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Paul C. Hackley

Publications and source records attributed to Paul C. Hackley.

At least 109 records · Page 6Linked to original sources
USGS2017

Organic petrology of peak oil maturity Triassic Yanchang Formation lacustrine mudrocks, Ordos Basin, China

An organic petrology evaluation and a determination of solid bitumen reflectance BR o "> BR o were completed for organic-rich Triassic Yanchang Formation mudrocks ( n = 15 "> n = 15 ) from the Ordos Basin, north-central China, as part of a larger investigation of “shale gas” resources. These data were integrated with information from Rock-Eval programmed pyrolysis to show that the samples are in the peak oil window of thermal maturity and that organic matter is dominated by solid bitumen with minor amounts of type III kerogen (vitrinite and inertinite) from vascular land plants. Describing a “kerogen type” for these rocks based strictly on parameters determined from programmed pyrolysis is misleading because the original organic matter has converted to hydrocarbons (present as solid bitumen), a large proportion of which may have been expelled into adjacent reservoir facies. However, based on the comparison with immature-early mature lacustrine mudrock (Garden Gulch Member of Green River Formation) and marine shale (Boquillas Formation), we suggest that the original organic matter in the organic-rich samples examined for our study may have been type I/II kerogen with hydrogen index values of > 700    mg   HC / g "> > 700 mg HC / g TOC.

Ordos basin↗
USGS2017

Liquid hydrocarbon characterization of the lacustrine Yanchang Formation, Ordos Basin, China: Organic-matter source variation and thermal maturity

Source-rock samples from the Upper Triassic Yanchang Formation in the Ordos Basin of China were geochemically characterized to determine variations in depositional environments, organic-matter (OM) source, and thermal maturity. Total organic carbon (TOC) content varies from 4 wt% to 10 wt% in the Chang 7, Chang 8, and Chang 9 members — the three OM-rich shale intervals. The Chang 7 has the highest TOC and hydrogen index values, and it is considered the best source rock in the formation. Geochemical evidence indicates that the main sources of OM in the Yanchang Formation are freshwater lacustrine phytoplanktons, aquatic macrophytes, aquatic organisms, and land plants deposited under a weakly reducing to suboxic depositional environment. The elevated C 29 "> C 29 sterane concentration and depleted δ C 13 "> δ 13 C values of OM in the middle of the Chang 7 may indicate the presence of freshwater cyanobacteria blooms that corresponds to a period of maximum lake expansion. The OM deposited in deeper parts of the lake is dominated by oil-prone type I or type II kerogen or a mixture of both. The OM deposited in shallower settings is characterized by increased terrestrial input with a mixture of types II and III kerogen. These source rocks are in the oil window, with maturity increasing with burial depth. The measured solid-bitumen reflectance and calculated vitrinite reflectance from the temperature at maximum release of hydrocarbons occurs during Rock-Eval pyrolysis ( T max "> T max ) and the methylphenanthrene index (MPI-1) chemical maturity parameters range from 0.8 to 1.05 % R o "> 1.05 % R o . Because the thermal labilities of OM are associated with the kerogen type, the required thermal stress for oil generation from types I and II mixed kerogen has a higher and narrower range of temperature for hydrocarbon generation than that of OM dominated by type II kerogen or types II and III mixed kerogen deposited in the prodelta and delta front.

Ordos basin↗
USGS2017

Controls on pore types and pore-size distribution in the Upper Triassic Yanchang Formation, Ordos Basin, China: Implications for pore-evolution models of lacustrine mudrocks

Our main objectives are to (1) learn if pore-evolution models developed from marine mudrocks can be directly applied to lacustrine mudrocks, (2) investigate what controls the different pore types and sizes of Chang 7 organic matter (OM)-rich argillaceous mudstones of the Upper Triassic Yanchang Formation, and (3) describe the texture, fabric, mineralogy, and thermal maturity variation in the Chang 7 mudstones. Lacustrine mudstones from nine cored wells along a depositional dip in the southeastern Ordos Basin, China, were investigated. Helium porosimetry, nitrogen adsorption, and field-emission scanning electron microscopy of Ar-ion milled samples were applied. Measured average total porosity of samples from a proximal to distal transect ( ϕ = 5.0 % "> ϕ = 5.0 % ) is higher than those from the two adjacent cored wells ( ϕ = 2.3 % "> ϕ = 2.3 % ). This difference in porosity partly caused by differences in the clay mineral content implies that in the fluvial-deltaic-lacustrine depositional environment, reservoir quality can vary significantly in a short distance. Owing to the uneven distribution of the sample set from proximal to distal area, we mainly evaluate variations in the proximal setting. Results from nitrogen-gas adsorption experiments show that there are four distinct patterns of pore-size distribution within the Chang 7 member of the Yanchang Formation with no particular correlation with mineralogical composition and thermal maturity. The pore network within Chang 7 mudstones is dominated by OM-hosted pores, with a lesser abundance of interparticle and intraparticle pores. The size distribution of mineral-hosted pores within these mudstones is found to be closely related to the rock texture (sorting and grain size) and fabric. Mudstones with well-sorted grains and a higher percentage of coarser grains have more abundant mineral pores. The sizes of OM-hosted pores in these compaction-dominated lacustrine mudstones were one to two orders of magnitude smaller than those in the marine mudstones that display abundant early cementation.

Ordos basin↗
USGS2017

Analysis of artificially matured shales with confocal laser scanning raman microscopy: Applications to organic matter characterization

Raman spectroscopy has been suggested as a method for characterizing the thermal maturity of rocks. The literature contains many empirical correlations between thermal maturity proxies, such as vitrinite reflectance (V Ro ) and pyrolysis-T max , with spectral metrics such as Raman peak-widths, peak-center positions, peak-areas and all manner of differences and ratios of these parameters. However, while these correlations may be convincing for small data sets from limited sample series, broader application of these metrics to disparate and heterogeneous samples proves difficult and there remains no consensus. In this extended abstract, Raman spectroscopy is introduced and the history of Raman analysis of carbonaceous material is briefly outlined, highlighting some of the latent difficulties and potential sources of bias. We suggest the organization of a community working group to establish terminology, guidelines, procedures and standards necessary for the successful development of this technique to characterize organic matter in an accessible, unbiased, and reproducible manner. For the present multi-phase study, immature shale samples from the Bakken and Duvernay formations were subjected to hydrous pyrolysis for 72 hours at temperatures from 280°C to 360°C. Rock residues were mounted and polished for analysis via confocal laser-scanning Raman microscopy and reflectance. The maturation series from the Bakken was randomized for the Phase-I single-blind study to be presented at this conference. For the Phase-II study, solid bitumen reflectance (B Ro ) values for the Duvernay series will be known. Multiple hyperspectral maps were collected from each Bakken sample, with each map consisting of a single diffraction-limited spot-size spectrum per 1 µm 2 in rectangular areas several hundred micrometers on a side. Initial attempts at using basic spectral metrics on small numbers of hand-selected spectra to sort the blind series produced inconclusive results: any number of possible correlations could be found. In an improved approach, the statistics of the full spectral datasets were leveraged to: 1) objectively identify organic carbon types (OCTs) in a given map based on Raman and fluorescence spectral characteristics, 2) identify those OCTs in other maps from the same sample and determine if the heterogeneity of the sample has been adequately characterized, and 3) identify the same OCTs in maps from other samples in the maturation series. In ongoing work, our goals are to: 1) use these analyses of the blind series to develop a hypothesis for a correlation to maturation, 2) test the hypothesis by applying the same analyses to the known Duvernay series (in Phase-II), 3) if necessary refine the hypothesis based on observations from the Duvernay analysis, and 4) finally reveal the true order of the Bakken series to verify if the hypothesized correlation accurately predicts the maturity order of the samples. In this document, we share progress to date. The analysis of one area of interest is detailed showing the differentiation of two OCTs based on Raman and fluorescence spectral features, including the use of 2-factor histograms, Principle Components Analysis (PCA), and Nonlinear Iterative Peak Fitting (NIPF).

Conference Paper↗
USGS2017

Application of organic petrology in high maturity shale gas systems

Application of incident light microscopy techniques for organic petrology in high temperature thermogenic shale gas systems demonstrates that solid bitumen is the dominant organic matter. Solid bitumen is retained as a residual conversion product as oil-prone kerogen cracks to hydrocarbons or occurs from the cracking of once liquid oil. Oil-prone Type I/II kerogens are not present in shale gas reservoirs, already having converted to hydrocarbons. Type III/IV kerogens (vitrinite and inertinite) are refractory and persist in shale gas reservoirs to high maturity with little morphological change apart from condensation and aromatization causing higher reflectance. Organic petrology applications are most useful for thermal maturity determination and delineation of hydrocarbon windows through measurement of vitrinite reflectance and vitrinite reflectance equivalents from other organic matter (zooclasts and/or solid bitumen). Depositional organo-facies determination generally is not possible in the gas window of thermal maturity; fluorescence microscopy is not useful as organic matter is no longer autofluorescent. Application of scanning electron microscopy (SEM) allows observation of an interconnected nano-scale organic porosity in shale gas systems but suffers from inability to identify organic matter types. SEM approaches to shale gas reservoir characterization therefore should not attempt differentiation of kerogen types or kerogen vs. solid bitumen identification unless correlative organic microscopy is performed. Herein are reviewed organic petrology results as used in the shale gas systems of North America, Europe and China, including SEM applications, citing recent examples from the literature.

Book chapter↗
USGS2017

Final data report for factors controlling DDE dechlorination rates on the Palos Verdes Shelf: A field and laboratory investigation

This data report provides a compilation of information developed over the last 6+ years by a multi-disciplinary, multi-institutional research team. The overall goal of this work has been to identify the biological, chemical, and physical factors that control rates of reductive dechlorination of DDE and DDMU in sediments of the Palos Verdes Shelf (PVS). More specific questions and objectives are delineated in the Scope of Work (section 12.1., Appendix 1). The study was composed of two parts: 1) field characterization studies, and 2) laboratory microcosm experiments. The goal of the field characterization studies was to define the conditions under which reductive dechlorination of DDE (and DDMU) is occurring in PVS sediments. This involved two separate cruises (2009, 2010) during which sediment cores, bottom water and other real-time field measurements (e.g., conductivity, temperature, depth of the water column) were acquired. The sediment cores were distributed among research team members for detailed chemical (R. Eganhouse, B. Orem, M. Reinhard), microbiological (A. Spormann), and physical (B. Edwards) analysis as well as for laboratory microcosm experiments (M. Reinhard). A team of collaborating USGS scientists generously contributed valuable information pertaining to geochronology (P. Swarzenski), the character of sedimentary geosorbent phases (P. Hackley), mineralogy (D. Webster), and grain-size characteristics (C. Sherwood) of PVS sediment samples. Together, this information will serve as framework for a conceptual model of natural degradation processes in the DDT-contaminated sediments on the PVS. These findings will enable the USEPA to gain a better understanding of the controls on reductive dechlorination and how dechlorination rates vary spatially and temporally. This, in turn, should facilitate decision making concerning the progress of natural attenuation and when monitoring at the site can be terminated. Toward that end, a brief Synthesis Report, summarizing and interpreting the acquired data, is being prepared and will be released in the coming year.

Palos Verdes Shelf↗
USGS2017

Geologic characterization of the hydrocarbon resource potential of the Upper Cretaceous Tuscaloosa marine shale in Mississippi and Louisiana, U.S.A.

Recent oil production from the Upper Cretaceous Tuscaloosa marine shale (TMS) has elevated the formation, previously assessed by the USGS in 2011 as part of the Eagle Ford Group, to its own distinct assessment unit for an upcoming assessment. Geologic characterization in preparation for the 2017 assessment has included the analysis of rock samples and produced oils, and the interpretation of well logs and biostratigraphic data. Results include new mapped extents of the reservoir, which reaches a maximum thickness of almost 500 feet in southern Mississippi and central Louisiana, and geochemical interpretations which support a self-sourced origin for high gravity (36-48 API) low sulfur oil. Programmed pyrolysis and petrography indicate the TMS contains dominantly Type III gas-prone kerogen with some Type II oil-prone kerogen present in the most organic-rich samples. TMS samples contain an average of 47 weight percent total clays, had organic carbon content which ranged from 0.14 to 4.0 weight percent, and had a thermal maturity of 0.57 to 0.99 percent vitrinite reflectance in the productive area. These characteristics were the same for the TMS within an area defined as a “high resistivity zone” and outside of it. These results will be integral to the planned USGS assessment of the TMS.

Conference Paper↗
USGS2016

Organic petrology and geochemistry of mudrocks from the lacustrine Lucaogou Formation, Santanghu Basin, northwest China: Application to lake basin evolution

Exploration for tight oil in the frontier Santanghu Basin of northwest China has resulted in recent commercial discoveries sourced from the lacustrine Upper Permian Lucaogou Formation, already considered a “world class source rock” in the Junggar Basin to the west. Here we apply an integrated analytical program to carbonate-dominated mudrocks from the Lucaogou Formation in Santanghu Basin to document the nature of organic matter (OM) in the context of an evolving lake system. The organic-rich samples (TOC 2.8–11.4 wt%; n = 10) were widely spaced from an ~ 200 m cored section, interpreted from textural and mineralogical evidence to document transition from a lower under-filled to an overlying balanced-filled lake. Organic matter is dominated by moderate to strongly fluorescent amorphous material with Type I geochemical signature (HI values 510–755; n = 10) occurring in a continuum from lamellar stringers, 10–20 μm thick, some ≥ 1 mm in length (possible microbial mat; preserved only in lower under-filled section) to finely-disseminated amorphous groundmass intimately intermixed with mineral matrix. Biomarkers for methanotrophs and photosynthetic cyanobacteria indicate a complex microbial consortium. A unicellular prasinophyte green alga(?), similar to Tasmanites in marine rocks, is present as discrete flattened discs 50–100 μm in diameter. Type III OM including vitrinite (some fluorescent) and inertinite also is abundant. Solid bitumen, indicating local kerogen conversion, fills voids and occurs throughout the cored section. Vitrinite reflectance values are 0.47–0.58%, consistent with strong OM fluorescence but may be “suppressed”. Other proxies, e.g., biomarker parameters, indicate the Lucaogou Formation is in the early oil window at this location. On average, slightly more amorphous OM and telalginite are present in the lower section, consistent with a shallow, stratified, saline environment with low sediment dilution. More inertinite is present in the upper section, indicating greater terrestrial influx and consistent with higher quartz and plagioclase content (dominantly authigenic chalcedony and albite). Laminated mudstones in the upper section indicate anoxia prevented bioturbation from benthic grazing, also indicating stratified water column conditions. A decrease upsection in authigenic dolomite with reciprocal increase of ankerite/siderite is consistent with decreasing salinity, as is an overall decrease in gammacerane index values. These observations suggest evolution from a shallow, stratified evaporative (saline) setting to a deeper, stratified freshwater basin with higher water input during Lucaogou deposition. The evolution from an under-filled to balance-filled lake in Santanghu Basin is similar to Lucaogou deposition in Junggar Basin, suggesting similar tectonic and climatic controls. Paleoclimate interpretations from other researchers in this area suggested an evolution from semi-arid to humid conditions during the Roadian; we interpret that the evolution from an under-filled to balanced-filled lake seen in our data is in response to climate change, and may represent increased groundwater delivery to the Santanghu Basin.

International Journal of Coal Geology↗
USGS2016

Application of organic petrography in North American shale petroleum systems: A review

Organic petrography via incident light microscopy has broad application to shale petroleum systems, including delineation of thermal maturity windows and determination of organo-facies. Incident light microscopy allows practitioners the ability to identify various types of organic components and demonstrates that solid bitumen is the dominant organic matter occurring in shale plays of peak oil and gas window thermal maturity, whereas oil-prone Type I/II kerogens have converted to hydrocarbons and are not present. High magnification SEM observation of an interconnected organic porosity occurring in the solid bitumen of thermally mature shale reservoirs has enabled major advances in our understanding of hydrocarbon migration and storage in shale, but suffers from inability to confirm the type of organic matter present. Herein we review organic petrography applications in the North American shale plays through discussion of incident light photographic examples. In the first part of the manuscript we provide basic practical information on the measurement of organic reflectance and outline fluorescence microscopy and other petrographic approaches to the determination of thermal maturity. In the second half of the paper we discuss applications of organic petrography and SEM in all of the major shale petroleum systems in North America including tight oil plays such as the Bakken, Eagle Ford and Niobrara, and shale gas and condensate plays including the Barnett, Duvernay, Haynesville-Bossier, Marcellus, Utica, and Woodford, among others. Our review suggests systematic research employing correlative high resolution imaging techniques and in situ geochemical probing is needed to better document hydrocarbon storage, migration and wettability properties of solid bitumen at the pressure and temperature conditions of shale reservoirs.

International Journal of Coal Geology↗
USGS2016

Organic petrology and geochemistry of Eocene Suzak bituminous marl, north-central Afghanistan: Depositional environment and source rock potential

Organic geochemistry and petrology of Eocene Suzak bituminous marl outcrop samples from Madr village in north-central Afghanistan were characterized via an integrated analytical approach to evaluate depositional environment and source rock potential. Multiple proxies suggest the organic-rich (TOC ∼6 wt.%) bituminous marls are ‘immature’ for oil generation (e.g., vitrinite R o < 0.4%, T max < 425 °C, PI ≤ 0.05, C 29 ααα S/S + R ≤ 0.12, C 29 ββS/ββS+ααR ≤ 0.10, others), yet oil seeps are present at outcrop and live oil and abundant solid bitumen were observed via optical microscopy. Whole rock sulfur content is ∼2.3 wt.% whereas sulfur content is ∼5.0–5.6 wt.% in whole rock extracts with high polar components, consistent with extraction from S-rich Type IIs organic matter which could generate hydrocarbons at low thermal maturity. Low Fe-sulfide mineral abundance and comparison of Pr/Ph ratios between saturate and whole extracts suggest limited Fe concentration resulted in sulfurization of organic matter during early diagenesis. From these observations, we infer that a Type IIs kerogen in ‘immature’ bituminous marl at Madr could be generating high sulfur viscous oil which is seeping from outcrop. However, oil-seep samples were not collected for correlation studies. Aluminum-normalized trace element concentrations indicate enrichment of redox sensitive trace elements Mo, U and V and suggest anoxic-euxinic conditions during sediment deposition. The bulk of organic matter observed via optical microscopy is strongly fluorescent amorphous bituminite grading to lamalginite, possibly representing microbial mat facies. Short chain n- alkanes peak at C 14 –C 16 ( n- C 17 / n- C 29 > 1) indicating organic input from marine algae and/or bacterial biomass, and sterane/hopane ratios are low (0.12–0.14). Monoaromatic steroids are dominated by C 28 clearly indicating a marine setting. High gammacerane index values (∼0.9) are consistent with anoxia stratification and may indicate intermittent saline-hypersaline conditions. Stable C isotope ratios also suggest a marine depositional scenario for the Suzak samples, consistent with the presence of marine foraminifera including abundant planktic globigerinida (?) and rare benthic discocyclina (?) and nummulites (?). Biomarker 2α-methylhopane for photosynthetic cyanobacteria implies shallow photic zone deposition of Madr marls and 3β-methylhopane indicates presence of methanotrophic archaea in the microbial consortium. The data presented herein are consistent with deposition of Suzak bituminous marls in shallow stratified waters of a restricted marine basin associated with the southeastern incipient or proto-Paratethys. Geochemical proxies from Suzak rock extracts (S content, high polar content, C isotopes, normal (αααR) C 27–29 steranes, and C 29 /C 30 and C 26 /C 25 hopane ratios) are similar to extant data from Paleogene oils produced to the north in the Afghan-Tajik Basin. This observation may indicate laterally equivalent strata are effective source rocks as suggested by previous workers; however, further work is needed to strengthen oil-source correlations.

Marine and Petroleum Geology↗
USGS2016

Aptian ‘Shale Gas’ Prospectivity in the Downdip Mississippi Interior Salt Basin, Gulf Coast, USA

This study evaluates regional ‘shale gas’ prospectivity of the Aptian section (primarily Pine Island Shale) in the downdip Mississippi Salt Basin (MSB). Previous work by the U.S. Geological Survey estimated a mean undiscovered gas resource of 8.8 trillion cubic feet (TCF) in the chronostratigraphic-equivalent Pearsall Formation in the Maverick Basin of south Texas, where industry has established a moderately successful horizontal gas and liquids play. Wells penetrating the downdip MSB Aptian section at depths of 12,000-15,000 ft were used to correlate formation tops in a 15-well cross-section extending about 200 miles (mi) east-southeastward from Adams Co. to Jackson Co. Legacy cuttings from these wells were analyzed for thermal maturity and source rock quality. Bitumen reflectance (n=53) increases with increasing present-day burial depth in the east-central study area from 1.0% to 1.7%. As the Aptian section shallows in Adams Co. to the west, bitumen Ro values are higher (1.7-2.0%), either from relatively greater heat flux or greater mid-Cenomanian uplift and erosion in this area. Total organic carbon (TOC) content ranges 0.01-1.21 and averages 0.5 wt.% (n=51); pyrolysis output (S2; n=51) averages 0.40 mg HC/g rock, indicating little present-day hydrocarbon-generative potential. Bitumen reflectance is preferred as a thermal maturity parameter as Tmax values are unreliable. Normalized X-ray diffraction (XRD) mineral analyses (n=26) indicate high average clay abundance (53 wt.%) relative to quartz (29%) and carbonate (18%). Mineral content shows a spatial relationship to an Appalachian orogen clastic sediment source, with proximal high clay and quartz and distal high carbonate content. Clastic influx from the Appalachian orogen is confirmed by detrital zircon U-Pb ages with dominant Grenville and Paleozoic components [105 ages from a Rodessa sandstone and 112 ages from a Paluxy (Albian) sandstone]. Preliminary information from fluid inclusion microthermometry (41 aqueous measurements from calcite cements in one argillaceous James Limestone sample) indicates homogenization temperatures (Th) of 120-135°C, consistent with present-day bottom-hole conditions and measured bitumen Ro values towards the western end of the MSB. Downdip in the central MSB, microthermometry (26 aqueous measurements from quartz dust rims in one Paluxy sandstone sample) and measured bitumen Ro values indicate maximum temperatures may have been significantly higher (~25°C) than present-day conditions. High inclusion salinities (15-25 wt.% salt) at both locations suggest interaction of pore fluids with evaporites. Mercury injection capillary pressure (MICP) analyses (n=3) indicate porosity ranges 1.3-2.1% and permeability 0.006-0.02 µD for Pine Island and Rodessa shales. Overall, results from this work indicate generally poor ‘shale gas’ prospectivity compared to other shale reservoirs based primarily on depth, low organic content, low porosity, and high clay content. However, thickness and thermal maturity are appropriate, moderate reservoir pressures are present, and petroleum systems modelling by others has indicated high undiscovered gas potential for the basin as a whole.

Conference Paper↗
USGS2015

Using ground and intact coal Samples to evaluate hydrocarbon fate during supercritical CO 2 injection into coal beds: effects of particle size and coal moisture

To investigate the potential for mobilizing organic compounds from coal beds during geologic carbon dioxide (CO 2 ) storage (sequestration), a series of solvent extractions using dichloromethane (DCM) and using supercritical CO 2 (40 &deg;C and 10 MPa) were conducted on a set of coal samples collected from Louisiana and Ohio. The coal samples studied range in rank from lignite A to high volatile A bituminous, and were characterized using proximate, ultimate, organic petrography, and sorption isotherm analyses. Sorption isotherm analyses of gaseous CO 2 and methane show a general increase in gas storage capacity with coal rank, consistent with findings from previous studies. In the solvent extractions, both dry, ground coal samples and moist, intact core plug samples were used to evaluate effects of variations in particle size and moisture content. Samples were spiked with perdeuterated surrogate compounds prior to extraction, and extracts were analyzed via gas chromatography&ndash;mass spectrometry. The DCM extracts generally contained the highest concentrations of organic compounds, indicating the existence of additional hydrocarbons within the coal matrix that were not mobilized during supercritical CO 2 extractions. Concentrations of aliphatic and aromatic compounds measured in supercritical CO 2 extracts of core plug samples generally are lower than concentrations in corresponding extracts of dry, ground coal samples, due to differences in particle size and moisture content. Changes in the amount of extracted compounds and in surrogate recovery measured during consecutive supercritical CO 2 extractions of core plug samples appear to reflect the transition from a water-wet to a CO 2 -wet system. Changes in coal core plug mass during supercritical CO 2 extraction range from 3.4% to 14%, indicating that a substantial portion of coal moisture is retained in the low-rank coal samples. Moisture retention within core plug samples, especially in low-rank coals, appears to inhibit accessibility of supercritical CO 2 to coal matrix porosity, limiting the extent to which hydrocarbons are mobilized. Conversely, the enhanced recovery of some surrogates from core plugs relative to dry, ground coal samples might indicate that, once mobilized, supercritical CO 2 is capable of transporting these constituents through coal beds. These results underscore the need for using intact coal samples, and for better characterization of forms of water in coal, to understand fate and transport of organic compounds during supercritical CO 2 injection into coal beds.

Energy & Fuels↗
USGS2015

Microscopical characterization of carbon materials derived from coal and petroleum and their interaction phenomena in making steel electrodes, anodes and cathode blocks for the Microscopy of Carbon Materials Working Group of the ICCP

This paper describes the evaluation of petrographic textures representing the structural organization of the organic matter derived from coal and petroleum and their interaction phenomena in the making of steel electrodes, anodes and cathode blocks. This work represents the results of the Microscopy of Carbon Materials Working Group in Commission III of the International Committee for Coal and Organic Petrology between the years 2009 and 2013. The round robin exercises were run on photomicrograph samples. For textural characterization of carbon materials the existing ASTM classification system for metallurgical coke was applied. These round robin exercises involved 15 active participants from 12 laboratories who were asked to assess the coal and petroleum based carbons and to identify the morphological differences, as optical texture (isotropic/anisotropic), optical type (punctiform, mosaic, fibre, ribbon, domain), and size. Four sets of digital black and white microphotographs comprising 151 photos containing 372 fields of different types of organic matter were examined. Based on the unique ability of carbon to form a wide range of textures, the results showed an increased number of carbon occurrences which have crucial role in the chosen industrial applications. The statistical method used to evaluate the results was based on the “raw agreement indices”. It gave a new and original view on the analysts' opinion by not only counting the correct answers, but also all of the knowledge and experience of the participants. Comparative analyses of the average values of the level of overall agreement performed by each analyst in the exercises during 2009–2013 showed a great homogeneity in the results, the mean value being 90.36%, with a minimum value of 83% and a maximum value of 95%.

International Journal of Coal Geology↗
USGS2015

Pore characteristics of Wilcox Group Coal, U.S. Gulf Coast Region: Implications for the occurrence of coalbed gas

Pore characteristics of 27 subbituminous coal samples (16 mesh splits) from the Paleocene–Eocene Wilcox Group of north Louisiana (Ouachita and Caldwell Parishes) and south Texas (Zavala County) were examined in relation to desorbed gas content. Coal gas of the Wilcox Group is primarily biogenic in origin; thermogenic gas also may be present in some areas. On an as-received basis, desorbed gas contents range from 0.59 to 1.28 m 3 /t for Ouachita Parish samples, 0.37 to 5.19 m 3 /t for the Caldwell Parish samples, and 0.02 to 0.06 m 3 /t for the Zavala County samples. For Louisiana coal samples, micropore surface area and volume are correlated to the desorbed gas content of the Wilcox Group coal (correlations: r = 0.50 and 0.47, respectively), suggesting that micropore surface area and volume are important in terms of gas-holding capacity. Adsorption by micropores appears to be the primary form of gas storage for the Louisiana coal samples. Micropore surface area and volumes also are strongly correlated with the carbon/ash yield ratio (r = 0.97 and 0.94, respectively), indicating that gas sorption occurs primarily on organic matter. Mineral matter appears to reduce the sorption capacity of the coal. Micropore width decreases with depth (r = − 0.63), probably as the result of increasing pressure and coal rank with depth. For the Louisiana coal samples, mesopore surface area is negatively correlated with the carbon/ash yield ratio (r = − 0.70), suggesting that mesopores are preferentially associated with mineral matter. Average mesopore size is correlated with desorbed gas (r = 0.80) for the relatively shallow Ouachita Parish samples (average depth = 441 m, 1446 ft); these results suggest that the permeability of the Wilcox coal is greater in the shallow stratigraphic intervals compared to deeper intervals. Additionally, mesopore size decreases with depth (r = − 0.80). For Ouachita Parish coal samples, negative correlations of gas with mesopore surface area (r = − 0.74) and mesopore volume (r = − 0.56) strongly suggest that gas is not adsorbed in mesopores, and that free gas may be present in larger mesopores, macropores, or fractures of the Wilcox coal. Results also suggest that moisture in Ouachita Parish samples is present in mesopores; moisture in mesopores may have blocked gas adsorption. The low-gas south Texas samples (average depth = 313 m, 1026 ft) are markedly different from the Louisiana samples. Specifically, micropore surface area and micropore volume are negatively correlated with desorbed gas for the Texas samples (r =− 0.21 and − 0.36, respectively). Geologic or environmental conditions probably were not conducive to the generation or storage of microbial gas in the Zavala County coals. The geologic settings (i.e., salinity of formation water, groundwater recharge, permeability of coal) of each study area are important factors that need to be considered in relation to the potential for generation or storage of microbial gas. In south Texas, tectonic stress may have led to a reduction in permeability in the Wilcox Group coal, creating an unfavorable environment for the generation or preservation of microbial gas. The subbituminous rank of the Zavala coals is also too low for significant thermogenic gas generation to have occurred.

Arkansas, Louisiana, Mississippi, Texas↗
USGS2015

Thermal maturity of Tasmanites microfossils from confocal laser scanning fluorescence microscopy

We report here, for the first time, spectral properties of Tasmanites microfossils determined by confocal laser scanning fluorescence microscopy (CLSM, using Ar 458 nm excitation). The Tasmanites occur in a well-characterized natural maturation sequence ( R o 0.48–0.74%) of Devonian shale ( n = 3 samples) from the Appalachian Basin. Spectral property λ max shows excellent agreement ( r 2 = 0.99) with extant spectra from interlaboratory studies which used conventional fluorescence microscopy techniques. This result suggests spectral measurements from CLSM can be used to infer thermal maturity of fluorescent organic materials in geologic samples. Spectra of regions with high fluorescence intensity at fold apices and flanks in individual Tasmanites are blue-shifted relative to less-deformed areas in the same body that have lower fluorescence intensity. This is interpreted to result from decreased quenching moiety concentration at these locations, and indicates caution is needed in the selection of measurement regions in conventional fluorescence microscopy, where it is common practice to select high intensity regions for improved signal intensity and better signal to noise ratios. This study also documents application of CLSM to microstructural characterization of Tasmanites microfossils. Finally, based on an extant empirical relation between conventional λ max values and bitumen reflectance, λ max values from CLSM of Tasmanites microfossils can be used to calculate a bitumen reflectance equivalent value. The results presented herein can be used as a basis to broaden the future application of CLSM in the geological sciences into hydrocarbon prospecting and basin analysis.

Fuel↗
USGS2015

Standardization of reflectance measurements in dispersed organic matter: results of an exercise to improve interlaboratory agreement

Vitrinite reflectance generally is considered the most robust thermal maturity parameter available for application to hydrocarbon exploration and petroleum system evaluation. However, until 2011 there was no standardized methodology available to provide guidelines for vitrinite reflectance measurements in shale. Efforts to correct this deficiency resulted in publication of ASTM D7708: Standard test method for microscopical determination of the reflectance of vitrinite dispersed in sedimentary rocks . In 2012-2013, an interlaboratory exercise was conducted to establish precision limits for the D7708 measurement technique. Six samples, representing a wide variety of shale, were tested in duplicate by 28 analysts in 22 laboratories from 14 countries. Samples ranged from immature to overmature (0.31-1.53% R o ), from organic-lean to organic-rich (1-22 wt.% total organic carbon), and contained Type I (lacustrine), Type II (marine), and Type III (terrestrial) kerogens. Repeatability limits (maximum difference between valid repetitive results from same operator, same conditions) ranged from 0.03-0.11% absolute reflectance, whereas reproducibility limits (maximum difference between valid results obtained on same test material by different operators, different laboratories) ranged from 0.12-0.54% absolute reflectance. Repeatability and reproducibility limits degraded consistently with increasing maturity and decreasing organic content. However, samples with terrestrial kerogens (Type III) fell off this trend, showing improved levels of reproducibility due to higher vitrinite content and improved ease of identification. Operators did not consistently meet the reporting requirements of the test method, indicating that a common reporting template is required to improve data quality. The most difficult problem encountered was the petrographic distinction of solid bitumens and low-reflecting inert macerals from vitrinite when vitrinite occurred with reflectance ranges overlapping the other components. Discussion among participants suggested this problem could not be easily corrected via kerogen concentration or solvent extraction and is related to operator training and background. No statistical difference in mean reflectance was identified between participants reporting bitumen reflectance vs. vitrinite reflectance vs. a mixture of bitumen and vitrinite reflectance values, suggesting empirical conversion schemes should be treated with caution. Analysis of reproducibility limits obtained during this exercise in comparison to reproducibility limits from historical interlaboratory exercises suggests use of a common methodology (D7708) improves interlaboratory precision. Future work will investigate opportunities to improve reproducibility in high maturity, organic-lean shale varieties.

Marine and Petroleum Geology↗
USGS2014

Petrographic maturity parameters of a Devonian shale maturation series, Appalachian Basin, USA. ICCP Thermal Indices Working Group interlaboratory exercise

This paper presents results of an interlaboratory exercise on organic matter optical maturity parameters using a natural maturation series comprised by three Devonian shale samples (Huron Member, Ohio Shale) from the Appalachian Basin, USA. This work was conducted by the Thermal Indices Working Group of the International Committee for Coal and Organic Petrology (ICCP) Commission II (Geological Applications of Organic Petrology). This study aimed to compare: 1. maturation predicted by different types of petrographic parameters (vitrinite reflectance and spectral fluorescence of telalginite), 2. reproducibility of the results for these maturation parameters obtained by different laboratories, and 3. improvements in the spectral fluorescence measurement obtained using modern detection systems in comparison with the results from historical round robin exercises. Mean random vitrinite reflectance measurements presented the highest level of reproducibility (group standard deviation 0.05) for low maturity and reproducibility diminished with increasing maturation (group standard deviation 0.12). Corrected fluorescence spectra, provided by 14 participants, showed a fair to good correspondence. Standard deviation of the mean values for spectral parameters was lowest for the low maturity sample but was also fairly low for higher maturity samples. A significant improvement in the reproducibility of corrected spectral fluorescence curves was obtained in the current exercise compared to a previous investigation of Toarcian organic matter spectra in a maturation series from the Paris Basin. This improvement is demonstrated by lower values of standard deviation and is interpreted to reflect better performance of newer photo-optical measuring systems. Fluorescence parameters measured here are in good agreement with vitrinite reflectance values for the least mature shale but indicate higher maturity than shown by vitrinite reflectance for the two more mature shales. This red shift in λ max beyond 0.65% vitrinite reflectance was also observed in studies of Devonian shale in other basins, suggesting that the accepted correlation for these two petrographic thermal maturity parameters needs to be re-evaluated. A good linear correlation between λ max and T max for this maturation series was observed and λ max 600 nm corresponds to T max of 440 °C. Nevertheless if a larger set of Devonian samples is included, the correlation is polynomial with a jump in λ max ranging from 540 to 570 nm. Up to 440 °C of T max , the λ max , mostly, reaches up to 500 nm; beyond a T max of 440 °C, λ max is in the range of 580–600 nm. This relationship places the “red shift” when the onset of the oil window is reached at T max of 440 °C. Moreover, the correlation between HI and λ max (r 2 = 0.70) shows a striking inflection and decrease in HI above a λ max of 600 nm, coincident with the approximate onset of hydrocarbon generation in these rocks.

International Journal of Coal Geology↗