Geology topics

Justin E. Birdwell

Publications and source records attributed to Justin E. Birdwell.

At least 73 records · Page 4Linked to original sources

USGS2020

Nanoscale molecular composition of solid bitumen from the Eagle Ford Group across a natural thermal maturity gradient

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 CH 2 , C═C, and C═O 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.

Energy and Fuels↗

USGS2020

Mineralogy and lithology of the Upper Cretaceous Niobrara Formation determined by hyperspectral core imaging

Sections of the Upper Cretaceous (Coniacian to Campanian) Niobrara Formation in two cores from Kansas and Colorado, the Amoco Rebecca Bounds and USGS Portland 1, respectively, were examined by hyperspectral core imaging and analysis. A spectral imaging system combining high-resolution photography (50 μm), 3D laser profiling (20 μm), and near-visible + short-wave infrared reflectance spectroscopy (wavelengths from 450 to 2500 nm, 500 μm pixel size) was applied to these cores to provide spectral and textural data facilitating creation of continuous mineral and lithology class maps. In addition, compositing of pixel-based results to group pixels to create mineralogical and lithological logs (0.5 ft resolution) was performed to facilitate comparisons to other geochemical datasets. The results show general correspondence in trends identified by previous geochemistry studies, with some exceptions due to instrumental limitations related to low reflectance of some rock intervals and the limited range of infrared wavelengths examined. This study provides a cursory overview of an extensive dataset meant to demonstrate the utility of hyperspectral core scanning to studies of mudrocks in petroleum systems as well as the kinds of information this technique can provide for detailed examination of stratigraphic features in sedimentary systems more generally.

Mountain Geologist↗

USGS2020

Examination of inertinite within immature Eagle Ford Shale at the nanometer-scale using atomic force microscopy-based infrared spectroscopy

The nanoscale molecular composition of sedimentary organic matter is challenging to characterize in situ given the limited tools available that can adequately interrogate its complex chemical structure. This is a particularly relevant issue in source rocks, as kerogen composition will strongly impact its reactivity and so is critical to understanding petroleum generation processes during catagenesis. The recent advent of tip-enhanced analytical methods, such as atomic force microscopy-based infrared spectroscopy (AFM-IR), has allowed for the major compositional features of kerogen and other types of in situ organic matter to be elucidated at spatial resolutions at or below 50 nm. Here AFM-IR was applied to examine inertinite, an important organic matter type, present in a thermally immature Eagle Ford calcareous mudstone. The data show that the nanoscale molecular composition of the examined inertinite is (i) less heterogeneous than solid bitumen in more thermally mature Eagle Ford samples and (ii) more hydrogen- and oxygen-rich than inertinite examined in the New Albany Shale.

Texas↗

USGS2020

Biomarker similarities between the saline lacustrine Eocene Green River and the Paleoproterozoic Barney Creek Formations

The Paleoproterozoic Barney Creek Formation, which is currently interpreted as a restricted, deep marine paleoenvironment, plays a disproportionate role in our understanding of Proterozoic ocean chemistry and the rise of complex life. The Barney Creek Formation hosts several unusual biomarker features, specifically its methylhopane and carotenoid signatures. Herein, we demonstrate that the saline lacustrine Eocene Green River Formation shares a similar distribution of methylhopanes and carotenoids, which is characteristic of saline lacustrine organic matter more generally. These distinct methylhopane and carotenoid patterns are not observed together in marine organic matter of any geologic age. These results imply a saline lacustrine depositional environment for the Barney Creek Formation, which agrees with earlier but now abandoned depositional models of this formation. As a result, models of Proterozoic ocean chemistry and emergence of complex life that rely on a marine Barney Creek Formation should be re-examined. Alternatively, if Paleoproterozoic marine biomarker signatures resemble those of younger saline lacustrine systems, then this must be recognized to accurately interpret geologic biomarker and paleoenvironmental records.

Colorado, Utah↗

USGS2020

Trends in thermal maturity indicators for the organic sulfur-rich Eagle Ford Shale

Thermal maturity is critical to evaluate petroleum systems and to interpret biomarker results for paleoenvironmental and geobiology studies. Many thermal maturity indices were developed for marine source rocks containing type II kerogen, but their behavior in organic sulfur-rich source rocks requires more investigation. Here, we present geochemical analyses of whole and extracted rock, isolated kerogens, and extractable organic matter across a natural thermal maturity transect of the Upper Cretaceous Eagle Ford Shale to evaluate the behavior of maturity parameters in organic sulfur-rich source rocks. The samples contain similar mineralogy and trace element composition, minimizing potential facies effects on thermal maturity parameters. Atomic H/C ratios of isolated kerogens, extractable organic matter yield, and programmed pyrolysis results show that the samples range from the pre-oil through dry gas generation windows. Programmed pyrolysis data and kerogen elemental ratios show that the immature samples host both type IIS (atomic Sorg/C > 0.04) and sulfur-rich type II kerogen (kerogen Sorg/C: 0.032 to 0.045) while the samples with lower kerogen Sorg/C ratios (kerogen Sorg/C < 0.03) are more mature. The vitrinite reflectance values corresponding to the onset of oil generation in the Eagle Ford are comparable to other type II petroleum systems. Likewise, the organic sulfur-rich Eagle Ford follows a similar hydrogen index and kerogen H/C trend as other marine type II source rocks. Hopane and sterane stereoisomer maturity ratios are anomalously elevated at low thermal maturities, so they should not be applied in organic sulfur-rich petroleum systems to infer thermal maturity. However, some biomarker ratios, including those that are more commonly used as source parameters, strongly track thermal maturity in this case study with limited facies variability.

Texas↗

USGS2020

Energy and minerals division tight oil and gas committee: Activities and commodity report for 2019-2020

In 2019, total daily tight oil and gas production increased in the United States month over month, with annualized growth of 14% for oil and 12% for gas. Those gains leveled off in the first quarter of 2020 due to aggressive price competition and increases in international production. Then came the pandemic with a substantially larger dose of economic turmoil, driving down demand due in part to shelter in place orders and safety concerns around travel. Between March and May, tight oil and gas production dropped by nearly 2 million bpd and almost 5 Bcf/day before beginning to recover. Production has continued to increase for the most part through the second half of 2020, but drilling remains subdued throughout most of the U.S. and uncertainty around long term demand along with the current price environment and general state of the economy has contributed to layoffs throughout the industry. Some shale-gas production has declined recently, but a few areas have seen expansion due to construction of LNG facilities along the East Coast of the U.S. (e.g., the Haynesville Formation). Current U.S. shale-gas production is still higher now than in 2019, with daily production of almost 71 Bcf as of October 2020 driven in large part by increased production from the Marcellus Shale in the Appalachian Basin and shales within the Permian Basin. Shale liquids production is down by around a million bpd to approximately 7.1 million (September 2020; U.S. EIA) from pre-pandemic production levels at the end of 2019 and beginning of 2020. Tight oil production remains dominated by plays in the Permian Basin as well as the Bakken and Eagle Ford Formations. On the development and production front, new enhanced oil recovery approaches for tight shale reservoirs are being more widely implemented. Natural gas or CO2 injection is currently being utilized in the Bakken Formation, Eagle Ford Formation, Anadarko Basin, and the Permian Basin to optimize injection sequences and boost recovery. Refracturing of existing wells to reduce drilling costs, improve production, and prolong well productive life has also begun to occur more widely in developed plays. International interest in exploiting hydrocarbons from unconventional reservoirs continues to develop, with active exploration projects on most continents. Europe remains relatively underexplored as compared to North America, although a total of 141 exploration and appraisal wells with a possible shale-gas exploration component have been spudded, including horizontal legs from vertical wells. Shale exploration has made a breakthrough in China with shale gas output in 2019 of 10 billion cubic meters (35.3 Bcf), 60% of which was produced from Sinopec’s Fuling Shale Gas field. Lacustrine shale oil exploration has also been successful in the Sichuan and Ordos Basins in central China, Junggar and Tarim Basins in northwest China, and Songliao Basin in north China, and Bohai Bay Basins in northeast China as of 2018. South America’s potential as an unconventional shale gas and oil province is mainly in Argentina and Brazil, where the production from Neuquen Basin’s tight shale of the Vaca Muerta Formation has been steadily increasing since 2016, but only 4% of the shale resource has been developed thus far. According to International Energy Agency’s report in 2013, Brazil holds the 9th largest unconventional gas reserves. Brazil has shale oil and gas potential in the Parana, Solimoes and Amazon Basins and is actively producing from the oil shale unit of the Irati Formation. In 2019, the Brazil energy ministry launched REATE 2020 to boost onshore investments that include the expectation of drilling an experimental unconventional well in the northeast region. For this inaugural report, the new AAPG EMD Tight Oil and Gas Committee (TO&G; formerly the Shale Gas & Liquids and Tight Gas Sands committees) has developed new commodity report requirements for contributors. This includes shorter annual reports focused on new developments, play concepts, along with the typical updates on production and new drilling in the play areas they cover. We are also asking contributors to collect background geologic and production related information into a document that summarizes important features of the plays they cover that will be stored on the TO&G webpage along with our commodity reports. TO&G is currently working to expand the number of contributors to cover more play areas and replace committee and advisory board members that have recently stepped down. Changes to committee leadership occurred in October as recent chairs transition to EMD elected positions.

Activities and Commodities Report↗

USGS2019

Distribution of mineral phases in the Eocene Green River Formation, Piceance Basin, Colorado – Implications for the evolution of Lake Uinta

The mineralogy of the Eocene Green River Formation in the Piceance Basin, Colorado, has been the subject of numerous studies since the 1920s. Most previous work has focused on the resource potential of these lacustrine mudrocks, which in addition to substantial oil shale potential (in-place resources of 353 billion barrels of synthetic crude oil for rocks yielding at least 25 gallons per ton, GPT), includes nahcolite, a currently utilized soda ash resource, and dawsonite, a potential alternative source of aluminum. Another reason to study the mineralogy in this system is that the geographic and stratigraphic distribution of various authigenic minerals may provide insights into the geochemistry and depositional environment of the long-lived Eocene Lake Uinta. In this study, legacy non-quantitative (presence/absence) X-ray diffraction (XRD) data recently published by the U.S. Geological Survey (USGS) for more than nine-thousand samples collected from thirty coreholes in the Green River Formation, Piceance Basin were examined. These data were used to better define the stratigraphic and paleogeographic extent of a set of indicator minerals (illite, analcime, albite, dawsonite, and nahcolite) within the Piceance Basin lacustrine strata. This set of minerals was selected based on observations from previous work and variability in their occurrence and co-occurrence within the Piceance Basin. The USGS database has been used to (1) construct maps showing geographic variations in mineral occurrences for 14 stratigraphically defined rich and lean oil shale zones; (2) assess co-occurrences of indicator minerals; and (3) compare occurrence results with quantitative XRD datasets collected on Piceance Basin oil shales. Occurrences of many authigenic minerals (analcime, dawsonite, and nahcolite) varied in the lacustrine strata near and around the depocenter, but others, like quartz, dolomite, and feldspar (potassium + undifferentiated), were widely and consistently present (>90% of samples) across the basin. Shifts in the distribution of indicator mineral occurrences generally coincide with changes identified in previous lake history descriptions and indicate that the water chemistry of Lake Uinta varied significantly going from near-shore to the depocenter and through time.

Colorado↗

USGS2019

Connections between Eocene Lakes Uinta and Gosiute with emphasis on the infilling stage of Lake Uinta in Piceance Basin

Late in its history, Eocene saline Lake Gosiute in the Greater Green River Basin, Wyoming and Colorado was progressively filled from north to south with coarse volcaniclastic sediments. During the infilling, Lake Gosiute began to drain southward across the Axial arch into saline Lake Uinta in the Piceance and Uinta Basins, Colorado and Utah (about 49 Ma) causing Lake Gosiute to freshen. Once Lake Gosiute was filled entirely (about 48 Ma), volcaniclastic sediments spilled over into Lake Uinta. The first coarse volcanic sediments entered the north part of Lake Uinta near the present-day mouth of Yellow Creek 15 miles south of the Axial arch during deposition of the Mahogany oil shale zone. There is evidence that a south-flowing river entered Lake Uinta from the Axial arch starting early in the history of the Lake and prior to substantial outflow from Lake Gosiute began. A petrographic study of sandstones from this period is consistent with an Axial arch source. It is likely that the outflow channel occupied this pre-existing drainage. Determining when outflow from Lake Gosiute began to move through this pre-existing channel is difficult as mainly mud-sized sediments would have entered Lake Uinta from Lake Gosiute prior to infilling. In addition, reliable dates for most of the strata deposited in Lake Uinta are lacking. A partial section of Lake Uinta strata is preserved at Deep Channel Creek about 10 mi south of the Axial arch. Here the R-6 oil shale zone, below the Mahogany zone, has graded into fluvial strata–the only place in the basin where this zone is not lacustrine. In addition, the underlying L-5 zone is atypically sandy. We propose that Lake Gosiute began to drain into Lake Uinta starting at about the beginning of deposition of the L-5 oil shale zone increasing the input of sediments into the northern part of Lake Uinta. Mud-sized sediments could have come from Lake Gosiute, but the coarser sediments likely came from the Axial arch. Volcaniclastic sediments produced a rapidly prograding deltaic complex that ultimately filled in much if not all of the eastern part of Lake Uinta. The first volcanic sediments to reach the deep depocenter were mainly fine-grained turbidites but ultimately the depocenter was largely filled by slumps off the over-steepened delta front. A petrographic study of the volcaniclastic sandstones indicates that the Absaroka volcanic field in northwest Wyoming is the likely source of the volcanic fraction.

Colorado, Utah↗

USGS2019

Geochemistry of a thermally immature Eagle Ford Group drill core in central Texas

The Upper Cretaceous Eagle Ford Group displays significant lateral and vertical geochemical variability. Much of the work on the Eagle Ford Group has been focused southwest of the San Marcos arch. To more fully characterize the Eagle Ford across the entire region, a thermally immature drill core was acquired north of the San Marcos arch that recovered the Pepper Shale and the Eagle Ford Group. Molecular and isotopic analyses of rock extracts were combined with bulk organic and inorganic geochemistry and mineralogy to track the variability in organic matter source and depositional environment, as well as to identify drivers of organic enrichment. The Pepper Shale received significant terrigenous organic matter in its distal deltaic or prodeltaic setting compared to the more distally deposited Eagle Ford Group that primarily hosts marine organic matter. The upper Eagle Ford contains two chemofacies. The older upper Eagle Ford chemofacies has similar mineralogy and organic matter to the underlying lower Eagle Ford, and both intervals display good to excellent source rock potential. In contrast, the younger upper Eagle Ford chemofacies has a different sterane assemblage, a larger terrigenous component, and a higher clay mineral abundance. However, anoxic to euxinic depositional conditions distinguish the lower Eagle Ford from the upper Eagle Ford, which was deposited under oxic to dysoxic conditions. Redox chemistry and organic matter source are two important variables that determine source rock quality, but they did not change in parallel during Eagle Ford deposition. Differences in organic facies explain the Tmax variability, and depositional redox conditions governed organic-richness in the Eagle Ford Group in central Texas.

Texas↗

USGS2019

Integration of microfacies analysis, inorganic geochemical data, and hyperspectral imaging to unravel mudstone depositional and diagenetic processes in two cores from the Triassic Shublik Formation, Northern Alaska

The Middle – Upper Triassic Shublik Formation is an organic-rich heterogeneous carbonate-siliciclastic-phosphatic unit that generated much of the oil in the Prudhoe Bay field and other hydrocarbon accumulations in northern Alaska. A large dataset, including total organic carbon (TOC), X-ray diffraction (XRD), X-ray fluorescence (XRF) and inductively coupled plasma – mass spectrometry (ICP-MS) measurements, has been built from core and outcrop samples of the Shublik, with a focus on the organic-rich intervals. In addition, two core intervals from the Shublik were analyzed using a hyperspectral imaging system in the visible, near-infrared and shortwave-infrared range. Integration of the hyperspectral results with core descriptions, microfacies interpretations, and analytical data is being used to decipher mudstone depositional and diagenetic processes. Petrographic analysis of Upper Triassic organic-rich intervals within the Shublik suggests that the main microfacies is a laminated bioclastic wackestone/packstone that was episodically disrupted by energetic events of variable intensity. These energetic events produced transitional and sparry calcite bioclastic packstone to grainstone intervals, depending on the depth of sediment column disturbance. By using hyperspectral imaging data from the Ikpikpuk core, individual distribution maps for minerals of interest have been generated and corroborate the microfacies interpretations. These maps also illustrate small-scale vertical changes in mineralogy. The laminated bioclastic wackestone/packstone intervals contain less calcite than the adjacent sparry bioclastic packstone to grainstone intervals. The calcite in these laminated intervals is more iron rich. This interpretation suggests that lower iron concentrations should be expected in the disrupted intervals than in nearby laminated intervals. Textural features are also enhanced in the hyperspectral images relative to visual description of the cores by combining the extraction of the average reflectance in the visible part of the electromagnetic spectrum and the depth of the main carbonate-related feature belonging to calcite. Examples noted in the enhanced imagery include low-angle features, calcite grain-size, and the size, shape and orientation of phosphatic nodules. This enhancement is being used to differentiate laminated from sparry bioclastic packstone to grainstone-rich intervals and provides a more comprehensive assessment of the microfacies than is practical by thin-section analysis.

Alaska↗

USGS2019

Variability in results from mineralogical and organic geochemical interlaboratory testing of U. S. Geological Survey shale reference materials

The expansion of unconventional petroleum resource exploration and production in the United States has led to an increase in source rock characterization efforts, particularly related to bulk organic and mineralogical properties. To support the analytical and research needs of industry and academia, as well as internal work, the U.S. Geological Survey (USGS) has collected and prepared shale geochemical reference materials (GRMs) from several major shale petroleum systems in the U.S. The sources of these materials are the Late Cretaceous Boquillas (lower Eagle Ford-equivalent) Formation (roadcut near Del Rio, TX), Late Cretaceous Mancos Shale (outcrop near Delta, CO), Devonian–Mississippian Woodford Shale (outcrop near Ardmore, OK), Late Cretaceous Niobrara Formation (quarry near Lyons, CO), Middle Devonian Marcellus Shale (creek bed in LeRoy, NY), and Eocene Mahogany zone oil shale of the Green River Formation (oil shale mine near Rifle, CO). Of particular interest in the development of these GRMs has been the examination of variability between laboratories and specific methods or instruments in commonly made measurements, including major- and trace-element concentrations, X-ray diffraction (XRD) mineralogy, total organic carbon (TOC) content, and programmed pyrolysis (PP) parameters. For the component concentrations and parameters we measured, the techniques and instrument types included: (1) elemental analysis by X-ray fluorescence, inductively coupled plasma mass spectrometry, and instrumental neutron activation analysis; (2) XRD mineralogy with various preparatory methods (spray drying or micronizing with or without internal standard); (3) TOC by combustion with infrared detection after carbonate removal or the PP approach; (4) PP by Rock-Eval 2 or more recently developed instruments (Rock-Eval 6, Source Rock Analyzer or SRA, and Hydrocarbon Analyzer With Kinetics or HAWK). Overall, the results showed that the selected shales cover a wide range of source rock organic and mineralogical properties. Major- and trace-element chemistry results showed low heterogeneity consistent with other USGS GRMs. Comparison of TOC results showed coefficients of variation (COV) of around 5% and the most consistent organic geochemical results between different laboratories and methods. Arguably the most relevant PP measurement, S2 or kerogen hydrocarbon-generating potential (mg-HC/g-rock), showed a somewhat wider range of variability than TOC (COV ~10%), but was consistent between the three modern instruments and the industry-standard Rock-Eval 2. Major phase mineralogy (mineral concentrations ≥10 wt. %, organic-free basis) were comparable between laboratories, but variability in minor phase identification and quantification was observed. Utilization of these shale GRMs as quality control samples and testing materials is expected to help support analytical and experimental efforts in the continued development of unconventional petroleum resources.

Colorado, Texas, Oklahoma↗

USGS2019

Controls on organic matter distributions in Eocene Lake Uinta, Utah and Colorado

The Green River Formation deposited in Eocene Lake Uinta in the Uinta and Piceance Basins, Utah and Colorado, contains the largest oil shale resource in the world with an estimated 1.53 trillion barrels of oil in-place in the Piceance Basin and 1.32 trillion barrels in the Uinta Basin. The Douglas Creek arch, a slowly subsiding hinge-line between the two basins, created separate deep depocenters with shallow water conditions near the crest of the arch. Lake Uinta was a saline lake throughout its history with a lower saline to hypersaline layer (monimolimnion) and an upper less saline layer (mixolimnion). Most of the organic matter in the Green River Formation was derived primarily from algae that lived in the photic zone of the lake and is very hydrogen-rich and oil-prone. In many modern large and deep lakes, rates of organic matter production are highly variable due to differences in nutrient supply. However, cyclonic circulation often leads to winnowing out organic and mineral matter in the mixolimnion leading to organic and fine-grained mineral matter being deposited in increasing amounts toward hydro-dynamically dead zones in the center of the circulation producing concentric bands of increasing organic matter content. Organic matter transport through the dense, hypersaline monimolimnion may have been facilitated by low density organic matter attaching to more dense clay mineral particles. Most of the oil shale intervals deposited in Lake Uinta display similar patterns in their organic matter distributions, increasing in very regular fashion toward the central areas of the lake’s two depocenters. This concentric feature is particularly prominent in the most laminated oil shale zones. Here, we propose that cyclonic circulation was present in Lake Uinta. Each basin appears to have had its own circulation currents, separated by shallow water conditions near the Douglas Creek arch, as well as one hydro-dynamically dead zone. Sediment gravity flow processes were also very active in some strata of Lake Uinta, leading to the reworking and redepositing of sediments. Two general types of sediment gravity flows are recognized: (1) organic-rich sediment gravity flows that reworked and may have concentrated organic-rich material closer to the two deep depocenters, and (2) sandstone and siltstone-rich organic-poor mass movement deposits that originated on marginal shelves. Mass movements could have been triggered by various natural processes and/or possibly by the movement of dense brines that evolved on marginal shelves and moved along the bottom of the water column toward the deep part of the lake. The uppermost, poorly consolidated sediment layer was incorporated in sediment gravity flows as they moved, and in many cases sediment gravity flows scoured down significantly into the more consolidated underlying sediment producing large rip-up clasts of laminated sediments. Truncation of more than 100 ft occurs at the base of a sequence of sediment gravity flows in one well, indicating a significant incised channel. Coarser-grained sediment gravity flows terminated before reaching the lake’s deepest areas, forming thick concentric buildups of organically-lean sediment near the base of the marginal slopes. Intervals dominated by organic-rich fine-grained sediment gravity flows have tightly concentric bands of increasing organic matter toward the deepest parts of the lake and can be organically richer than the richest laminated intervals. There is some evidence that the hydro-dynamically quiet zones did not always correspond closely to the deepest areas of the lake, extending in some cases into shallower areas.

Colorado, Utah↗

USGS2019

Element cycling in the Middle-Late Triassic Shublik Formation: Mineralization vs. recycling of biolimiting nutrients in an unconventional resource play

The Triassic Shublik Formation in northern Alaska is one of the major source rocks in North America, having generated much of the petroleum in Prudhoe Bay and associated fields. The middle Shublik Formation, the focus of this study, is a highly phosphatic, organic-rich carbonate mudstone interval. Apatite cements can occur as phosphatic peloids, steinkerns, elongate or angular nodules, and shells or shell fragments. We propose a model whereby phosphatization is favored in early diagenetic environments that have low concentrations of dissolved iron relative to reactive organic matter in the pore water sulfate reduction zone.

Alaska↗

USGS2018

Investigation into the effect of heteroatom content on kerogen structure using advanced 13C solid-state nuclear magnetic resonance spectroscopy

To elucidate how different extreme heteroatom concentrations in oil shale kerogen may present and contribute to various structural features, three shale samples, containing kerogen with high oxygen content, low heteroatom content, and high sulfur content, were analyzed using advanced 13 C solid-state nuclear magnetic resonance (NMR) techniques, including multiple cross-polarization/magic angle spinning (multiCP/MAS), dipolar dephasing (multiCP/DD), and 2D 1 H– 13 C heteronuclear correlation (2D HETCOR). We found that oxygen in Estonian kukersite was present mostly in aromatic C–O structures and that nonprotonated aromatic carbons bonded to oxygen and alkyl chains led to more diverse aromatic signal distributions and structures in the kukersite organic matter than were observed in the other shales. The low-heteroatom kerogen present in Australian Glen Davis torbanite had the simplest structural pattern and the lowest aromaticity, despite having a lower atomic H/C ratio than the kerogens present in the other shales. The organic sulfur-rich Ghareb marinite from Jordan contained the highest aromaticity and most diverse alkyl structures among the three shales. 2D HETCOR with 1 H spin diffusion showed that the structural heterogeneity of the Glen Davis kerogen was <1 nm, indicating the preservation of structures present in precursor organic matter. Like previous NMR studies of shales and kerogens, this analysis of organic matter in whole shale samples with unusual heteroatom content demonstrates that structural characteristics in organic matter are not necessarily captured by kerogen typing based solely on elemental ratios (H/C, O/C) or programmed pyrolysis parameters and that NMR provides deeper insights into kerogen structure.

Energy & Fuels↗

USGS2018

Assessment of undiscovered oil and gas resources in the Eagle Ford Group and associated Cenomanian–Turonian Strata, U.S. Gulf Coast, Texas, 2018

Using a geology-based assessment methodology, the U.S. Geological Survey estimated undiscovered, technically recoverable mean resources of 8.5 billion barrels of oil and 66 trillion cubic feet of gas in continuous accumulations in the Upper Cretaceous Eagle Ford Group and associated Cenomanian–Turonian strata in onshore lands of the U.S. Gulf Coast region, Texas.

Louisiana, Texas↗

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↗

USGS2018

Evolution of sulfur speciation in bitumen through hydrous pyrolysis induced thermal maturation of Jordanian Ghareb Formation oil shale

Previous studies on the distribution of bulk sulfur species in bitumen before and after artificial thermal maturation using various pyrolysis methods have indicated that the quantities of reactive (sulfide, sulfoxide) and thermally stable (thiophene) sulfur moieties change following consistent trends under increasing thermal stress. These trends show that sulfur distributions change during maturation in ways that are similar to those of carbon, most clearly illustrated by the increase in aromatic sulfur (thiophenic) as a function of thermal maturity. In this study, we have examined the sulfur moiety distributions of retained bitumen from a set of pre- and post-pyrolysis rock samples in an organic sulfur-rich, calcareous oil shale from the Upper Cretaceous Ghareb Formation. Samples collected from outcrop in Jordan were subjected to hydrous pyrolysis (HP). Sulfur speciation in extracted bitumens was examined using K-edge X-ray absorption near-edge structure (XANES) spectroscopy. The most substantial changes in sulfur distribution occurred at temperatures up to the point of maximum bitumen generation (∼300 °C) as determined from comparison of the total organic carbon content for samples before and after extraction. Organic sulfide in bitumen decreased with increasing temperature at relativ ely low thermal stress (200–300 °C) and was not detected in extracts from rocks subjected to HP at temperatures above around 300 °C. Sulfoxide content increased between 200 and 280 °C, but decreased at higher temperatures. The concentration of thiophenic sulfur increased up to 300 °C, and remained essentially stable under increasing thermal stress (mg-S/g-bitumen basis). The ratio of stable-to-reactive+stable sulfur moieties ([thiophene/(sulfide+sulfoxide+thiophene)], T/SST) followed a sigmoidal trend with HP temperature, increasing slightly up to 240 °C, followed by a substantial increase between 240 and 320 °C, and approaching a constant value (∼0.95) at temperatures above 320 °C. This sulfur moiety ratio appears to provide complementary thermal maturity information to geochemical parameters derived from other analyses of extracted source rocks.

Fuel↗

USGS2017

Extension of the analytical window for characterizing aromatic compounds in oils using a comprehensive suite of high-resolution mass spectrometry techniques and double bond equivalence versus carbon number plot

In this study, comprehensive two-dimensional (2D) gas chromatography–mass spectrometry (GC–MS), atmospheric pressure photoionization (APPI) quadrupole-Orbitrap mass spectrometry (MS), and Fourier transform ion cyclotron resonance mass spectrometry (FT-ICR MS) were used to study the aromatic fractions of crude oil and oil shale pyrolysates (shale oils). The collected data were compared and combined in the double bond equivalence (DBE) versus carbon number plot to obtain a more complete understanding of the composition of the oil fractions. The numbers of peaks observed by each technique followed the order 2D GC–MS < Orbitrap MS < FT-ICR MS. The class distributions observed by Orbitrap MS and FT-ICR MS were similar to each other but different from that observed by 2D GC–MS. The DBE and carbon number distributions of the 2D GC–MS and Orbitrap MS data were similar for crude oil aromatics. The FT-ICR MS plots of DBE and carbon number showed an extended range of higher values relative to the other methods. For the aromatic fraction of an oil shale pyrolysate generated by the Fischer assay, only a few nitrogen-containing compounds were observed by 2D GC–MS but a large number of these compounds were detected by Orbitrap MS and FT-ICR MS. This comparison clearly shows that the data obtained from these three techniques can be combined to more completely characterize oil composition. The data obtained by Orbitrap MS and FT-ICR MS agreed well with one another, and the combined DBE versus carbon number plot provided more complete coverage of compounds present in the fractions. In addition, the chemical structure information provided by 2D GC–MS could be matched with the chemical formulas in the DBE versus carbon number plots, providing information not available in ultrahigh-resolution MS results. It was therefore concluded that the combination of 2D GC–MS, Orbitrap MS, and FT-ICR MS in the DBE versus carbon number space facilitates structural assignment of heavy oil components.

Energy & Fuels↗