Joseph R. Hatch

Origin of minerals in joint and cleat systems of the Pottsville Formation, Black Warrior basin, Alabama: Implications for coalbed methane generation and production

Coalbed methane is produced from naturally fractured strata in the lower Pennsylvanian Pottsville Formation in the eastern part of the Black Warrior basin, Alabama. Major fracture systems include orthogonal fractures, which consist of systematic joints in siliciclastic strata and face cleats in coal that strike northeast throughout the basin. Calcite and minor amounts of pyrite commonly fill joints in sandstone and shale and, less commonly, cleats in coal. Joint-fill calcite postdates most pyrite and is a weakly ferroan, coarse-crystalline variety that formed during a period of uplift and erosion late in the burial history. Pyrite forms fine to coarse euhedral crystals that line joint walls or are complexly intergrown with calcite.Stable-isotope data reveal large variations in the carbon isotope composition of joint- and cleat-fill calcite (10.3 to +24.3 Peedee belemnite [PDB]) but only a relatively narrow range in the oxygen-isotope composition of this calcite (16.2 to 4.1 PDB). Negative carbon values can be attributed to 13C-depleted CO2 derived from the oxidation of organic matter, and moderately to highly positive carbon values can be attributed to bacterial methanogenesis. Assuming crystallization temperatures of 2050C, most joint- and cleat-fill calcite precipitated from fluids with 18O ratios ranging from about 11 to +2 standard mean ocean water (SMOW). Uplift and unroofing since the Mesozoic led to meteoric recharge of Pottsville strata and development of freshwater plumes that were fed by meteoric recharge along the structurally upturned, southeastern margin of the basin. Influxes of fresh water into the basin via faults and coalbeds facilitated late-stage bacterial methanogenesis, which accounts for the high gas content in coal and the carbonate cementation of joints and cleats.Diagenetic and epigenetic minerals can affect the transmissivity and storage capacity of joints and cleats, and they appear to contribute significantly to interwell heterogeneity in the Pottsville Formation. In highly productive coalbed methane fields, joint- and cleat-fill calcite have strongly positive 13C values, whereas calcite fill has lower 13C values in fields that are shut in or abandoned. Petrographic analysis and stable-isotope geochemistry of joint- and cleat-fill cements provide insight into coalbed methane reservoir quality and the nature and extent of reservoir compartmentalization, which are important factors governing methane production.

Possible Late Middle Ordovician Organic Carbon Isotope Excursion: Evidence from Ordovician Oils and Hydrocarbon Source Rocks, Mid-Continent and East-Central United States

Oils generated by Middle Ordovician rocks are found throughout the Mid-Continent and east-central regions of the United States. Gas chromatographic characteristics of these oils include a relatively high abundance of n-alkanes with carbon numbers less than 20, a strong predominance of odd-numbered n-alkanes between C10 and C20, and relatively small amounts of branched and cyclic alkanes. Saturated and aromatic hydrocarbon fractions of 43 Ordovician oils from the Anadarko, Ardmore, Forest City, Illinois, Michigan, Salina-Sedgwick, and Williston basins and the Iowa shelf demonstrate a wide range in carbon isotope composition (^dgr13Csat = -24.9 ^pmil to -33.9 ^pmil, (^dgr13Carom = -24.3 ^pmil to -33.7 ^pmil). Saturated and aromatic hydrocarbons extracted from late Middle Ordovician shales (17 core samples) show ranges in ^dgr13C similar to that of the oils. The wide ranges in ^dgr13C for oils and rock extracts reflect a major, positive excursion(s) (6-9 per ^pmil) in organic matter ^dgr13C in late Middle Ordovician rocks. This excursion has at least a regional significance in that it can be documented in sections 480 mi (770 km) apart in south-central Kansas and eastern Iowa. The distance may be as much as 930 mi (1,500 km) if the carbon isotope variations observed in Michigan basin Ordovician oils and in organic matter from late Middle Ordovician rocks in southwestern Ontario are related to the same carbon isotope excursion. Organic-matter ^dgr13C in core samples from south-central Kansas and eastern Iowa is not directly related to variations in quantity or quality of organic matter, or maceral compositi n. The positive excursion in organic matter ^dgr13C is a possible result of increased organic matter productivity and/or preservation. The parallel shifts in organic and carbonate ^dgr13C in core samples from 1 E. M. Greene well, Washington County, Iowa, imply changes in the isotope composition of the ocean-atmosphere carbon reservoir. Differences in the magnitude of the carbon isotope shifts between organic matter (8.8 ^pmil) and carbonate (4.2 ^pmil) in this core suggest a decrease, either locally or regionally, in available dissolved CO2, possibly a result of high organic-matter productivity and/or limited circulation in the late Middle Ordovician seas.

Regional fluid flow as a factor in the thermal history of the Illinois basin: Constraints from fluid inclusions and the maturity of Pennsylvanian coals

Vitrinite reflectance measurements on Pennsylvanian coals in the Illinois basin indicate significantly higher thermal maturity than can be explained by present-day burial depths. An interval of additional sedimentary section, now removed by erosion, has been suggested to account for the discrepancy. Although burial could indeed account for the observed maturity levels of organic matter, fluid-inclusion temperatures provide a stringent additional constraint. In this article, we combine measurements of coal maturity with fluid-inclusion temperatures from three sites to constrain the basins thermal and burial history: the Fluorspar district at the Illinois basins southern margin, the Upper Mississippi Valley zinc district at the basins northern margin, and a north-central location. Two-dimensional numerical modeling of a north-south cross section through the basin tests scenarios both with and without regional fluid flow. Vitrinite reflectance values can be matched assuming burial by 1.8-2.8 km of southward-thickening additional, post-Pennsylvanian sedimentary section. In the central and northern Illinois basin, however, these burial depths and temperatures are not sufficient to account for the fluid-inclusion data. To account for both parameters with burial alone does not appear feasible. In contrast, our best hypothesis assumes a wedge of post-Pennsylvanian sediment-thickening southward to about 1.2 km and a brief period of magmatism in the Fluorspar district. Significant advective heat redistribution by northward regional fluid flow accounts for fluid-inclusion temperatures and coal maturities throughout the basin. The modeling results demonstrate the potential contribution of advective heat transport to the thermal history of the Illinois basin. (Begin page 258)

The US Geological Survey's national coal resource assessment: The results

Abstract The US Geological Survey and the State geological surveys of many coal-bearing States recently completed a new assessment of the top producing coal beds and coal zones in five major producing coal regions—the Appalachian Basin, Gulf Coast, Illinois Basin, Colorado Plateau, and Northern Rocky Mountains and Great Plains. The assessments, which focused on both coal quality and quantity, utilized geographic information system technology and large databases. Over 1,600,000 million short tons of coal remain in over 60 coal beds and coal zones that were assessed. Given current economic, environmental, and technological restrictions, the majority of US coal production will occur in that portion of the assessed coal resource that is lowest in sulfur content. These resources are concentrated in parts of the central Appalachian Basin, Colorado Plateau, and the Northern Rocky Mountains.

Black Shale Source Rocks and Oil Generation in the Cambrian and Ordovician of the Central Appalachian Basin, USA

Nearly 600 million bbl of oil (MMBO) and 1 to 1.5 trillion ft3 (tcf) of gas have been produced from Cambrian and Ordovician reservoirs (carbonate and sandstone) in the Ohio part of the Appalachian basin and on adjoining arches in Ohio, Indiana, and Ontario, Canada. Most of the oil and gas is concentrated in the giant Lima-Indiana field on the Findlay and Kankakee arches and in small fields distributed along the Knox unconformity. Based on new geochemical analyses of oils, potential source rocks, bitumen extracts, and previously published geochemical data, we conclude that the oils in both groups of fields originated from Middle and Upper Ordovician black shale (Utica and Antes shales) in the Appalachian basin. Moreover, we suggest that approximately 300 MMBO and many trillions of cubic feet of gas in the Lower Silurian Clinton sands of eastern Ohio originated in these same source rocks. Oils from the Cambrian and Ordovician reservoirs have similar saturated hydrocarbon compositions, biomarker distributions, and carbon isotope signatures. Regional variations in the oils are attributed to differences in thermal maturation rather than to differences in source. Total organic carbon content, genetic potential, regional extent, and bitumen extract geochemistry identify the black shale of the Utica and Antes shales as the most plausible source of the oils. Other Cambrian and Ordovician shale and carbonate units, such as the Wells Creek formation, which rests on the Knox unconformity, and the Rome Formation and Conasauga Group in the Rome trough, are considered to be only local petroleum sources. Tmax, CAI, and pyrolysis yields from drill-hole cuttings and core indicate that the Utica Shale in eastern and central Ohio is mature with respect to oil generation. Burial, thermal, and hydrocarbon-generation history models suggest that much of the oil was generated from the Utica-Antes source in the late Paleozoic during the Alleghanian orogeny. A pervasive fracture network controlled by basement tectonics aided in the distribution of oil from the source to the trap. This fracture network permitted oil to move laterally and stratigraphically downsection through eastward-dipping, impermeable carbonate sequences to carrier zones such as the Middle Ordovician Knox unconformity, and to reservoirs such as porous dolomite in the Middle Ordovician Trenton Limestone in the Lima-Indiana field. Some of the oil and gas from the Utica-Antes source escaped vertically through a partially fractured, leaky Upper Ordovician shale seal into widespread Lower Silurian sandstone reservoirs.

Mechanical and Thermal Control of Cleating and Shearing in Coal: Examples from the Alabama Coalbed Methane Fields, USA

Natural fractures provide most of the interconnected macroporosity in coal. Therefore, understanding the characteristics of these fractures and the associated mechanisms of formation is essential for effective coalbed methane exploration and field management. Natural fractures in coal can be divided into two general types: cleat and shear structures. Cleat has been studied for more than a century, yet the mechanisms of cleat formation remain poorly understood (see reviews by Close, 1993; Laubach et al.,1998). An important aspect of cleating is that systematic fracturing of coal is takes place in concert with devolatization and concomitant shrinkage of the coal matrix during thermal maturation (Ammosov and Eremin, 1960). Coal, furthermore, is a mechanically weak rock type that is subject to bedding-plane shear between more competent beds like shale, sandstone, and limestone. Yet, the significance of shear structures in coal has only begun to attract scientific interest (Hathaway and Gayer, 1996; Pashin, 1998).

Geochemical Characterization of Rocky Mountain, Northern Great Plains, and Interior Province Coals: ABSTRACT

Statistical summaries of proximate and ultimate analyses, heat of combustion, and content of 36 major, minor, and trace elements were calculated for 37 Eocene, 470 Paleocene, and 419 Cretaceous coal samples from 31 coal fields or areas in the Rocky Mountain and Northern Great Plains coal provinces and for 503 Pennsylvanian coal samples from 14 areas in the Interior coal province. These analyses show that coals within an age group have similar ranges in composition, and that each group has its own distinctive compositional characteristics. Most variability in element content can be related to changes in rank and differences in ash and total sulfur contents. Mean contents of Ca, Mg, Na, Ba, and Sr are related to rank and decrease as apparent coal rank increases from lignite A to high-volatile B bituminous coal. Mean contents of Si, Al, K, Ti, Ga, Li, Sc, Th, V, Y, and Yb increase as the mean ash content increases (correlation coefficients 0.6), suggesting that these elements are present as aluminosilicates, stable oxides, or phosphate mineral phases. Mean contents of Fe, As, Cd, Co, Cu, Mo, Ni, Pb, Sb, and Zn show high correlation with total sulfur. Contents of these elements are low in Paleocene (0.6% sulfur) and Cretaceous (0.7% sulfur) coals, higher in Eocene (1.8% sulfur) coals, and generally highest in Pennsylvanian (3.9% sulfur) coals. The mean contents of B, Be, Cr, F, Hg, Mn, Nb, Se, U and Zr show no direct relationships to changes in rank or ash and total sulfur contents. Decrease in element content with increased rank probably is related to loss o functional groups that act as cation-exchange sites on organic matter. Ash and sulfur contents are dependent on pH-controlled levels of bacterial activity in ancestral peat swamps. End_of_Article - Last_Page 447------------

A petroleum system for the Salina Basin in Kansas based on organic geochemistry and geologic analog

The Salina Basin historically has been an “exploration desert”—a home of dryholes. Although this basin, which underlies much of north-central Kansas, may never be a prolific source of hydrocarbons, recent research into the maturation and geochemistry of organic matter and oils in Kansas can provide guidelines for a new exploration strategy. The Salina Basin is similar to the oil-productive Forest City Basin in northeastern Kansas in many ways. Both basins originated as a single large basin (i.e., the North Kansas Basin) prior to the rise of the Nemaha Uplift in Late Mississippian-Early Pennsylvanian time. Their Paleozoic stratigraphy thus is similar and the axes of both basins are presently at approximately the same depth. Thermal maturation modeling and available organic-matter maturation data indicate that the lower Paleozoic rocks in the axes of both basins are in the early stages of oil generation. In the Forest City Basin the Ordovician Simpson Group is the deepest known hydrocarbon source-rock—oil-reservoir interval, and by analogy, exploration tests in the Salina Basin, at a minimum, should penetrate through this stratigraphic interval. Ordovician Simpson Group shales in the Forest City Basin are the source rocks for a geochemically distinct oil, which also occurs in Ordovician reservoirs in the extreme southern end of the Salina Basin. To increase the odds of success in an exploration program in the Salina Basin, wildcat wells should be drilled where thermal maturation is greatest. The broad NW–SE-trending basin axis is the most logical area. Exploration tests along this axis in the northern end of the basin may have an extra advantage as organic matter in the Simpson Group may be more thermally mature because of greater burial depth during the Cretaceous. Along the eastern margin of the nearby Central Kansas Uplift and Pratt Anticline, several Paleozoic geologic structures, some of which contain major oil fields, are attributable to tectonic reactivation along the western margin of the Precambrian Central North American Rift System (CNARS). Prospective structural trends in the Paleozoic section of the Salina Basin are anticipated to be associated with this underlying tectonic boundary. The western margin of the CNARS trends NNE–SSW where it passes under the axis of the Salina Basin in northeastern Lincoln and southeastern Mitchell counties. This area is sparsely drilled, with less than two tests per township. If an exploration program can define lower Paleozoic structural closures in this region, these structures may represent the best chance for future petroleum discoveries.

Comparative Organic Geochemistry of Shales and Coals from Cherokee Group and Lower Part of Marmaton Group of Middle Pennsylvanian Age, Oklahoma, Kansas, Missouri, and Iowa: ABSTRACT

Mid-Continent middle Pennsylvanian rocks are a complex assemblage of coal-cyclothem lithologies. Organic-matter-rich rocks in the section include coals (33 to 76% organic carbon--org. C), marine, dark-gray to gray-black shales (1 to 8% org. C), and laminated, phosphatic black shales (4 to 28% org. C). Organic matter in these rocks came mostly from peat swamps, as shown by similarities between coal and shales in organic petrography, hydrogen (H) and oxygen (O) indices (Rock-Eval pyrolysis), pyrolysis-gas chromatographic analyses, and gas chromatographic analyses of saturated hydrocarbon fractions of CHCl3 extracts. A halocline, resulting from the river waters that transported the dissolved and fine particulate organic matter from the extensive swamps, may have b en the principal mechanism for restricting circulation in the shale-depositing environments. Some organic geochemical properties vary significantly within and between the coal and shale lithologies, reflecting inferred differences in intensity of depositional and diagenetic anoxic conditions and degree of thermal maturation. For shales with comparable thermal maturities, deposition and diagenesis under more intense anoxic conditions result in higher org. C, P, U, Se, Mo, V, Ni, Ag, and Cr contents, H indices, saturate/aromatic and NSO/asphaltene ratios in CHCl3 extracts, and lower O indices, pristane/phytane ratios, and organic carbon ^dgr13C values (more negative by 1 to 2 per mil). H and O indices in coals resemble those of shales deposited under the most intense anoxic conditions. In contrast, saturate/aromatic, NSO/asphaltene, and pristane/phytane ra ios in coal extracts, trace- and minor-element contents, and organic carbon ^dgr13C of coals resemble shales deposited under relatively oxic conditions. A few coals are overlain by black phosphatic shales and have been subjected to more intense anoxic diagenesis. These coals have higher U, Se, Mo, V, Ni, and Cr contents, lower pristane/phytane ratios, and more negative (~1 per mil) organic carbon ^dgr13C values. When normalized to n-C18, most pristane/phytane variability in all rock types appears to be related to variation in amounts of pristane, phytane content remaining relatively constant. With increased degree of thermal maturity, (1) H and O indices decrease in both coals and shales; (2) total bitumen/org. C and pristane/phytane ratios increase in sh les but decrease in coals; and (3) saturate/aromatic ratios increase significantly only in shales that were subject to high levels of anoxic diagenesis. The black phosphatic shales contain extractable organic matter that is most similar to Cherokee crude oils from northeast Oklahoma and southeast Kansas. End_of_Article - Last_Page 579------------

Weathering-Induced Chemical Changes in Surface Coals from Paleocene Fort Union Formation, Red Rim Area, Sweetwater and Carbon Counties, Wyoming: ABSTRACT

Statistically significant differences in chemical composition between 20 outcrop and 22 stratigraphically equivalent core coal samples were demonstrated by proximate and ultimate analyses, heat-of-combustion and forms-of-sulfur determinations, and chemical analyses for 37 elements. The outcrop samples were collected from depths of 30 to 72 in. (75 to 180 cm) on very steep (> 45°) slopes. Core samples were from depths of 31 to 190 ft (9 to 58 m) at distances between 300 and 1,500 ft (91 and 457 m) from the outcrop. Mean annual precipitation in the Red Rim area is ~ 11 in. (28 cm); mean monthly temperatures range from 22°F (-5.5°C) in January to 68°F (20°C) in July. Apparent rank of unweathered coal is subbituminous C coal. Compared with the core samples (moisture and Btu/lb, as-received basis, all others moisture-free basis) the outcrop samples have significantly higher mean moisture (37.4 vs 23.8%), volatile matter (43.8 vs 35.1%), oxygen (24.9 vs 15.6%), and nitrogen (1.0 vs 0.8%); lower ash (13.3 vs 18.2%), hydrogen (3.0 vs 4.7%), sulfur (0.6 vs 1.1%) and heat of combustion (5,330 vs 7,690 Btu/lb); similar fixed carbon (42.5 vs 46.6%) and carbon contents (56.7 vs 60.3%). The sulfate part of the total sulfur increased from 5% in core to 18% in outcrop samples; pyritic sulfur decreased from 14 to 10%, and organic sulfur decreased from 84 to 71%. As indicated by differences in element/Al ratios between core and outcrop samples, the relative rates of removal of Si, K, B, Cr, Ga, La, Li, and V from coal during weathering are signi icantly greater than Al; Cd, Co, F, Ni, Se, and Zn are significantly greater than Al; Cd, Co, F, Ni, Se, and Zn are significantly less than Al; and Ca, Mg, Na, Fe, Ti, As, Ba, Be, Cu, Mg, Mn, Mo, Nb, Pb, Sb, Se, Sr, Th, U, Y, Yb, and Zr are similar to Al. Additional significant chemical changes in outcrop samples should be expected in areas of warmer, more humid climates, where coal is of lower rank, or in samples collected on less-steep slopes or at shallower depths. End_of_Article - Last_Page 936------------