Log-derived regional source-rock characteristics of the Woodford Shale, Anadarko Basin, Oklahoma
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Bulletin↗
Geology topics
James W. Schmoker
Publications and source records attributed to James W. Schmoker.
Woodford shale in the Anadarko basin: Could it be another 'Bakken type' horizontal target?
The Woodford shale is one of several organic rich "black" shales of late Devonian and early Mississippian age present in basins of the North American craton. Where thermally mature, these black shales are economically important as hydrocarbon source rocks. The Woodford shale is widely regarded as a major source rock in the Anadarko basin. This report describes regional depositional trends and organic carbon content of the Woodford shale as evidenced by wire line logs in the Oklahoma portion of the Anadarko basin.
Oil & Gas Journal↗
Thermal maturity of the Anadarko Basin
Levels of thermal maturity are estimated for Paleozoic strata in five areas of the central Anadarko basin for times between the Paleozoic and the present, and depths of the oil window are plotted as a function of geologic time. Mean surface temperature assumed here for calculating Lopatin's time-temperature index of thermal maturity (TTl) in the central Anadarko basin declines from 80°F (27°C) to 60°F (16°C) from early Paleozoic time to the present. Shallow-water carbonates and lower paleolatitudes suggest warmer climates in the Paleozoic for this area. The geothermal gradient is assumed to equal 4.0°F/100 ft (7.3°C/100 m) in the Late Cambrian and to decay over a 100-m.y. period to the present regional gradient of 1.3°F/100 ft (2.4°C/100 m). Initial basin formation was caused by crustal thinning. Accumulation of thick Pennsylvanian sediments in a foreland-style basin dominated by vertical lithospheric flexure represents a second major period of subsidence. An elevated geothermal gradient during this time is not assumed for TTl calculations, because mathematical models suggest time-invariant heat flows in such basins. TTl computations based on these assumptions indicate that oil could have been generated in the ancestral Anadarko basin >350 m.y. ago. By the end of the Pennsylvanian, significant volumes of kerogen were in the oil window (and perhaps beyond), and significant volumes have remained in the oil window up to the present day. These circumstances may partially explain the unusual richness of the Anadarko basin as a Paleozoic hydrocarbon province.
Oklahoma↗
Relationship of clay-mineral diagenesis to temperature, age, and hydrocarbon generation–an example from the Anadarko Basin, Oklahoma
Randomly interstratified illite/smectite (I/S) is present in Springeran and Morrowan rocks (Late Mississippian and Early Pennsylvanian) of the Anadarko basin, Oklahoma, at present-day depths <2,750 m, but disappears at depths of 2,750-3,050 m. Only ordered I/S is found in samples below 3,050 m. The work reported here relates the diagenesis of I/S to burial history and oil generation in the Anadarko basin and tests the dependence of the smectite-to-illite reaction on temperature and time. Published temperature models of clay diagenesis suggest that, for Tertiary and Cretaceous rocks, the transition from randomly interstratified I/S to ordered I/S occurs at 100-110°C. Burial reconstructions for the Anadarko basin indicate that maximum temperatures of 100-110°C correspond to present-day burial depths between 2,700 and 3,100 m. These independently calculated depths for the 100-110°C isotherm match the depths at which randomly interstratified I/S is observed to disappear in Morrowan-Springeran rocks. Thus, random I/S disappears at the same temperature in rocks that differ in age by some 300 m.y. Although the extent of the smectite-to-illite reaction is controlled by kinetics, and effects of time are apparent in laboratory experiments and short-lived geologic systems, the results of this study suggest that time plays a secondary role in long-term diagenetic settings.
Oklahoma↗
Formation resistivity as an indicator of the onset of oil generation in the Woodford Shale, Anadarko Basin, Oklahoma
The Upper Devonian and Lower Mississippian Woodford Shale is a black, organic-rich shale that is a major hydrocarbon source rock in the Anadarko basin. With the onset of oil generation, nonconductive hydrocarbons begin to replace conductive pore water in the Woodford, and formation resistivity increases. Crossplots of formation resistivity versus either vitrinite reflectance (R O ) or Lopatin's time-temperature index of thermal maturity (TTI) define two data populations that represent immature shales and shales that have generated oil. The midpoint of the resistivity zone marking the transition between immature and mature shales is -35 ohm-m. The onset of appreciable oil generation in the Woodford Shale of the study area occurs at maturity levels of R O near 0.57% and of TTI between 33 and 48.
Oklahoma↗
Selected characteristics of limestone and dolomite reservoirs in the United States
Data from the United States Oil and Gas File (TOTL) developed by the University of Oklahoma, Norman, Oklahoma, are used to characterize the lithology, location (state and basin), geologic age, year of discovery, depth to top of pay, porosity, permeability, water saturation, volume of crude oil and nonassociated gas originally in place, and net-pay thickness of limestone and dolomite reservoirs in the United States. Distributions of these parameters, representing thousands of reservoirs, establish a framework to which individual carbonate reservoirs can be compared, and provide insights into geologic processes affecting reservoir characteristics. Limestone reservoirs are more numerous in the United States than dolomite reservoirs (by a ratio of about 3 to 1) because limestones are more abundant than dolomites. However, in the eight states that account for over 90% of United States carbonate reservoirs, there is a statistical tendency for carbonate reservoirs to occur preferentially in dolomites. Dolomite reservoirs, on the average, are larger and deeper than those of limestone, yet they often have lower matrix porosities and permeabilities. This line of investigation offers supplemental evidence that dolomitization tends to improve the reservoir properties of a given formation, and that effective fracture systems at reservoir depths are more likely to occur in dolomites than in limestones.
American Association of Petroleum Geologists Bulle↗
Empirical relation between carbonate porosity and thermal maturity: An approach to regional porosity prediction
Data indicate that porosity loss in subsurface carbonate rocks can be empirically represented by the power function, ^Thgr = a (TTI) b , where ^Thgr is regional porosity, TTI is Lopatin's time-temperature index of thermal maturity, the exponent, b, equals approximately -0.372, and the multiplier, a, is constant for a given data population but varies by an order of magnitude overall. Implications include the following. 1. The decrease of carbonate porosity by burial diagenesis is a maturation process depending exponentially on temperature and linearly on time. 2. The exponent, b, is essentially independent of the rock matrix, and may reflect rate-limiting processes of diffusive transport. 3. The multiplying coefficient, a, incorporates the net effect on porosity of all depositional and diagenetic parameters. Within constraints, carbonate-porosity prediction appears possible on a regional measurement scale as a function of thermal maturity. Estimation of carbonate porosity at the time of hydrocarbon generation, migration, or trapping also appears possible.
American Association of Petroleum Geologists Bulle↗
High-porosity Cenozoic carbonate rocks of South Florida: Progressive loss of porosity with depth
Porosity measurements by borehole gravity meter in subsurface Cenozoic carbonates of south Florida reveal an extremely porous mass of limestone and dolomite which is transitional in total pore volume between typical porosity values for modern carbonate sediments and ancient carbonate rocks. A persistent decrease of porosity with depth, similar to that of chalks of the Gulf Coast, occurs in these rocks. We make no attempt to differentiate depositional or diagenetic facies which produce scatter in the porosity-depth relationship; the dominant data trends thus are functions of carbonate rocks in general rather than of particular carbonate facies. Carbonate strata with less than 20% porosity are absent from the rocks studied here. Aquifers and aquicludes cannot be distinguished on the basis of porosity. Although aquifers are characterized by great permeability and well-developed vuggy and even cavernous porosity in some intervals, they are not exceptionally porous when compared to other Tertiary carbonate rocks in south Florida. Permeability in these strata is governed more by the spacial distribution of pore space and matrix than by the total volume of porosity present. Dolomite is as porous as, or slightly less porous than, limestones in these rocks. This observation places limits on any model proposed for dolomitization and suggests that dolomitization does not take place by a simple ion-for-ion replacement of magnesium for calcium. Dolomitization may be selective for less porous limestone, or it may involve the incorporation of significant amounts of carbonate as well as magnesium into the rock. The great volume of pore space in these rocks serves to highlight the inefficiency of early diagenesis in reducing carbonate porosity and to emphasize the importance of later porosity reduction which occurs during the burial or late near-surface history of limestones and dolomites.
Florida↗
Volume of organic-rich Devonian shale in the Appalachian Basin: relating "black" to organic-matter content: Geologic notes
Some estimates of natural-gas resources in the Devonian shale of the Appalachian basin depend on the volume of organic-rich shale in the basin. A map by L. G. Wallace and W. de Witt showing the thickness and extent of Devonian "black" shale facies in the Appalachian basin is widely used as an indicator of organic-rich shale, but the map is derived from subjective evaluations of shale color. Wallace and de Witt's definition of "black" is shown here to correspond to an organic-matter content of approximately 4% or more by volume and a Munsell color value for dry pressed-powder samples of about N5 (medium gray) or darker. The volume of Devonian shale with an organic-matter content greater than 2.0% by volume (a definition of "organic-rich" that is preferred by the writers) a erages 1.44 times that of the "black" shale of Wallace and de Witt, and totals about 2,574 × 10 12 cu ft (72.9 × 10 12 cu m) in the Appalachian basin.
Appalachian Basin↗
Determination of organic-matter content of Appalachian Devonian shales from gamma-ray logs
The organic-matter content of the Devonian shale of the Appalachian basin is important for assessing natural-gas resources. In most of the western part of the Appalachian basin the organic-matter content of the Devonian shale can be estimated from gamma-ray wire-line logs. Organic-matter contents estimated using these logs are compared with determinations from direct laboratory analyses of organic carbon for 74 intervals of varying thickness from 12 widely separated wells. The cumulative pool of gamma-ray logs for the Devonian shale forms a large and geographically broad data base. The approach may also be applicable to other formations.-from Author
Appalachian Basin↗
Organic content of Devonian shale in western Appalachian basin
In the organic-rich facies of the Devonian shale in the western part of the Appalachian basin, the distribution of organic matter provides an indirect measure of both gas in place and the capacity of the shale to supply gas to permeable pathways.The boundary between organic-rich ('black') and organic-poor ('gray') facies is defined here as 2% organic content by volume. The thickness of organic-rich facies ranges from 200ft in central Kentucky to 1000ft along the Kentucky-West Virginia border. The average content of the organic-rich facies increases from 5% by volume on the edge to 16% in central Kentucky. The net thickness of organic matter in the organic-rich facies shows the amount of organic material in the shale, and is the most fundamental of the organic-content characterizations. Net thickness of organic matter ranges between 20 and 80ft (6.1 and 24.4m) within the mapped area.-from Author
kentucky, New York, Ohio, Pennsylvania, Virginia, ↗
Defining organic-rich facies in the Devonian shale in the western part of the Appalachian Basin
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Open-File Report↗
Borehole gravity surveys in native-sulfur deposits, Culberson and Pecos counties, Texas
Native-sulfur deposits in west Texas are heterogeneous, with sulfur content and formation properties varying significantly over small vertical and horizontal distances. The zone of recovery of the Frasch process extends tens or even hundreds of feet around each recovery well, but the investigation depth of most wire-line logs is measured in inches. Consequently, the analysis of drill cores is still the primary method for the evaluation of sulfur deposits.
Texas↗
Principal facts for borehole gravity stations in test wells Ue10j, Ue7ns, and Ue5n, Nevada Test Site, Nye County, Nevada
In August of 1976, borehole gravity surveys were conducted by the U.S. Geological Survey at the Nevada Test Site in the Ue10j, Ue7ns, and Ue5n test wells. The work was done in cooperation with the Lawrence Livermore Laboratory. The U.S. Geological Survey-LaCoste and Romberg borehole gravity meter was used in the logging program (McCulloh and others, 1967a; McCulloh and others, 1967b). The primary objective of this work was to obtain data for the determination of in situ formation densities utilizing an instrument not significantly affected by casing, borehole rugosity, or other near-borehole conditions. A secondary objective was to obtain duplicate data, by reoccupying subsurface stations, so that the precision and repeatability of borehole gravity data could be studied.
Nevada↗
Principal facts for borehole gravity stations in stratigraphic test well ERDA No. 9, Eddy County, New Mexico
Since 1972 the U.S. Geological Survey has been conducting a series of field evaluation studies in southeastern New Mexico for the Waste Management Division of the Department of Energy (formerly U.S. Energy Research and Development Administration). On the basis of these studies, a tentative site for a nuclear waste repository/disposal facility has been selected near the center of the Los Medafios area in Eddy and Lea Counties, New Mexico (Fig. 1). The proposed host rock for the emplacement of nuclear waste at the potential repository site consists of the bedded evaporite deposits of the Salado Formation. Numerous test holes have been drilled in the Los Medafios area to determine geologic conditions and to obtain geophysical data and rock samples for additional site-evaluation studies. This report tabulates borehole gravity data acquired in one of these test holes, ERDA No. 9, and summarizes the geology of the consolidated rock formations in which gravity observations were made.
New Mexico↗