely half the level averaged in the late ’70s and early ’80s, and the average wellhead price, in real terms, is the lowest in 15 years; and yet gas reserve additions have equaled in volume the reserves added when gas drilling and wellhead prices were twice the level of the past six years (Figure 1).

EVOLUTIONARY FEATURES OF ATHLETA (EOCENE, GASTROPODA) FROM THE GULF COASTAL PLAIN'

Volutid gastropods of the genus Athleta Conrad, 1853, are abundant and well preserved in marine Eocene rocks of the Gulf Coastal Plain (fig. 1). Several representatives of this genus form an evolutionary or phylogenetic stock characterized by Athleta petrosa (Conrad, 1833). Main evolutionary features are derived from a quantitative phylogenetic study of 1,600 specimens of Athleta from several localities in the Gulf Coastal Plain (Fisher, Rodda, and Dietrich, in press), and are summarized herein. Four species, A. tuomeyi Conrad, 1853, A. petrosa (Conrad, 1833), A. lisbonensis (Aldrich, 1897), and A. dalli (Harris, 1895), comprise the A. petrosa stock (fig. 2). The most common species is A. petrosa, found in Claibornian and Jacksonian rocks; it forms the main line of the stock and includes three successional subspecies: A. petrosa new subspecies, from the Reklaw Formation in Texas; A. petrosa petrosa from the Weches, Stone City, and Cook Mountain formations in Texas, equivalent rock units in Louisiana, and the Gosport Formation of Alabama; and A. petrosa symmetrica (Conrad) from Jacksonian rocks in Texas, Louisiana, and Mississippi. Other species of the stock are related closely to A. petrosa but show morphologic trends that define separate, divergent lineages. A. tuomneyi is an early cladogenetic species and occurs in the Wilcox Group throughout the Gulf Coastal Plain. A. lisbonensis is found in Claibornian rocks in Texas and Alabama; A. dalli has been collected only from Claibornian rocks in Texas. Phylogenetic relationships of taxa forming the A. petrosa stock are shown diagrammatically in fig. 2.

Depositional systems and environments

Depositional systems are descriptions of the interrelationships of form and the physical, chemical,…

Definition of Depositional Geological Elements in Deep-Water Minibasins of the Gulf of Mexico Using Spectral Decomposition in Depth Domain

Submarine channels, large scours, distributary channel-lobe complexes, turbidite fan complexes and many other components of deep water depositional systems in the central Gulf of Mexico were successfully imaged and mapped using spectral decomposition in the depth domain. When this powerful tool is applied along an interpreted seismic horizon, a better definition of stratigraphic architecture is obtained.