Geology topics

Javin J. Hatcherian

Publications and source records attributed to Javin J. Hatcherian.

29 records · Page 2Linked to original sources

USGS2020

Investigating the effects of broad ion beam milling to sedimentary organic matter: Surface flattening or heat-induced aromatization and condensation?

Previous work has proposed transfer of kinetic heat energy from low-energy broad ion beam (BIB) milling causes thermal alteration of sedimentary organic matter, resulting in increases of organic matter reflectance. Whereas, other studies have suggested the organic matter reflectance increase from BIB milling is due to decreased surface roughness. To test if reflectance increases to sedimentary organic matter (vitrinite) caused by BIB milling were related to molecular aromatization and condensation, Raman and Fourier transform infrared (FTIR) spectroscopies were used to evaluate potential compositional changes in the same vitrinite locations pre- and post-BIB milling. The same locations also were examined by atomic force microscopy (AFM) to determine topographic changes caused by BIB milling (as quantified by the areal root-mean-square roughness parameter S q ). Samples consisted of four medium volatile bituminous coals. A non-aggressive BIB milling approach was used with conditions of 5 min, 4 keV, 15°incline, 360° rotation at 25 rpm and 100% focus (1.5 kV discharge; ∼100 μA). This gentle BIB milling caused vitrinite reflectance (VR o ) increases of 12 to 36% of the original values determined optically before milling (average 26% increase). When molecular proxies from FTIR (A- and C-factor, branching ratio) were plotted against each other for the same vitrinite locations pre- and post-milling, mean data points for each sample generally lie within error of a 1:1 line. Likewise, mean Raman thermal proxy [full-width half maximum of G-band (G-FWHM), Raman band separation (RBS) and D1/G band intensity ratio] values were similar for pre- and post-milled locations, also plotting within error of a 1:1 line. AFM confirms the majority (24 of 36) of pre- and post-ion milled surface pairs were smoother (lower S q values) after BIB milling. These results are interpreted to indicate VR o increase induced by the gentle BIB milling conditions used in this study is an effect of decreased diffuse reflectance due to flatter surfaces, causing more photons to reflect directly back to the detector. Little evidence was observed for molecular aromatization and condensation of vitrinite molecules following BIB milling (with the conditions used). The presence of milling-induced artifacts, including differential milling effects dependent on location and the development of self-organized patterned structures, indicate much work remains in standardization of BIB milling before its promulgation as a routine sample preparation technique for organic petrography. These results provide better understanding of anthropogenic-induced changes to geological samples caused by the now widespread adoption of BIB milling as a disruptive innovation in sample preparation.

Fuel↗

USGS2020

Organic petrography of Leonardian (Wolfcamp A) mudrocks and carbonates, Midland Basin, Texas: The fate of oil-prone sedimentary organic matter in the oil window

To better understand evolution of oil-prone sedimentary organic matter to petroleum and expulsion from source rock, we evaluated organic petrographic features of Leonardian Wolfcamp A repetitive siliceous and calcareous mudrock and fine-grained carbonate lithofacies cycles occurring in the R. Ricker #1 core from Reagan County, Midland Basin, Texas. The objectives of the petrographic investigation were to estimate thermal maturity, identify organic matter types and abundances, and identify the presence or absence of migrated hydrocarbons in organic-lean carbonate layers. An integrated analytical program included geochemical screening [total organic carbon (TOC) content by LECO, programmed pyrolysis by hydrocarbon analyzer with kinetics (HAWK) including analysis of solvent-extracted samples], X-ray diffraction mineralogy, organic petrography, scanning electron microscopy with energy dispersive spectroscopy (SEM-EDS) including correlative light and electron microscopy (CLEM), and micro-Fourier transform infrared spectroscopy (μ-FTIR) analyses of solid bitumen. The data indicate all samples are early to middle oil window thermal maturity with solid bitumen reflectance (BR o ) values of 0.55–0.86% and T max of 440–455 °C. Organic matter is predominantly solid bitumen (as identified by optical microscopy) in all lithofacies with minor contributions from inertinite. Solid bitumen abundance decreases from siliceous mudrock (TOC >3.0 wt%) to calcareous mudrock (TOC 1.0 to 3.0 wt%) to fine-grained carbonate (TOC <1.0 wt%) lithofacies. Interpretations of petrographic data suggest siliceous and calcareous mudrocks are source rock lithofacies and contain solid bitumen (with petroleum generation potential) that is residual (what remains) from conversion of an original Type II sedimentary organic matter. In turn, fine-grained carbonates are interpreted as reservoir lithofacies which contained little or no original oil-prone sedimentary organic matter and at present-day contain only a minor component of migrated solid petroleum sourced from adjacent siliceous and calcareous mudrock lithofacies. This work helps to document petroleum generation and migration processes, improve unconventional reservoir characterization and better define areas of oil window thermal maturity in an area critical to United States hydrocarbon production.

Texas↗

USGS2020

Oil-source rock correlation studies in the unconventional Upper Cretaceous Tuscaloosa marine shale (TMS) petroleum system, Mississippi and Louisiana, USA

The U.S. Geological Survey assessed undiscovered unconventional hydrocarbon resources reservoired in the Upper Cretaceous Tuscaloosa marine shale (TMS) of southern Mississippi and adjacent Louisiana in 2018. As part of the assessment, oil-source rock correlations were examined in the TMS play area where operators produce light (38–45° API), sweet oil from horizontal, hydraulically-fractured wells in an overpressured ‘high-resistivity’ (>5 Ω-m) zone at the base of the TMS. Geochemical data from 39 oil samples and 17 source rock solvent extracts collected from the TMS play area indicate close correspondence for Tuscaloosa Group oils [from lower Tuscaloosa, middle Tuscaloosa (the TMS) and upper Tuscaloosa reservoirs] in thermal maturity (computed from MPI), SARA proportions, n- alkane distributions, isoprenoid and DBT/P ratios, monoaromatic steroids, and δ 13 C isotopic compositions (from whole oils, saturate and aromatic fractions). Other parameters (normal steranes, extended homohopanes, C 31 R/C 30 hopane, norhopane/hopane and tricyclic terpane ratios, gammacerane/hopane) show most oil samples have similar values, suggesting all Tuscaloosa Group oils are from a common mixed marine-terrigenous source rock. Tighter distributions for triaromatic steroid (TAS) and δ 13 C isotopic composition for conventional oils in lower and upper Tuscaloosa reservoirs may indicate charge occurred in a single or shorter pulse relative to TMS oils which show broader TAS and δ 13 C properties, possibly from their generation over an extended period of burial maturation. Dissimilarity in geochemical properties between lower Tuscaloosa source rock solvent extracts and Tuscaloosa Group oils indicates lower Tuscaloosa source rocks did not contribute significantly to conventional and unconventional Tuscaloosa Group hydrocarbon accumulations. Whereas, TMS solvent extracts are similar to Tuscaloosa Group oils, suggesting an oil-source rock correlation. Excluding the possibility for long-distance lateral migration from a similar source downdip (which is unnecessary given thermal maturity considerations), the observations indicate 1. the TMS is a self-sourced reservoir, 2. the TMS is the source of oils accumulated in nearby conventional Tuscaloosa Group reservoirs, and 3. thin organic-rich shales in the lower Tuscaloosa did not contribute substantially to any oil accumulations in the Tuscaloosa Group.

Louisiana, Mississippi↗

USGS2019

Nanoscale molecular fractionation of organic matter within unconventional petroleum source beds

Fractionation of petroleum during migration through sedimentary rock matrices has been observed across lengths of meters to kilometers. Selective adsorption of specific chemical moieties at mineral surfaces and/or the phase behavior of petroleum during pressure changes typically are invoked to explain this behavior. Such phenomena are of interest as they impact both the quality and recoverability of petroleum resources. Given the current emphasis on unconventional (continuous) resources, there is a need to understand petroleum fractionation occurring during expulsion and migration at the nanometer to micron scale, due to the fine-grained nature of petroliferous mudrocks. Here, organic matter compositional differences observed within kukersites (petroleum source beds containing acritarch Gloeocapsomorpha prisca) and the overlying carbonate reservoir layer from the Ordovician Stonewall Formation are explored using a suite of spectroscopic methods, primarily through atomic force microscopy based infrared spectroscopy (AFM-IR). AFM-IR is capable of providing spatial resolutions approaching 50 nm and allows for assessment of the molecular fingerprint of kukersite organic matter across transition zones from organic-rich ‘source’ layers into neighboring carbonate ‘reservoir’ layers ~150 μm away. Results indicate that organic matter composition begins to vary immediately following expulsion from source layers, with loss of carbonyl groups and a concomitant decrease in alkyl chain-length, as migration distance increases. These chemical transitions correlate with a decrease in fluorescence intensity, increase in solid bitumen reflectance, and increase in Raman aromaticity proxies (D-G band separation) in the organic matter. Our findings are consistent with the retention of polar compounds onto mineral grains during expulsion and migration, following primary cracking and bituminization of the Gloeocapsomorpha prisca kerogen.

Energy and Fuels↗

USGS2019

Reflectance increase from broad beam ion milling of coals and organic-rich shales due to increased surface flatness

Broad ion beam (BIB) milling is useful in organic petrology because it can yield flat sample surfaces and avert the ‘smearing’ of organic matter (OM) that results from traditional mechanical polishing. This potentially makes BIB especially useful in the study of nano-porosity, where even minor mechanical disruption of the sample surface distorts the sample characteristic of interest—the pore structure. However, several studies have observed an OM reflectance increase after BIB milling, concluding that ion milling may cause thermal alteration to OM surfaces. To better understand ion milling effects on organic matter, coal (subbituminous, high volatile bituminous, medium volatile bituminous, anthracite) and shale [Bakken Formation, Ohio Shale-Huron Member (5), Kimmeridge Clay Formation, Alum Shale, New Albany Shale] samples were prepared using traditional mechanical polishing methods. Reflectance measurements (% Ro) were gathered on all maceral types present before BIB milling, followed by re-measurement of OM reflectance at the same locations after milling. Most OM increased in reflectance after BIB milling, with some exceptions in high maturity samples. Liptinite macerals in both coal and shale samples showed the greatest percent reflectance increase on average (+133%; n=338), followed by solid bitumen (+49%; n=313), vitrinite (+26%; n=413), and inertinite (+9%; n=220). Despite the increases to OM reflectance caused by BIB milling, no evidence was found for kerogen conversion (e.g., change in maceral abundances), or for migration of newly generated petroleum (e.g., pseudomorphic replacement of kerogen by solid bitumen). Such changes occur when samples are thermally altered from immature conditions into the oil window (e.g., by hydrous pyrolysis), and, if the increases in OM reflectance were thermally driven (by BIB milling), they should have been observed in the above experiments. Herein, we also used atomic force microscopy to document a decrease in surface roughness of correlative locations of OM on pre- and post-ion milled samples. This improved surface polish caused by BIB milling appears to be the root cause of increased OM reflectance, as no other supporting evidence of thermal alteration could be found. That is, the fraction of light formerly lost to oblique scatter in diffuse reflectance from a mechanically polished surface is converted to specular reflectance after BIB ion milling. Thus the light leaves the surface at a near normal angle and returns to the detector, resulting in increased OM reflectance.

International Journal of Coal Geology↗

USGS2018

Assessment of undiscovered continuous oil and gas resources in the Upper Cretaceous Tuscaloosa marine shale of the U.S. Gulf Coast, 2018

Using a geology-based assessment methodology, the U.S. Geological Survey assessed mean undiscovered, technically recoverable continuous resources of 1.5 billion barrels of oil and 4.6 trillion cubic feet of gas in the Upper Cretaceous Tuscaloosa marine shale in onshore and State waters of Louisiana, Mississippi, Alabama, and Florida in the U.S. Gulf Coast region.

Upper Cretaceous Tuscaloosa Marine Shale↗

USGS2018

On the petrographic distinction of bituminite from solid bitumen in immature to early mature source rocks

The oil-prone maceral bituminite (and its equivalents: ‘amorphous organic matter’, ‘sapropelinite’, ‘amorphinite’, etc.) converts to petroleum during thermal maturation of source rocks, resulting in formation of a mobile saturate-rich hydrocarbon and a polar-rich residue of solid bitumen. Evidence of this transition is preserved in immature to early mature source rocks (e.g., Alum, Bakken, Kimmeridge, New Albany, Ohio shales, among many others), where organic petrography reveals a continuum of textures, reflectance, and fluorescence intensity occurring between bituminite and solid bitumen. Bituminite generally is characterized by high(er) intensity fluorescence, low contrast to the inorganic matrix, lower reflectance (compared to solid bitumen), and heterogeneous wispy or ‘schlieren’ textures. In comparison, solid bitumen generally shows lower intensity or no fluorescence compared to bituminite, a distinct contrast to the mineral matrix which usually includes a gray homogeneous surface of low to moderate reflectance, and may possess void-filling, embayment or groundmass textures suggesting evidence of migration or its in situ exsolution. However, these properties may manifest across a continuous spectrum in a sample or in a single microscope field, often making identification inconclusive. Unambiguous identification is further hampered by sample preparation, e.g., mechanical polish may improve homogeneity of larger accumulations, whereas smaller accumulations, or those sheltered by hard minerals, may appear more heterogeneous, leading to identification of the same organic matter as solid bitumen or bituminite, respectively. The disruptive innovation of ion milling in shale sample preparation leads to increased organic reflectance and surface homogeneity, causing bituminite and other oil-prone macerals, e.g., alginite, to develop a gray reflecting surface which is easy to confuse with solid bitumen, especially when obvious void-filling or embayment textures of the latter are absent. Herein we review distinction of solid bitumen from bituminite and alginite in immature to early mature source rocks, providing examples from nine samples illustrated by typical organic petrography images, including samples from hydrous pyrolysis experiments. Based on a review of the literature, we observe an arbitrary reflectance limit of 0.30% in mechanically polished samples seems to differentiate bituminite (<0.30%) from confident identifications of homogeneous solid bitumen (which otherwise lacks obvious void-filling or identifying embayment textures) as individual macerals on a continuous spectrum in immature and early mature source rocks. Future work conducted by governing bodies such as the International Committee for Coal and Organic Petrology (ICCP) should consider interlaboratory studies conducted on multiple immature source rock samples to develop consensus guidelines for bituminite and solid bitumen discrimination.

International Journal of Coal Geology↗

USGS2018

High microscale variability in Raman thermal maturity estimates from shale organic matter

Raman spectroscopy has recently received attention as a means to estimate thermal maturity of organic matter in petroleum generating source rocks to complement more traditional approaches such as vitrinite reflectance and programmed pyrolysis. While many studies have observed positive correlations between source rock thermal maturity and Raman spectral parameters, little attention has been given to the degree of variation in the Raman response across individual organic grains, especially for shales or mudrocks with highly dispersed organic matter. Here the spatial variation in Raman estimates of thermal maturity within individual organic grains is assessed from shales from the Boquillas, Marcellus, Niobrara, and Woodford Formations. The thermal maturity parameters extracted from Raman spectra can vary widely across distances of ≤5 μm within the same organic grain. These results illustrate the high degree of chemical heterogeneity inherent to the organic matter within these source rocks. Additionally, the spatial pattern of the Raman parameters, as revealed by 2D Raman mapping, imply that organic matter structure is influenced by associations with mineral surfaces within the surrounding rock matrix. Chemical heterogeneity and matrix effects directly impact the Raman response from these types of materials and thus the extracted thermal maturity estimate. These findings highlight the care which must be adopted when making Raman measurements of organic matter within source rock matrices, especially for samples which feature highly dispersed, heterogeneous organic matter as found in petroliferous mudrocks.

International Journal of Coal Geology↗

USGS2017

Nanoscale geochemical and geomechanical characterization of dispersed organic matter in shale by infrared nanoscopy

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.

Nature Communications↗

USGS2017

Utilization of integrated correlative light and electron microscopy (iCLEM) for imaging sedimentary organic matter

We report here a new microscopic technique for imaging and identifying sedimentary organic matter in geologic materials that combines inverted fluorescence microscopy with scanning electron microscopy and allows for sequential imaging of the same region of interest without transferring the sample between instruments. This integrated correlative light and electron microscopy technique is demonstrated with observations from an immature lacustrine oil shale from the Eocene Green River Mahogany Zone and mid‐oil window paralic shale from the Upper Cretaceous Tuscaloosa Group. This technique has the potential to allow for identification and characterization of organic matter in shale hydrocarbon reservoirs that is not possible using either light or electron microscopy alone, and may be applied to understanding the organic matter type and thermal regime in which organic nanoporosity forms, thereby reducing uncertainty in the estimation of undiscovered hydrocarbon resources.

Journal of Microscopy↗

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↗