Northern Appalachian Basin Research Articles

The Frasnian/Famennian boundary in central and eastern United States

The Frasnian/Famennian (F/F) Boundary in the northern Appalachian Basin is found in the Hanover Shale and equivalent strata where it is locally associated with a black shale interval equivalent to the Upper Kellwasser interval in Europe. The boundary is immediately below the Dunkirk–Huron black shale that represents the IIe T–R cycle transgression. In the southern Appalachian Basin, the southern edge of the Cincinnati Arch, and the southeastern Illinois Basin the F/F boundary is at or near the base of the Gassaway Member of the Chattanooga Shale or the Morgan Trail Member of the New Albany Shale, or was eroded during the IIe T–R cycle beginning in the Middle triangularis Zone. In the western Illinois Basin (Grassy Creek Shale), Michigan Basin (Lachine Member of Antrim Shale), and southern continental margin (Woodford Shale) the F/F boundary is within black shale strata, indicative of an earlier development of the IIe T–R transgression inboard of the Appalachian Basin or the juxtaposition of the IIe T–R transgression over the Upper Kellwasser black shale interval without significant or recognizable lithologic change.

An integrated assessment of a "type euxinic" deposit: Evidence for multiple controls on black shale deposition in the middle Devonian Oatka Creek formation

An integrated lithologic, paleontologic, and multi-proxy geochemical study of the Middle Devonian Oatka Creek Formation, a black shale in the northern Appalachian Basin, indicates that a number of different factors contributed to organic carbon-rich black shale deposition. Conditions leading to this organic-rich sedimentary deposit were ultimately controlled by a relative sealevel rise, dominantly eustatic but with possible contributions from local tectonics, which cut off the supply of carbonate to the basin. Geochemical proxy evidence –such as Mo/Ti, Fe/Ti, Corg, Spy, and δ34Spy –suggests that as sealevel continued to rise after the carbonate supply was cut off, a threshold was crossed at which point conditions in the basin shifted from dominantly anoxic to dominantly euxinic (anoxic-sulfidic bottom waters). Concurrent with the shift to dominantly euxinic conditions, the supply of siliciclastic sediments was cut off, resulting in a condensed horizon, as evidenced by the elemental ratios of Si/Al and K/(Fe+Mg) and the relative concentration of eolian silt as determined petrographically and from scanning electron microscopy. Sediment starvation in the basin appears to have facilitated the biogeochemical (re)cycling of C, N, and P. Specifically, the elemental ratios of C, N, and P and the stable carbon isotope composition of organic matter suggest that the preferential regeneration of P under anoxic conditions (and of N during the oxic phase of oxic/anoxic oscillation) led to enhanced primary production in surface waters, thereby maintaining euxinic conditions in the bottom waters through respiration of settling organic matter. Finally, it is observed that, though conditions in the basin seem to have remained consistently anoxic-sulfidic for some time after the initial shift to euxinic conditions, a progressive increase in siliciclastic sedimentation led to a corresponding decrease in the enrichment of various redox-related elements, illustrating the overriding control that sedimentation can have on geochemical proxy records.

Coalbed gas systems, resources, and production and a review of contrasting cases from the San Juan and Powder River basins

Coalbed gas has been produced commercially from the northern Appalachian basin since the 1930s and from the San Juan basin since the early 1950s. However, the magnitude and economic sig nificance of coalbed gas resources were realized only in the 1970s and early 1980s when the U.S. Bureau of Mines, U.S. Department of Energy, the Gas Research Institute, and oil and gas operators made a concerted effort to demonstrate commercial production of coalbed gas from vertical wells. Exploration and development ex panded in the late 1980s and early 1990s, due partly to an uncon ventional fuels tax credit. By 2000, coalbed gas accounted for 8.8% of the reserves (15.7 tcf [0.44 Tm3]) and 9.2% of the annual pro duction (1.38 tcf [40 Gm3]) of dry gas in the United States. From 1989 through 2000, cumulative United States coalbed gas produc tion was 9.63 tcf (272 Gm3). Today, coalbed gas development has spread to about a dozen basins in the United States, and exploration is progressing worldwide. Coal beds are self-sourcing reservoirs that can contain ther mogenic, migrated thermogenic, biogenic, or mixed gas. Coalbed gas is stored primarily within micropores of the coal matrix in an adsorbed state and secondarily in micropores and fractures as free gas or solution gas in water. The key parameters that control gas resources and producibility are thermal maturity, maceral compo sition, gas content, coal thickness, fracture density, in-situ stress, permeability, burial history, and hydrologic setting. These param eters vary greatly in the producing fields of the United States and the world. In 2000, the San Juan basin accounted for more than 80% of the United States coalbed gas production. This basin contains a gi ant coalbed gas play, the Fruitland fairway, which has produced more than 7 tcf (0.2 Tm3) of gas. The Fruitland coalbed gas system and its key elements contrast with the Fort Union coalbed gas play in the Powder River basin. The Fort Union coalbed play is one of the fastest developing gas plays in the United States. Its production escalated from 14 bcf (0.4 Gm3) in 1997 to 147.3 bcf (4.1 Gm3) in 2000, when it accounted for 10.7% of the United States coalbed gas production. By 2001, annual production was 244.7 bcf (6.9 Gm3). Differences between the Fruitland and Fort Union petroleum systems make them ideal for elucidating the key elements of contrasting coalbed gas petroleum systems.

Modelling rock–water interactions in flooded underground coal mines, Northern Appalachian Basin

Inverse geochemical modelling was used to investigate rock–water interactions in flooded underground coal mines in northern Appalachia, USA. In early flooding, Pittsburgh seam mine waters are usually acidic ( c. pH 3), with dissolved metals Fe and Al ranging from 10 to >100 mg l −1 . Within a few decades, however, waters in fully flooded mines usually have pH of about 7 S.U., and alkalinity >300 mg l −1 CaCO 3 Eq. Eh shifts from oxidizing ( c . 500 to 700 mv) to reduced (−100 to −200 mv) conditions. Sodium concentrations may increase an order of magnitude; sulphate and iron concentrations may also increase. Water samples were collected from several mine-pools in West Virginia and Pennsylvania. A conceptual model was developed based on quantitative hydrology, mine-pool chemistry, mining conditions and mineralogy. The model was tested with the geochemical code PHREEQC. Simulations included mixing recharge and acid mine waters, precipitation–dissolution reactions involving carbonates, sulphates, oxy-hydroxides and sulphides, and ion adsorption and exchange. Na exchange was a dominant process in all models. Carbonates are orders of magnitude undersaturated in the juvenile mine-pool, but near saturation in the mature mine-pool, suggesting they are a primary source of acid neutralization and alkalinity. The mature mine-pool is simultaneously near equilibrium with iron sulphide, iron carbonate and iron oxy-hydroxide mineral phases. The rapid change in mine-pool water quality has substantial implications for management of these systems. Corresponding author eperry@osmre.gov

Three-Dimensional Crystal Structures of Illite-Smectite Minerals in Paleozoic K-Bentonites from the Appalachian Basin

AbstractThe three-dimensional crystal structures of illite-smectite (I-S) in K-bentonite samples from the Appalachian Basin are characterized by rotational disorder in the stacking sequence of 2:1 illite layers, different proportions of n60° rotations (as opposed to n120°) in the rotated layers, and layers with centrosymmetric trans-vacant (tv) octahedral sites that are randomly interstratified with noncentric cis-vacant (cv) layers. The proportion of cv interstratification in the I-S increases with tetrahedral A1 and decreases with octahedral Mg and Fe content. The I-S minerals in the northern Appalachian basin K-bentonites are characterized by high (79% average) proportions of cv (Pcv) layers. In contrast, I-S from equivalent K- bentonites from the southern Appalachian basin has low Pcv values (38% average). These values do not correlate with expandability or rotational disorder. The geographic distribution of these I-S structural parameters may have resulted from possibly short-term, hot, and advective fluid migrations that differed in Mg concentrations and/or other physical and chemical parameters.

Bulge Migration and Pinnacle Reef Development, Devonian Appalachian Foreland Basin.

Detailed stratigraphic analyses of Late Emsian and Early Eifelian (Lower to Middle Devonian) carbonate-dominated strata in the northern Appalachian Basin indicate anomalous, locally varying relative sea level changes and inversions of topography. The distribution of a major basal-bounding unconformity, basinal pinnacle reefs, local absence of parasequences, and eastward migration of shallow marine carbonate lithofacies and related biofacies in the Onondaga Limestone and underlying strata mark the retrograde migration of an elongate, northeast-southwest-trending area of positive relief, bordered on its cratonward side by a similarly migrating basin of intermediate depth. These features are thought to represent the forebulge and back-bulge basin of the Appalachian foreland basin system as it developed during a time of relative quiescence within the Acadian Orogeny. However, the relatively small size of the bulgelike feature (ca. 80-100-km-wide, 20-50-m positive relief), its great distance from the probable deformation front (>400 km), and the lack of a well-developed foredeep immediately adjacent to the bulgelike feature may indicate that it represents a smaller-scale flexural high ("flexural welt") superposed over the cratonward edge of the larger-scale classical forebulge of the basin. Development of shallow-water reefs on the crest of the bulge during sea level lowstand, followed by migration of the bulge and widespread transgression, permitted growth of economically significant pinnacle reefs in the deep basin center. Further subsurface reef exploration should concentrate along the projected position of the bulge during the basal Onondaga lowstand.

00/00040 Coal quality in the Northern Appalachian Basin

The national coal resource assessment, being conducted by the US Geological Survey (USGS), provides information on both the quantity and quality of the coal beds and zones of the coals that are expected to provide most of the coal utilized in the US during the next few decades. As part of this assessment, the USGS developed comprehensive geochemical databases for the Pittsburgh and the Upper Freeport coal beds, which are then used to map and model trends in the ash yield, sulfur (S) content, and calorific value of the coals, as well as trends in selected major-, minor-, and trace- element contents. Compilation of the databases, mapping of geochemical trends, and comparisons of the trends and mean values for ash yield, S content, calorific value (Btu/lb), arsenic (As) content, selenium (Se) content, mercury (Hg) content, and chlorine (Cl) content for these beds are discussed in the paper. Final results for the complete database are presented for the Pittsburgh coal bed. Preliminary results for ash yield, S content and calorific value are presented for the Upper Freeport coal bed.

A digital resource model of the Upper Pennsylvanian Pittsburgh coal bed, Monongahela Group, northern Appalachian basin coal region, USA

The U.S. Geological Survey is currently conducting a coal resource assessment of the coal beds and zones that are expected to provide the bulk of the Nation's coal resources for the next few decades. The Pittsburgh coal bed is the first bed in the northern and central Appalachian basin coal region to undergo a fully-digital assessment. The bed-specific assessment is being carried out in partnership with the state geologic surveys of West Virginia (WV), Pennsylvania (PA), Ohio (OH), and Maryland (MD). Comprehensive stratigraphic and geochemical databases have been developed for the Pittsburgh coal bed, and areal extent, mined areas, structure contour, isopach, overburden thickness maps of the bed have been released as United States Geological Survey (USGS) Open-File Reports. The resulting resource model indicates that of the original 34 billion short tons (31 billion tonnes) of Pittsburgh coal, 16 billion short tons (14 billion tonnes) remain. Although most of the remaining coal is thinner, deeper, and higher in ash and sulfur (S) than the original resource, there are blocks of extensive thick (6–8 ft or 1.8–2.4 m) coal in southwestern PA and the northern panhandle of WV.

The central and northern Appalachian Basin—a frontier region for coalbed methane development

The Appalachian basin is the world's second largest coalbed-methane (CBM) producing basin. It has nearly 4000 wells with 1996 annual production at 147.8 billion cubic feet (Bcf). Cumulative CBM production is close to 0.9 trillion cubic feet (Tcf). The Black Warrior Basin of Alabama in the southern Appalachian basin (including a very minor amount from the Cahaba coal field) accounts for about 75% of this annual production and about 75% of the wells, and the remainder comes from the central and northern Appalachian basin. The Southwest Virginia coal field accounts for about 95% of the production from the central and northern parts of the Appalachian basin. Production data and trends imply that several of the Appalachian basin states, except for Alabama and Virginia, are in their infancy with respect to CBM development. Total in-place CBM resources in the central and northern Appalachian basin have been variously estimated at 66 to 76 trillion cubic feet (Tcf), of which an estimated 14.55 Tcf (∼20%) is technically recoverable according to a 1995 U.S. Geological Survey assessment. For comparison in the Black Warrior basin of the 20 Tcf in-place CBM resources, 2.30 Tcf (∼12%) is technically recoverable. Because close to 0.9 Tcf of CBM has already been produced from the Black Warrior basin and the proved reserves are about 0.8 Tcf for 1996 [Energy Information Administration (EIA), 1997]. U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves, 1996 Annual Report. U.S. Department of Energy DOE/EIA-0216(96), 145 pp.], these data imply that the central and northern Appalachian basin could become increasingly important in the Appalachian basin CBM picture as CBM resources are depleted in the southern Appalachian basin (Black Warrior Basin and Cahaba Coal Field). CBM development in the Appalachian states could decrease the eastern U.S.A.'s dependence on coal for electricity. CBM is expected to provide over the next few decades a virtually untapped source of unconventional fossil fuel in the Appalachian states, where the CBM resources are large and the demand for cleaner fossil-fuel energy is high.

Production characteristics and reservoir analysis of coalbed methane reservoirs

Six Appalachian coalbed methane (CBM) projects are reviewed and evaluated in terms of reservoir engineering techniques and CBM recoverability. These include three non-mine-related projects in the northern Appalachian basin, one non-mine-related, and two mine-related projects in the central Appalachian basin of southwestern Virginia. Generally, low production rates and low CBM reserves are characteristic of the central and northern Appalachian basin; therefore, minimizing production costs is fundamental to the economic success of a CBM project in these regions. Well deliverability is determined through permeability testing and through production data analysis using a reservoir simulator to history match historic production data. All of the non-mine-related projects utilize vertical wells with well spacings of 60 to 100 acre (0.23–0.40 km 2) that produce from multiple coalbeds at depths as much as 762 m. The targets are coalbeds of the Pocahontas and New River Formations and correlative Lee Formation. In the Nora Field of Virginia (Equitable Resources, developer), well spacing is 60 acre (0.23 m 2), and recoverability is high (30–60% of initial gas in place). Well stimulation is by foam or water as the fracture medium. The average gas in place is 675 MMscf well −1, and the expected lifetime of the wells is 30 years. Cost of water disposal is a major economic factor in CBM development in the Appalachian basin. Water disposal is accomplished by using water disposal holes (injection wells) rather than surface water discharged, which is generally not permitted. Water disposal in the central Appalachian basin involves relatively low volumes of water (30 STB day −1, declining to 1 to 2 STB day −1). In the northern Appalachian basin in Indiana County, PA (Belden and Blake, developer), vertical CBM holes penetrate six to eight Allegheny Formation coalbeds. Water and a sand proppant are used for stimulation. Production levels are low (<100 Mcf day −1 well −1). The life of a vertical CBM hole drilled in advance of mining is 3 to 5 years. This type of hole may be converted to a gob hole after mining is completed. Gob gas is recovered mainly from coalbeds above the mined coalbed and has high recoverability of as much as 10 MMscf day −1 well −1. Horizontal CBM holes produce almost pure methane and typically have 1 year of production.

Relative importance of physical and economic factors in Appalachian coalbed gas assessment

In the 1995 National Assessment of Oil and Gas Resources prepared by the U.S. Geological Survey, only 20% of the assessed technically recoverable Appalachian Province coalbed gas resources were economic. Physical and economic variables are examined to explain the disparity between economic and technically recoverable coalbed gas. The Anticline and Syncline plays of the Northern Appalachian Basin, which account for 77% of the assessed technically recoverable coalbed gas, are not economic. Analysis shows marginal reductions in costs or rate of return will not turn these plays into commercial successes. Physical parameters that determine ultimate well recoverability and the rate of gas recovery are primary reasons the Northern Appalachian Basin plays are non-commercial. If the application of new well stimulation technology could offset slow gas desorption rates, Appalachian Province economic gas could increase to more then 70% of the technically recoverable gas. Similarly, if operators are able to develop strategies to selectively drill plays by avoiding dry holes and non-commercial occurrences, the economic fraction of technically recoverable gas could increase to over half.

Abstract: Pennsylvanian Lacustrine Limestones in Continental Cyclothems of the Northern Appalachian Basin

Abstract: Pennsylvanian Lacustrine Limestones in Continental Cyclothems of the Northern Appalachian Basin

Groundwater transformation of a low-sulfur to a high-sulfur coal, the Harlem coal of the northern Appalachian basin

The Harlem coal is postulated to have been deposited in raised-bog settings. It was initially deposited as low-sulfur peat, but groundwater of a later origin altered portions of it to high-sulfur coal. The total sulfur content of 172 samples from 31 locations on a moisture- and ash-free basis have a quadrimodal distribution with two major modes at 0.75% S and 2.0%S. Multiple sampling and analyses at specific mine sites indicate that the addition of sulfur of a later origin occurred either laterally adjacent to sandstone channels or vertically adjacent to faults. Significant sulfur addition also occurred above clay partings at these sites. The original low-sulfur nature is preserved where the coal bed is isolated from descending groundwater by a thick impervious layer. Trace-element analyses show high concentrations of mobile elements such as Na and Mn in the high-sulfur coals.

Pennsylvanian continental cyclothem development: no evidence of direct climatic control in the Upper Freeport Formation (Allegheny Group) of Pennsylvania (northern Appalachian Basin)

The occurrence of lacustrine carbonates in the Allegheny Group (upper Middle Pennsylvanian) continental cyclothems of the northern Appalachian Basin has been attributed to climatic alternation of wet (coal deposition) and dry (carbonate deposition) periods. However, we present evidence from facies associations, coal and carbonate petrography, and carbonate stable isotope geochemistry for a uniformly wet climate throughout deposition of one of the earliest continental cyclothems, the Upper Freeport Formation (UFF). We propose a depositional model comprising a large wetland complex drained by an anastomosed fluvial system containing a mosaic of channels, freshwater siliciclastic and carbonate lakes, and peat bogs/swamps on a siliciclastic floodplain. Carbonate phases represent bio-induced precipitates modified by lake dynamics, and not evaporative deposits. Absence of covariant isotopic trends between δ 18O and δ 13C and a relatively small range of δ 18O values (−1.9 to −6.4% PDB), that are close to or lighter than predicted paleoprecipitation for the Pennsylvanian equatorial regions, indicate hydrologically open, short residence time lake systems, in support of our sedimentary model. Combined sedimentologic and isotopic data do not indicate reduced effective moisture (precipitation-evaporation) during intervals of limestone deposition. The UFF lakes developed in a relatively wet climate zone without significant episodic closure due to climatically induced water deficit. Lithologic patterns within the UFF cyclothem are primarily attributed to the evolution of anastomosed fluvial systems controlled by subsidence in an active foreland basin rather than to short-term climatic change or eustacy.

The U.S. Geological Survey's National Coal Resource Assessment: The Northern and Central Appalachian Basin: ABSTRACT

The US Geological Survey (USGS) Energy Resource Surveys Program is currently conducting a five-year National Coal Resource Assessment project. Primary focus is on the quality and quantity of top-producing coal beds and coal zones in five of the nine major coal producing regions in the US. These regions include the (1) Northern and Central Appalachian Basin, (2) Gulf Coastal Plain, (3) Illinois Basin, (4) Colorado Plateau, and (5) Powder River Basin and Northern Great Plains.

Late Pennsylvanian climate changes and palynomorph extinctions

A major floral change occurs in the Upper Pennsylvanian strata in the Midcontinent, Illinois basin, and in the northern Appalachian basin of eastern United States. Lycospora spp. (derived from arborescent lycopsids) became extinct along with some other palynomorph taxa. This investigation is concerned with the importance of this major floral change. Samples were studied from western Pennsylvania, eastern Ohio, and West Virginia (from a previous study) cover the stratigraphic interval from the Upper Freeport coal bed, uppermost part of the Allegheny Formation, to the Mahoning, Mason, Brush Creek, Wilgus, and Anderson coal beds in the lower part of the Conemaugh Formation. The floral change occurs either at or below the accepted Desmoinesian-Missourian boundary in the Midcontinent and Illinois basin, whereas in the northern Appalachians this change occurs in the lower part of the Conemaugh Formation, between the Mahoning and Brush Creek coal beds, or when the Mason is present, between the Mahoning and Mason coal beds. With the advent of late Middle Pennsylvanian time, the climate began to change from wet tropical to seasonal tropical. The Middle-Upper Pennsylvanian boundary is the culmination of this drying trend, which was marked by reduction of available water. The peat swamps are interpreted as having changed from the domed type of bog to the planar type under these circumstances. Thus, in general, the coals of the Conemaugh Formation are characteristically much thinner than those of the Allegheny Formation. This was caused by a number of factors including reduced or more seasonal rainfall, decline of arborescent lycopsids, and the increased dominance of herbaceous and fern plants. As a result, there are fewer minable coal beds in the Conemaugh Formation. The first coal bed above the extinction of Lycospora spp. is dominated by the palynomorph taxon Endosporites globiformis which is derived from a heterosporous, herbaceous lycopsid. However, Sigillaria, another arborescent lycopsid, did not become extinct at this time as evidenced by the presence of the palynomorph genus Crassispora which is derived from Sigillaria. The reason for the survival of Sigillaria is not known, but it may have been able to adapt, in a limited fashion, to some sort of specialized microenvironment. The ferns, based on palynomorph occurrence, become numerically more important throughout the balance of the Conemaugh Formation, and dominate the Pittsburgh No. 8 and Pomeroy coal beds in the overlying Monogahela Formation.

Middle Devonian (Eifelian) Carbonates, Northern and Central Appalachian Basin: Sequence Stratigraphic Framework: ABSTRACT

Middle Devonian (Eifelian) Carbonates, Northern and Central Appalachian Basin: Sequence Stratigraphic Framework: ABSTRACT

Paleoshoreline patterns in the transgressive-regressive sequences of Pennsylvanian rocks in the northern Appalachian Basin, U.S.A.

Sheets of sponge spicule flint of Pennsylvanian age (Bashkirian, Moscovian, Kasimovian) that are present in the northern Appalachian Basin of Ohio and adjacent parts of Kentucky, Pennsylvania and West Virginia, are important indicators of paleoshorelines. This flint typically occurs with or occupies the position normally held by shallow-water limestone and contains a normal marine fauna. The flint was deposited above coal or underclay, representing the detritus-starved marine portion of a transgressive-regressive sequence and marking the eastern limit of transgression across a westward-spreading alluvial plain. Flint occurs at several stratigraphic positions in the upper Pottsville-lower Conemaugh interval. The most important are: Boggs, Upper Mercer and Kanawha flints of the upper Pottsville Group; Kilgore-Flint Ridge, Zaleski and Vanport flints of the lower Allegheny Group; and Brush Creek flint of the lower Conemaugh Group. Lithofacies maps of these beds were constructed to show the distribution of the flint. Limestone-hosted flint occurs in long discontinuous chains of sheetlike bodies, whereas shale-hosted flint occurs in single sheets with restricted geographic distribution. Chains of limestone-hosted flint attain maximum dimensions of a few meters in thickness, a few kilometers in width and several hundreds of kilometers in length. The Upper Mercer, Vanport and Brush Creek flints are particularly extensive, forming arcuate shoreline patterns that parallel the fronts of large delta systems. Beds of clay ironstone and/or coal above flint indicate that the lagoonal environment in which flint was deposited was followed closely by a change to stagnant waters. Cementation of flint with silica likely occurred under the lower pH conditions existing at that time and when depths of burial were shallow.

Geologic, fluid inclusion, and isotopic studies of the Findlay Arch District, northwestern Ohio

The Findlay Arch district is a cluster of noneconomic, carbonate-hosted mineral occurrences centered in northwestern Ohio. The principal host rocks are vuggy dolostones that range in age from Middle Silurian to Middle Devonian. Reef complexes, beds of nodular gypsum, collapse breccias, and fracture zones provided important stratigraphic and structural ore controls. The main-stage phases are brown, yellow, and purple fluorite, sphalerite, and galena. The sphalerite/galena ratios are 100 or higher. Early dolomite, pyrite-marcasite, and celestite I are premain-stage phases, whereas saddle dolomite, vug-filling calcite, celestite II, barite, and strontianite are postmain-stage phases.T h and T m measurements of fluid inclusions in fluorite and sphalerite indicate that these minerals were precipitated from a warm Na-Ca-Cl brine, likely derived from the northern Appalachian basin. The flow path is inferred from westward-diminishing salinity values that are documented in successive generations of inclusions. The dominant thermal trend was aregional temperature plateau that peaked at about 110 degrees C. Thermal and salinity data imply that the flow system developed during the Alleghenian orogeny when the burial depth of host rocks was at a maximum and when the brine was diluted isothermally as it migrated westward across the arch. Coexisting inclusions of oil and brine indicate that these fluids moved through the district together.Similar sulfur isotope compositions (-0.9 to +4.8 and -3.4 to +0.6ppm) in sphalerite and galena show that these sulfides are genetically related. These data generally agree with sulfur compositions of late Paleozoic seawater sulfate, which is consistent with an Alleghenian age for the Findlay arch sulfur source. Lead isotope compositions of galena (Haden, 1977) fall in the field of the Appalachian ores and diagenetic galena, indicating further that nonradiogenic Paleozoic sedimentary rocks to the east were the likely source of lead.Minerals in vugs lack a radiogenic component of strontium. Nevertheless, a basinal brine is required for the fluorite-sphalerite mineralization, because a rock capable of providing the salinity of the fluid inclusions was absent in the district. The strontium isotope composition of this brine apparently was reset, acquiring the signature of Salina gypsum of Upper Silurian age. A local source of strontium and sulfur is indicated for celestite I, because its S and Sr isotope compositions are nearly identical to those of the Salina anhydrite.Brown calcite in veins associated with the Bowling Green fault zone contains strontium that is slightly radiogenic relative to vug-filling calcite. This, along with the prehydrocarbon age of the brown calcite, indicates that these early veins and the fiuorite-sphalerite mineralization are not coeval.

Completion Methods in Coal-Seam Reservoirs

Summary Wells drilled to produce methane from coal seams are completed with either a perforated casing method, a stable cavity method, or an openhole method. The perforated casing method followed by hydraulic fracturing works best in most coalseam wells. In high-permeability, high-pressure coal seams, the stable cavity method may be preferred, To design the optimum completion, a completion engineer must consider the unique aspects of producing methane from coal. Introduction Methane produced from coal seams is an important energy source in the petroleum industry. The increased development of coal-seam reservoirs can be attributed to (1) U.S. income tax credit that is associated with producing coalbed methane, (2) Gas Research Inst. (GRI) research funding to improve technology, and (3) an increased awareness in the industry concerning the importance of coalbed methane. Geologic assessments of coalbed methane reservoirs have been funded by the U.S. DOE and the GRI. Currently, resource assessments are available on the Arcoma basin, Black Warrior basin, Cahaba and Coosa coal fields, Central Appalachian basin, Greater Green River coal region, Illinois basin, Northern Appalachian basin, Pennsylvania anthracite fields. Piceance basin, Powder River basin. Raton basin, Richmond and Deep River basins, San Juan basin, Uintah basin, Valley coal fields, Western Washington coal region, and the Wind River basin. On the basis of detailed studies of these coal areas, GRI estimates that 300 to 400 Tcf of gas in place is contained in the U.S. Table 1 contains the details concerning the gas in place for each basin. Most methane recoverable from coal seams will be in reservoirs that are less than 5,000 ft deep. The low-cost drilling associated with the shallow depths makes coalbed methane development suitable for independent producers. In addition, the need for large acreage positions and the technical challenges involved with producing gas from coal seams also provide incentives for big producing companies to pursue coalbed methane development actively. Because of these inducements, a wide variety of companies develop coalbed methane reservoirs. Several papers on completing wells in coalbed methane formations have been published. In 1980, Steidle et al. published a paper concerning completion techniques from vertical published a paper concerning completion techniques from vertical methane drainage boreholes in Virginia. Lambert et al., Logan et al., and Clark et al. have discussed specific completion problems in specific coalbed methane areas. Lambert et al. problems in specific coalbed methane areas. Lambert et al. discussed completion alternatives that have been evaluated in the Black Warrior basin. Logan et al. and Clark et al. discussed coal-seam well completions in the San Juan and Piceance basins. Much of the published information on coal seams has evolved through research projects sponsored by the GRI. The objective of this paper is to explain the various completion options that are available to an operator developing a coal-seam reservoir. On the basis of the unique properties of coal, the engineer must develop a completion strategy. The strategy should include specific details concerning the site of the perforations and the stimulation treatment needed to maximize gas perforations and the stimulation treatment needed to maximize gas recovery.