Solid organic matter (OM) plays an essential role in the generation, migration, storage, and production of hydrocarbons from economically important shale rock formations. Electron microscopy images ...have documented spatial heterogeneity in the porosity of OM at nanoscale, and bulk spectroscopy measurements have documented large variation in the chemical composition of OM during petroleum generation. However, information regarding the heterogeneity of OM chemical composition at the nanoscale has been lacking. Here we demonstrate the first application of atomic force microscopy-based infrared spectroscopy (AFM-IR) to measure the chemical and mechanical heterogeneity of OM in shale at the nanoscale, orders of magnitude finer than achievable by traditional chemical imaging tools such as infrared microscopy. We present a combination of optical microscopy and AFM-IR imaging to characterize OM heterogeneity in an artificially matured series of New Albany Shales. The results document the evolution of individual organic macerals with maturation, providing a microscopic picture of the heterogeneous process of petroleum generation.
Raman spectroscopy was studied as a thermal maturity probe in a series of Upper Devonian Ohio Shale samples from the Appalachian Basin spanning from immature to dry gas conditions. Raman spectroscopy ...also was applied to samples spanning a similar thermal range created from 72-h hydrous pyrolysis (HP) experiments of the Ohio Shale at temperatures from 300 to 360 °C and isothermal HP experiments lasting up to 100 days of similar Devonian–Mississippian New Albany Shale. Raman spectra were treated by automated evaluation software based on iterative and simultaneous modeling of signal and baseline functions to decrease subjectivity. Spectra show robust correlation to measured solid bitumen reflectance (BRo) values and were therefore used to construct logarithmic regression relationships for calculation of BRo equivalent values. Raman spectra show considerable differences between natural samples and HP residues with similar measured BRo values, indicating as-yet undetermined differences in carbon chemistry. We speculate this result may be due to differences in the sampling interactions of Raman vs reflectance measurements, and the incomplete nature of maturation reactions in the time-limited hydrous pyrolysis residues. Samples used in this study are similar in organic assemblage (dominantly solid bitumen) to other commonly exploited North American shale petroleum systems, i.e., Bakken, Barnett, Duvernay, Fayetteville, and Woodford shales. Therefore, results presented herein may be broadly applicable to other important shale plays. However, caution is suggested and Raman spectroscopy as a thermal probe may need individual calibration in each shale play due to differences in solid bitumen carbon chemistry.
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.
•Organic petrography of the important North American shale plays is reviewed.•Organic petrography allows thermal maturity and organo-facies determination.•Solid bitumen is the dominant organic matter present in thermally mature shales.•SEM approaches are important but unable to identify organic matter types.•Oil-prone kerogen generally is not present in thermally mature shales.
•Tasmanites spectra were measured by confocal laser scanning microscopy (CLSM).•CLSM spectra agree with spectra from conventional fluorescence microscopy.•CLSM identifies discrete spectral regions of ...individual Tasmanites bodies.•CLSM spectra can be used to calculate a bitumen Ro equivalent value.•This work extends application of CLSM to hydrocarbon prospecting and basin analysis.
We report here, for the first time, spectral properties of Tasmanites microfossils determined by confocal laser scanning fluorescence microscopy (CLSM, using Ar 458nm excitation). The Tasmanites occur in a well-characterized natural maturation sequence (Ro 0.48–0.74%) of Devonian shale (n=3 samples) from the Appalachian Basin. Spectral property λmax shows excellent agreement (r2=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 λmax values and bitumen reflectance, λmax 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.
Organic petrology developed as coal petrology at the beginning of the 20th century dedicated mainly to the study of coals because of their utilization in industry. Coal petrology was then considered ...a branch of coal science. Later, with the development of specialized nomenclature, classification of coal components, and the standardization and improvement of analytical (microscopical) methods, this discipline expanded in interests and name, becoming organic petrology. Organic petrology carries a broader context, being as well a tool applied in the study of dispersed organic matter in sedimentary rocks due to its importance in exploration for fossil fuel resources. At present, organic petrology is a discipline widely recognized for its role in fundamental and applied research with respect to both coal utilization and in geosciences. Throughout the 20th century several important monographs have been published on the discipline of organic petrology, including “Stach's textbook of coal petrology” (1st edition 1935, 2nd 1975, 3rd 1982), updated as the more general “Organic petrology” by Taylor et al. (1998). More recently, the text “Applied coal petrology: the role of petrology in coal utilization” was published by Suárez-Ruiz and Crelling (2008). This review is the first in a two-part review series that describes and updates the role of organic petrology in geosciences. A second part complementing this one and focused on the applications of organic petrology to other scientific fields will follow.
► Organic petrology. ► Organic petrology: geological applications. ► Organic petrology and basin analysis. ► Organic petrology depositional environments. ► Organic petrology and fossil fuel resources exploration.
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% Ro), 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 to 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 to 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.
•ASTM method D7708 was tested by an interlaboratory study.•Six shale samples were tested by 28 analysts in 22 laboratories from 14 countries.•Repeatability limits (intralaboratory) ranged from 0.03 to 0.11% absolute reflectance.•Reproducibility limits (interlaboratory) ranged from 0.12 to 0.54% absolute reflectance.•Using D7708 improved reproducibility compared to historical interlaboratory studies.
High-resolution scanning electron microscopy (SEM) visualization of sedimentary organic matter is widely utilized in the geosciences for evaluating microscale rock properties relevant to depositional ...environment, diagenesis, and the processes of fluid generation, transport, and storage. However, despite thousands of studies which have incorporated SEM methods, the inability of SEM to differentiate sedimentary organic matter types has hampered the pace of scientific advancement. In this study, we show that SEM-cathodoluminescence (CL) properties can be used to identify and characterize sedimentary organic matter at low thermal maturity conditions. Eleven varied mudstone samples with a broad array of sedimentary organic matter types, ranging from the Paleoproterozoic to Eocene in age, were investigated. Sedimentary organic matter fluorescence intensity and CL intensity showed an almost one-to-one correspondence, with certain exceptions in three samples potentially related to radiolytic alteration. Therefore, because CL emission can be used as a proxy for fluorescence emission from sedimentary organic matter, CL emission during SEM visualization can be used to differentiate fluorescent from non-fluorescent sedimentary organic matter. This result will allow CL to be used as a visual means to quickly differentiate sedimentary organic matter types without employing correlative optical microscopy and could be widely and rapidly adapted for SEM-based studies in the geosciences.
Microscopic solid bitumen is a petrographically defined secondary organic matter residue produced during petroleum generation and subsequent oil transformation. The presence of solid bitumen impacts ...many reservoir properties including porosity, permeability, and hydrocarbon generation and storage, among others. Furthermore, solid bitumen reflectance is an important parameter for assessing the thermal maturity of formations with little to no vitrinite. While the molecular composition of solid bitumen will strongly impact associated parameters such as the development of organic matter porosity, hydrocarbon generation, and optical reflectance, assessing the molecular composition of solid bitumen in situ within shale reservoirs can be challenging due to the small grain sizes (often ≤1 μm in diameter) and the inherent heterogeneity of shale formations. Here we employ the recently developed atomic force microscopy based infrared spectroscopy (AFM-IR) technique to investigate solid bitumen molecular composition in situ within shale samples from the Late Cretaceous Eagle Ford Group. These samples possess sulfur-rich type II kerogens that span a natural thermal maturity gradient from early oil generation to the dry gas window. The application of AFM-IR allows for the rapid collection of thousands of compositional measurements from solid bitumen with ∼50 nm resolution. Our results indicate that (i) solid bitumen from the lower Eagle Ford displays both intra- and intergranular variation in the relative abundance of CH2, CC, and CO moieties present; (ii) this molecular variation tends to, but does not always, decrease with an increase in thermal maturity; and (iii) the solid bitumen composition between samples, from an atomic ratio perspective, is more similar than analysis of bulk kerogen isolates would indicate. These findings are discussed with perspective toward understanding the impact of thermal stress on the composition of secondary organic matter within the Eagle Ford Shale and highlight the growing awareness that organic matter heterogeneity within petroliferous mudrocks extends down to the nanoscale regime.
•Tuscaloosa marine shale has a high sealing capacity for CO2 sequestration.•Calculated CO2 column heights in reservoir range 23–255 m before seal invasion.•Seal leakage more likely to occur from ...historical wellbores than capillary failure.
This work used mercury injection capillary pressure (MICP) analyses of the Tuscaloosa Group in Mississippi, including the Tuscaloosa marine shale (TMS), to assess their efficacy and sealing capacity for geologic carbon dioxide (CO2) sequestration. Tuscaloosa Group porosity and permeability from MICP were evaluated to calculate CO2 column height retention. TMS and Lower Tuscaloosa shale samples have, respectively, Swanson permeability values less than 0.003 md and 0.00245 md; porosity from 3.86% to 9.86% and 1.34% to 7.96%; median pore throat sizes from 0.00342 to 0.0111 μm and 0.00311 to 0.017 μm; and pore radii from 0.0130 to 0.152 μm and 0.0132 to 0.149 μm. Mercury entry pressures for the TMS and Lower Tuscaloosa range from 4.9 to 57.1 MPa and 5.0 to 56.3 MPa, respectively. Calculated CO2 column heights that the TMS sample set can retain in the reservoir range from 23 to 255 m when the TMS is near 100% water saturation. Potential top seal leakage is more likely to be influenced by the numerous well penetrations through the confining system of the TMS rather than capillary failure. Results of this study demonstrate desirable sealing capacity of the TMS for geologic CO2 sequestration in reservoir sandstones of the Lower Tuscaloosa and could provide an analogue to other potential CO2 sequestration top seals.
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