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J.L. Clayton

Publications and source records attributed to J.L. Clayton.

At least 19 recordsLinked to original sources
USGS2007

Stream ecosystem response to limestone treatment in acid impacted watersheds of the allegheny plateau

Restoration programs are expanding worldwide, but assessments of restoration effectiveness are rare. The objectives of our study were to assess current acid-precipitation remediation programs in streams of the Allegheny Plateau ecoregion of West Virginia (USA), identify specific attributes that could and could not be fully restored, and quantify temporal trends in ecosystem recovery. We sampled water chemistry, physical habitat, periphyton biomass, and benthic macroinvertebrate and fish community structure in three stream types: acidic (four streams), naturally circumneutral (eight streams), and acidic streams treated with limestone sand (eight streams). We observed no temporal trends in ecosystem recovery in treated streams despite sampling streams that ranged from 2 to 20 years since initial treatment. Our results indicated that the application of limestone sand to acidic streams was effective in fully recovering some characteristics, such as pH, alkalinity, Ca2+, Ca:H ratios, trout biomass and density, and trout reproductive success. However, recovery of many other characteristics was strongly dependent upon spatial proximity to treatment, and still others were never fully recovered. For example, limestone treatment did not restore dissolved aluminum concentrations, macroinvertebrate taxon richness, and total fish biomass to circumneutral reference conditions. Full recovery may not be occurring because treated streams continue to drain acidic watersheds and remain isolated in a network of acidic streams. We propose a revised stream restoration plan for the Allegheny Plateau that includes restoring stream ecosystems as connected networks rather than isolated reaches and recognizes that full recovery of acidified watersheds may not be possible. ?? 2007 by the Ecological Society of America.

Ecological Applications↗
USGS2003

A stable carbon isotope and biological marker study of Polish bituminous coals and carbonaceous shales

Biological marker and carbon isotopic compositions of coals and carbonaceous shales from the Upper Carboniferous strata of the Upper Silesian (USCB), Lower Silesian (LSCB), and Lublin (LCB) coal basins were determined to assess depositional conditions and sources of the organic matter. n-Alkane, sterane, and isoprenoid distribution, and carbon isotope ratios are consistent with an origin from higher plants. In some cases, pristane/phytane (Pr/Ph) ratios of carbonaceous shales (roof and floor shales) are < 1.0, while the associated coals have high ratios (??? 1.0). This suggests that reducing conditions prevailed during deposition of the shales, but a period of oxidizing conditions accompanied deposition of the coals. Steranes present in coal extracts are dominated by the 14??(H)17??(H)20R C29 stereoisomers, typical, but not conclusive, of higher plant origin. Carbonaceous shales exhibit a wider range of sterane composition, suggesting local, significant input of algal organic matter. Significant amounts of benzohopanes and gammacerane are present in some coals. Although benzohopanes are present at least in small amounts in samples from many different environments, they have been reported to occur most commonly in marine environments. The present study seems to provide the first example where benzohopanes have been reported in significant amounts in terrestrial organic matter. Gammacerane is abundant in rocks or sediments deposited in carbonate or highly saline marine environments. The finding of high gammacerane concentrations in the coals expands the depositional settings in which it has been observed and questions its utility as an independent indicator of hypersaline carbonate environments. Stable carbon isotope composition of coals, and type III kerogen in carbonaceous shales as well as correlation of stable carbon isotope composition of saturated and aromatic hydrocarbons in carbonaceous shales from both the USCB and the LSCB indicate terrigenous origin. Bitumens are always co-genetic with associated coals and kerogens. Isotopic data reveal that Sofer's genetic classification of oils is not applicable to organic matter in coals. ?? 2003 Elsevier B.V. All rights reserved.

International Journal of Coal Geology↗
USGS2002

Controls on porphyrin concentrations of Pennsylvanian organic-rich shales, Western U.S.A.

Organic-rich black shales of Middle Pennsylvanian (Desmoinesian) age occur over much of the central U.S. and as far west as the northern Denver and southeastern Powder River basins. Total organic carbon contents (Corg) are commonly greater than 10 wt %. Porphyrin concentrations (vanadyl + nickel) are as high as 40000 ppm relative to extractable bitumen. In bulk, the organic matter contained in the shales is mostly type II and III (Rock-Eval hydrogen indexes 200-400 mg of hydrocarbons/g of Corg). The finding of high porphyrin concentrations in type III organic matter is unusual but can be explained by a depositional model wherein high preservation of primary organic production (water column photosynthesis) is combined with substantial input of allochthonous organic matter. The allochthonous organic matter (low porphyrin concentration) may come from erosion during advance of the sea across the area or from fluvial transport from shore.

Energy & Fuels↗
USGS2002

Assessment of hydrocarbon source rock potential of Polish bituminous coals and carbonaceous shales

We analyzed 40 coal samples and 45 carbonaceous shale samples of varying thermal maturity (vitrinite reflectance 0.59% to 4.28%) from the Upper Carboniferous coal-bearing strata of the Upper Silesian, Lower Silesian, and Lublin basins, Poland, to evaluate their potential for generation and expulsion of gaseous and liquid hydrocarbons. We evaluated source rock potential based on Rock-Eval pyrolysis yield, elemental composition (atomic H/C and O/C), and solvent extraction yields of bitumen. An attempt was made to relate maceral composition to these source rock parameters and to composition of the organic matter and likely biological precursors. A few carbonaceous shale samples contain sufficient generation potential (pyrolysis assay and elemental composition) to be considered potential source rocks, although the extractable hydrocarbon and bitumen yields are lower than those reported in previous studies for effective Type III source rocks. Most samples analysed contain insufficient capacity for generation of hydrocarbons to reach thresholds required for expulsion (primary migration) to occur. In view of these findings, it is improbable that any of the coals or carbonaceous shales at the sites sampled in our study would be capable of expelling commercial amounts of oil. Inasmuch as a few samples contained sufficient generation capacity to be considered potential source rocks, it is possible that some locations or stratigraphic zones within the coals and shales could have favourable potential, but could not be clearly delimited with the number of samples analysed in our study. Because of their high heteroatomic content and high amount of asphaltenes, the bitumens contained in the coals are less capable of generating hydrocarbons even under optimal thermal conditions than their counterpart bitumens in the shales which have a lower heteroatomic content. Published by Elsevier Science B.V.

Chemical Geology↗
USGS1998

2,3,6-/3,4,5-Trimethyl substituted diaryl carotenoid derivatives (Chlorobiaceae) in petroleums of the Belarussian Pripyat River Basin

Degradation products of the 2,3,6-/3,4,5-trimethyl substituted analog of isorenieratene were characterized in Belarussian petroleums. Devonian oils of low maturity were found to contain high concentrations (e.g., 35 mg/g) of C40 diaryl isoprenoids (2,3,6-/3,4,5-trimethyl substitution) along with an abundance of maturation-related compounds. A maturation scheme for diaryl carotenoid (2,3,6-/3,4,5-trimethyl substitution) precursors was proposed. Diaryl isoprenoids and aryl isoprenoid (2,3,6- and 3,4,5-trimethyl substitutions) contents were found to decrease as a function of maturity. Maturity parameters based on (i) the ratio of two specific C15 aryl isoprenoids and (ii) the ratio of C15 (2,3,6) aryl isoprenoids to C40 diaryl isoprenoids (2,3,6-/3,4,5) were proposed.Degradation products of the 2,3,6-/3,4,5-trimethyl substituted analog of isorenieratene were characterized in Belarussian petroleums. Devonian oils of low maturity were found to contain high concentrations (e.g., 35 mg/g) of C40 diaryl isoprenoids (2,3,6-/3,4,5-trimethyl substitution) along with an abundance of maturation-related compounds. A maturation scheme for diaryl carotenoid (2,3,6-/3,4,5-trimethyl substitution) precursors was proposed. Diaryl isoprenoids and aryl isoprenoid (2,3,6- and 3,4,5-trimethyl substitutions) contents were found to decrease as a function of maturity. Maturity parameters based on (i) the ratio of two specific C15 aryl isoprenoids and (ii) the ratio of C15 (2,3,6) aryl isoprenoids to C40 diaryl isoprenoids (2,3,6-/3,4,5) were proposed.

Conference Paper↗
USGS1998

Geochemistry of coalbed gas - a review

Coals are both sources and reservoirs of large amounts of gas that has received increasing attention in recent years as a largely untapped potential energy resource. Coal mining operations, such as ventilation of coalbed gas from underground mines, release coalbed CH4 into the atmosphere, an important greehouse gas whose concentration in the atmosphere is increasing. Because of these energy and environmental issues, increased research attention has been focused on the geochemistry of coalbed gas in recent years. This paper presents a summary review of the main aspects of coalbed gas geochemistry and current research advances.Coals are both sources and reservoirs of large amounts of gas that has received increasing attention in recent years as a largely untapped potential energy resource. Coal mining operations, such as ventilation of coalbed gas from underground mines, release coalbed CH4 into the atmosphere, an important greenhouse gas whose concentration in the atmosphere is increasing. Because of these energy and environmental issues, increased research attention has been focused on the geochemistry of coalbed gas in recent years. This paper presents a summary review of the main aspects of coalbed gas geochemistry and current research advances.

International Journal of Coal Geology↗
USGS1997

Geochemistry of oils from the Junggar basin, northwest China

The Junggar basin of northwestern China is a structural basin containing a thick sequence of Paleozoic-Pleistocene rocks with estimated oil reserves of as much as 5 billion bbl. Analyses of 19 oil samples from nine producing fields and two oil-stained cores in the Junggar basin revealed the presence of at least five genetic oil types. The geochemistry of the oils indicates source organic matter deposited in fresh to brackish lake and marine environments, including coaly organic matter sources. The volumetrically most important oil type discovered to date is produced from Late Carboniferous-Middle Triassic reservoirs in the giant Karamay field and nearby fields located along the northwestern margin of the Junggar basin. Oil produced from the Mahu field, located downdip in a depression east of the Karamay field, is from a different source than Karamay oils. Unique oil types are also produced from an upper Permian reservoir at Jimusar field in the southeastern part of the basin, and from Tertiary (Oligocene) rocks at Dushanzi field and Lower Jurassic rocks at Qigu field, both located along the southern margin of the basin. Previous studies have demonstrated the presence of Upper Permian source rocks, and the possibility of Mesozoic or Tertiary sources has been proposed, but not tested by geochemical analysis, although analyses of some possible Jurassic coal source rocks have been reported. Our findings indicate that several effective source rocks are present in the basin, including local sources of Mesozoic or younger age for oil accumulations along the southern and southeastern margins of the basin. Future exploration or assessment of petroleum potential of the basin can be improved by considering the geological relationships among oil types, possible oil source rocks, and reservoirs.

Junggar Basin↗
USGS1997

Geology, thermal maturation, and source rock geochemistry in a volcanic covered basin: San Juan sag, south-central Colorado

The San Juan sag, concealed by the vast San Juan volcanic field of south-central Colorado, has only recently benefited from oil and gas wildcat drilling and evaluations. Sound geochemical analyses and maturation modeling are essential elements for successful exploration and development. Oil has been produced in minor quantities from an Oligocene sill in the Mancos Shale within the sag, and major oil and gas production occurs from stratigraphically equivalent rocks in the San Juan basin to the southwest and in the Denver basin to the northeast.

Colorado↗
USGS1996

Structure, stratigraphy, and petroleum geology of the Little Plain basin, northwestern Hungary

The basement of the Little Plain (Kisalfold) basin is composed of two parts: an eastern part comprised of folded and overthrusted Triassic and Paleozoic rocks of the Pelso block (Transdanubian Central Range) compressed in the Early Cretaceous, and a western part consisting of stacked nappes of the Austroalpine zone of Paleozoic rocks, significantly metamorphosed during Cretaceous and later compression, overriding Jurassic oceanic rift-zone rocks of the Penninic zone. The evolution of the basin began in the late Karpatian-early Badenian (middle Miocene) when the eastern part of the basin began to open along conjugate sets of northeast- and northwest-trending normal faults. Neogene rocks in the study area, on the average, contain less than 0.5 wt. % total organic carbon (TOC) and, therefore, are not considered effective source rocks. Locally, however, where TOC values are as high as 3 wt. %, significant amounts of gas may have been generated and expelled. Although potential stratigraphic traps are numerous in the Neogene section, these potential traps must be downgraded because of the small amount of hydrocarbons discovered in structural traps to date. With the exception of the Cretaceous, the Mesozoic section has not been actively explored. Large anticlinal and overthrust structures involving pre-Cretaceous strata remain undrilled.

Little Plain basin↗
USGS1992

Extraction of whole versus ground source rocks: Fundamental petroleum geochemical implications including oil-source rock correlation

In petroleum geochemistry, extractable hydrocarbons (HCs) in source rocks have typically been studied by grinding the rock to a fine powder (≤100 mesh) and then extracting the HCs from the rock with a solvent. This procedure carries the implicit assumption that the HCs are homogeneously distributed throughout the rock. However, sequential Soxhlet extractions of whole (unpowdered) source rocks have shown that progressive extracts from the same rock can be quite different and may not even correlate with each other. A crude oil-like material clearly has been fractionated from indigenous bitumen in these rocks, has moved to cracks and parting laminae in the rocks, is ready for expulsion from the rocks, and is thus most accessible to the first extracting solvents. This process, which we believe is largely due to HC gases and carbon dioxide generated over all maturation ranks in source rocks, carries petroleum geochemical implications of a fundamental nature for oil-source rock correlations and gives insight into primary migration mechanisms, origin of oil deposits, and use of maturity and organic-facies indices.

Geochimica et Cosmochimica Acta↗
USGS1991

Oil-generating coals of the San Juan Basin, New Mexico and Colorado, U.S.A.

Coal beds of the Upper Cretaceous Fruitland Formation in the San Juan Basin of northwestern New Mexico and southwestern Colorado have significant liquid hydrocarbon generation potential as indicated by typical Rock-Eval Hydrogen Indexes in the range of 200–400 mg hydrocarbon/g organic carbon (type II and III organic matter). Small, non-commercial quantities of oil have been produced from the coal beds at several locations. The oils are characterized by high pristane/phytane ( ca 4) and pristane/ n -C 17 ratios ( ca 1.2), abundant C 21+ alkanes in the C 10+ fraction with a slight predominance of odd carbon-numbered n -alkanes, abundant branched-chain alkanes in the C 15+ region, and a predominance of methylcyclohexane in the C 4 -C 10 fraction. The oils are indigenous to the Fruitland Formation coals and probably migrated at thermal maturities corresponding to vitrinite reflectance values in the range 0.7–0.8%. Although the oils found to date are not present in commercial amounts, these findings illustrate the potential of some coals to generate and expel oil under conditions of moderate thermal heating.

Colorado, New Mexico↗
USGS1990

Origin and migration of hydrocarbon gases and carbon dioxide, Bekes Basin, southeastern Hungary

The Békés Basin is a sub-basin within the Pannonian Basin, containing about 7000 m of post-Cretaceous sedimentary rocks. Natural gases are produced from reservoirs (Precambrian to Tertiary in age) located on structural highs around the margins of the basin. Gas composition and stable carbon isotopic data indicate that most of the flammable gases were derived from humic kerogen contained in source rocks located in the deep basin. The depth of gas generation and vertical migration distances were estimated using quantitative source rock maturity-carbon isotope relationships for methane compared to known Neogene source rock maturity-depth relationships in the basin. These calculations indicate that as much as 3500 m of vertical migration has occured in some cases. Isotopically heavy (> − 7 > 0 ) CO 2 is the predominant species present in some shallow reservoirs located on basin-margin structural highs and has probably been derived via long-distance vertical and lateral migration from thermal decompositon of carbonate minerals in Mesozoic and older rocks in the deepest parts of the basin. A few shallow reservoirs (< 2000m) contain isotopically light (−50 to −60% 0 ) methane with only minor amounts of C 2+ homologs (< 3% v/v). This methane is probably mostly microbial in origin. Above-normal pressures, occuring at depths greater than 1800 m, are believed to be the principal driving force for lateral and vertical gas migration. These pressures are caused in part by active hydrocarbon generation, undercompaction, and thermal decomposition of carbonates.

Bekes Basin↗
USGS1989

Characterization of coal-derived hydrocarbons and source-rock potential of coal beds, San Juan Basin, New Mexico and Colorado, U.S.A.

Coal beds are considered to be a major source of nonassociated gas in the Rocky Mountain basins of the United States. In the San Juan basin of northwestern New Mexico and southwestern Colorado, significant quantities of natural gas are being produced from coal beds of the Upper Cretaceous Fruitland Formation and from adjacent sandstone reservoirs. Analysis of gas samples from the various gas-producing intervals provided a means of determining their origin and of evaluating coal beds as source rocks. The rank of coal beds in the Fruitland Formation in the central part of the San Juan basin, where major gas production occurs, increases to the northeast and ranges from high-volatile B bituminous coal to medium-volatile bituminous coal ( R m values range from 0.70 to 1.45%). On the basis of chemical, isotopic and coal-rank data, the gases are interpreted to be thermogenic. Gases from the coal beds show little isotopic variation ( δ 13 C 1 values range −43.6 to −40.5 ppt), are chemically dry (C 1 /C 1–5 values are > 0.99), and contain significant amounts of CO 2 (as much as 6%). These gases are interpreted to have resulted from devolatilization of the humic-type bituminous coal that is composed mainly of vitrinite. The primary products of this process are CH 4 , CO 2 and H 2 O. The coal-generated, methane-rich gas is usually contained in the coal beds of the Fruitland Formation, and has not been expelled and has not migrated into the adjacent sandstone reservoirs. In addition, the coal-bed reservoirs produce a distinctive bicarbonate-type connate water and have higher reservoir pressures than adjacent sandstones. The combination of these factors indicates that coal beds are a closed reservoir system created by the gases, waters, and associated pressures in the micropore coal structure. In contrast, gases produced from overlying sandstones in the Fruitland Formation and underlying Pictured Cliffs Sandstone have a wider range of isotopic values ( δ 13 C 1 values range from −43.5 to −38.5 ppt), are chemically wetter (C 1 /C 1–5 values range from 0.85 to 0.95), and contain less CO 2 (< 2%). These gases are interpreted to have been derived from type III kerogen dispersed in marine shales of the underlying Lewis Shale and nonmarine shales of the Fruitland Formation. In the underlying Upper Cretaceous Dakota Sandstone and Tocito Sandstone Lentil of the Mancos Shale, another gas type is produced. This gas is associated with oil at intermediate stages of thermal maturity and is isotopically lighter and chemically wetter at the intermediate stage of thermal maturity as compared with gases derived from dispersed type III kerogen and coal; this gas type is interpreted to have been generated from type II kerogen. Organic matter contained in coal beds and carbonaceous shales of the Fruitland Formation has hydrogen indexes from Rock-Eval pyrolysis between 100 and 350, and atomic H:C ratios between 0.8 and 1.2. Oxygen indexes and atomic O:C values are less than 24 and 0.3, respectively. Extractable hydrocarbon yields are as high as 7,000 ppm. These values indicate that the coal beds and carbonaceous shales have good potential for the generation of liquid hydrocarbons. Voids in the coal filled with a fluorescent material that is probably bitumen is evidence that liquid hydrocarbon generation has taken place. Preliminary oil-source rock correlations based on gas chromatography and stable carbon isotope ratios of C 15+ hydrocarbons indicate that the coals and (or) carbonaceous shales in the Fruitland Formation may be the source of minor amounts of condensate produced from the coal beds at relatively low levelsof thermal maturity ( R m =0.7).

International Journal of Coal Geology↗
USGS1989

Geochemical evidence for Paleozoic oil in Lower Cretaceous O Sandstone, northern Denver basin

Organic geochemical properties of the oil produced from the Lower Cretaceous O sandstone on the eastern flank of the Denver basin indicate that this oil has been derived from a different source rock than other Cretaceous oils in the basin. O sandstone oil is characterized by low pristane/phytane ratio, high isoprenoid/n-alkane ratios, high asphaltene content, high sulfur content, and slight predominance of even-carbon numbered n-alkanes in the C 25+ fraction. These features are evidence of a Paleozoic source and indicate a carbonate rock is the likely source. Preliminary source rock evaluation and correlation data suggest that calcareous black shales and marls of Middle Pennsylvanian (Desmoinesian) age are the source of the O sandstone oil. This is the first rep rted occurrence of oil from Paleozoic source rocks in a Cretaceous reservoir in the Denver basin. Two important implications for further exploration are evident if vertical migration from Paleozoic source rocks has occurred. First, Paleozoic rocks of Middle Pennsylvanian age or younger are potential exploration objectives where reservoirs and suitable trapping mechanisms are present. Second, future exploration for oil in the O sandstone and upper Paleozoic rocks should consider stratigraphic relationships between possible source and reservoir rocks and possible migration conduits.

Colorado↗