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Justin E. Birdwell

Publications and source records attributed to Justin E. Birdwell.

At least 55 records · Page 3Linked to original sources
USGS2022

The role of organic matter diversity on the Re-Os systematics of organic-rich sedimentary units: Insights into the controls of isochron age determinations from the lacustrine Green River Formation

The range of 187 Re/ 188 Os values measured from samples of five organic-rich lacustrine mudstones units in the Eocene Green River Formation in the easternmost Uinta Basin covaries with organic matter diversity driven by changing water column conditions. A set of samples from the Douglas Creek Member has the highest pristane/phytane ratio and lowest β-carotane/ n -C 30 ratio compared to overlying units, indicating deposition in an oxic-anoxic environment with low salinity that would have allowed for the accumulation of a diverse assemblage of aquatic organisms. These samples define the broadest 187 Re/ 188 Os range of 1504. In contrast, samples from the R6 and Mahogany zones possess lower pristane/phytane ratios and higher β-carotane/ n -C 30 ratios indicating deposition in a more restricted lacustrine environment with elevated salinities and alkalinities that would have limited aquatic organic matter diversity. The R6 and Mahogany zones have the narrowest range of 187 Re/ 188 Os values measured in this study of 254.9 and 154.6, respectively. As noted by previous workers, these results suggest that organic matter diversity plays a primary role in determining the range of 187 Re/ 188 Os ratios in a sample set, and in turn the uncertainty of Re-Os age determinations from organic-rich sedimentary rocks. The Re-Os data from the R3 zone and R6 zone yield ages of 49.7 ± 3.4 Ma and 42.0 ± 18 Ma, respectively, which are statistically indistinguishable based on 2σ uncertainty from three previously reported Re-Os age determinations and those provided by 40 Ar/ 39 Ar geochronology of interbedded volcanic ash beds. Although the age uncertainty is high, these findings further highlight the importance of Re-Os geochronology in lacustrine basins, particularly those with thick mudstone successions that lack volcanic ash layers, reliable biostratigraphy , or magnetostratigraphic control. In these cases, even ages with large uncertainties can be useful to constrain burial history and thermal history models. Together, the initial 187 Os/ 188 Os ratios of five sets of samples analyzed from the Uinta Basin define the largest Os isotope stratigraphic record from any lacustrine basin compiled to date and record a shift from a value of 1.40 to 1.48 between the R3 and R4 zones in the lower part of the Parachute Creek Member. This small shift may signify a change in the chemical weathering products that entered the lake preserved 20 to 50 m above the contact between the Douglas Creek and the lower Parachute Creek members during a period when the basin transitioned from a shallow lake with mostly open hydrology to an alkaline lake with more frequent basin restrictions.

Colorado, Utah, Wyoming↗
USGS2022

Evaluating aromatization of solid bitumen generated in the presence and absence of water: Implications for solid bitumen reflectance as a thermal proxy

Geological models for petroleum generation suggest thermal conversion of oil-prone sedimentary organic matter in the presence of water promotes increased liquid saturate yield, whereas absence of water causes formation of an aromatic, cross-linked solid bitumen residue. To test the influence of hydrogen from water, organic-rich (22 wt% total organic carbon , TOC) mudrock samples from the Eocene lacustrine Green River Formation Mahogany zone oil shale were pyrolyzed under hydrous and anhydrous conditions in closed system batch reactors at temperatures between 300 and 370 °C for 72 h. Pre- and post-pyrolysis samples were characterized using petrographic approaches including optical microscopy , reflectance, Raman spectroscopy , and scanning electron and transmission electron microscopy to quantify differences in relative appearance, abundance, and composition of solid bitumen newly generated during the pyrolysis experiments. Petrographic analyses were supplemented by geochemical screening measurements (TOC content and programmed temperature pyrolysis). Results show post-hydrous pyrolysis residues contain lower TOC, are comprised of solid bitumen with greater aromaticity , and have textures indicative of lower viscosities, relative to anhydrous residues from the same temperature pyrolysis conditions. These observations suggest solid bitumen forming from thermal conversion of oil-prone sedimentary organic matter under anhydrous conditions may be less aromatic, although more cross-linked, than solid bitumen forming under hydrous conditions at the same time-temperature combination. To explain these results, we suggest that a radical disproportionation mechanism is favored in the presence of hydrogen donated from water, and that this disproportionation promotes aromatization in the solid residue with concomitant expulsion of saturated hydrocarbons.

International Journal of Coal Geology↗
USGS2022

Bulk and intramolecular carbon isotopic compositions of hydrocarbon gases from laboratory pyrolysis of oil shale of the Green River Formation: Implications for isotope structures of kerogens

Evaluation of intramolecular isotope distributions within organic compounds can provide important insights into gas formation processes and structural properties of gas-generating precursors, such as kerogen, bitumen, and oil, in natural reservoirs. Until recently, little has been known about the intramolecular isotope distributions within kerogens. In this study, we conducted systematic pyrolysis experiments of gas generation from a lacustrine oil shale of the Eocene Green River Formation under hydrous and anhydrous conditions (equivalent maturity or Easy %R o : 0.76 to 3.27 at 310 to 480 °C for 3 to 50 days), measuring gas yields and compositions, as well as bulk and position-specific (PS) carbon isotope compositions. Gas generation processes were investigated in combination with kinetic Monte Carlo (kMC) simulations on a model Type I kerogen based on the chemical structures of oil shale of the Green River Formation. The comparison of our experimental results with kMC modelling indicates a series of β-scission, radical isomerization, and recombination reactions better represent the bulk isotope compositions of propane in the pyrolysis of the oil shale of the Green River Formation, but the ΔC c-t (= δ 13 C cen – δ 13 C ter ) values of propane at Easy %R o > 1.5 can be better simulated by a simple combination of propyl groups with H radicals. Combining our previous works on marine shale of the Woodford Formation and Springfield Coal Member of the Carbondale Formation, PS carbon isotopes of propane indicate that in the lacustrine shales of the Green River Formation and the marine Woodford Shale, propane is sourced from C C bond cleavage, while C O bond cracking generates propane from coal at the initial kerogen cracking stage. At high maturity, the differences of late-stage propane production among the source rocks lead to the different bulk and PS C kinetic isotope effects of propane. Our findings suggest that the δ 13 C at the terminal position of propane precursors is likely up to 3.6‰ higher than at the central position in the Green River kerogen, while they are similar in the marine shale of Woodford Formation. In addition, the δ 13 C at the central position of propyl groups attached to heteroatom compounds is relatively more positive in the Springfield Coal Member of the Carbondale Formation than in Green River kerogen. A comparison of intramolecular C isotopes of propyl groups in the kerogens with their bulk δ 13 C, based on the PS δ 13 C of early-generated propane, contributes to our understanding of heterogeneities of isotopic structures of sedimentary organic matter.

International Journal of Coal Geology↗
USGS2022

Geologic models underpinning the 2018 US Geological Survey assessment of hydrocarbon resources in the Eagle Ford Group and associated Cenomanian–Turonian strata, United States Gulf Coast, Texas

The availability of new geologic and production data has greatly increased since 2010, when the US Geological Survey (USGS) last assessed undiscovered, technically recoverable oil and gas resources in the Cenomanian–Turonian (CT) Eagle Ford Group (EFG) across Texas. This new information facilitated an updated assessment of undiscovered continuous oil and gas resources in the Eagle Ford and associated CT strata. Literature and USGS research data were used to build the geologic models for the assessment units (AUs). The USGS defined six continuous AUs within the EFG: (1) Eagle Ford Marl Continuous Oil, (2) Eagle Ford Marl Continuous Gas, (3) Submarine Plateau-Karnes Trough Continuous Oil, (4) Submarine Plateau-Karnes Trough Continuous Gas, (5) CT Mudstone Continuous Oil, and (6) CT Mudstone Continuous Gas. An additional AU, the CT Slope Continuous Gas AU, was defined but not quantitatively assessed. The boundaries of these AUs were defined by thickness, lithofacies, thermal maturity, regional geology, and the spatial distribution of productive fairways. The resulting total mean estimates for undiscovered, technically recoverable resources for these six AUs are 8.5 billion bbl of oil and 66 trillion ft 3 of gas. These results for both oil and gas resources are within the top five volumes of previously assessed continuous accumulations in the United States and attest to the importance of the EFG and associated CT strata as a significant source of petroleum well into the future.

Texas↗
USGS2021

Multimineral petrophysics of thermally immature Eagle Ford Group and Cretaceous mudstones, U.S. Geological Survey Gulf Coast 1 research wellbore in central Texas

Traditional petrophysical methods to evaluate organic richness and mineralogy using gamma-ray and resistivity log responses are not diagnostic in source rocks. We have developed a deterministic, nonproprietary method to quantify formation variability in total organic carbon (TOC) and three key mudrock mineralogical components of nonhydrocarbon-bearing source rock strata of the Eagle Ford Group by developing a set of log-derived multimineral models calibrated with Fourier transform infrared spectroscopy core data from the research borehole U.S. Geological Survey Gulf Coast 1 West Woodway. We determined that bulk density response is a reliable indicator of organic content in these thermally immature, water-bearing source rocks. Multimineral findings indicate that a high degree of laminae-scale mineralogical heterogeneity exists due to thinly interbedded carbonate cements amid clay-rich mudstone layers. The lower part of the Eagle Ford Group contains the highest average TOC content (4.7 wt%) and the highest average carbonate volume (64.1 vol%), making it the optimal target in thermally mature areas for source-rock potential and hydraulic-fracture placement. In contrast, the uppermost portion of the Eagle Ford Group contains the highest average volume of clay minerals (42.6 vol%), which increases the potential for wellbore stability issues. Petrophysical characterization reveals that porosity is approximately 30% in this relatively uncompacted formation. In this thermally immature source rock, water saturation is nearly 100% and no free hydrocarbons were observed on the resistivity logs. No evidence of borehole ellipticity was observed on the three-arm caliper log, and horizontal stresses are presumed to be directionally uniform in the vicinity of this near-surface wellbore. This shallow wellbore has a temperature gradient of 1.87°F/100 ft (16.3°C/km) and is likely influenced by earth surface heating.

Texas↗
USGS2021

Insights on geochemical, isotopic, and volumetric compositions of produced water from hydraulically fractured Williston Basin oil wells

Tracing produced water origins from wells hydraulically fractured with freshwater-based fluids is sometimes predicated on assumptions that (1) each geological formation contains compositionally unique brine and (2) produced water from recently hydraulically fractured wells resembles fresher meteoric water more so than produced water from older wells. These assumptions are not valid in Williston Basin oil wells sampled in this study. Although distinct average 228 Ra/ 226 Ra ratios were found in water produced from the Bakken and Three Forks Formations, average δ 2 H, δ 18 O, specific gravity, and conductivity were similar but exhibited significant variability across five oil fields within each formation. Furthermore, initial produced water (“flowback”) was operationally defined based on the presence of glycol ether compounds and water from wells that had produced <56% of the amount of fluids injected and sampled within 160 days of fracturing. Flowback unexpectedly exhibited higher temperature, specific gravity, conductivity, δ 2 H, and δ 18 O, but lower oxidation–reduction potential and δ 11 B, relative to the wells thought to be producing formation brines (from wells with a produced-to-injected water ratio [PIWR] > 0.84 and sampled more than 316 days after fracturing). As such, establishing an overall geochemical and isotopic signature of produced water compositions based solely on chemical similarity to meteoric water and formation without the consideration of well treatments, well completion depth, or lateral location across the basin could be misleading if these signatures are assumed to be applicable across the entire basin. These findings have implications for using produced water compositions to understand the interbasin fluid flow and trace sources of hydraulic fracturing fluids.

Montana, North Dakota↗
USGS2021

A review of spatially resolved techniques and applications of organic petrography in shale petroleum systems

This review examines new techniques and applications of organic petrography in source-rock reservoir petroleum systems that have occurred along with development of the global ‘shale revolution’ in energy resources. The review is limited to techniques and instrumentation that provide spatially resolved information, typically at or below microscales, for dispersed organic matter occurring in situ in samples of shale and mudrock. A brief summary of ion beam sample preparation is followed by discussion of the most common analytical techniques and applications. Advantages and limitations of each technique, including requisite sample preparation, types of information generated [e.g., molecular or elemental (isotopic) abundance], sensitivity, and resolution are discussed. In a few cases, techniques not yet applied to organic petrology of shale or mudrock are described (e.g., X-ray photoelectron spectroscopy imaging), in anticipation of near-term future application. The most common in situ techniques applied for characterization of organic matter in shale and mudrock include optical (including fluorescence) and electron microscopies, Raman, fluorescence, and infrared spectroscopies, and surficial measurements via force microscopy. Techniques that show growing application to organic petrography of shale include tip-enhanced photothermal infrared spectroscopy, mass spectrometry imaging, and synchrotron-based spectroscopies, among others. It is anticipated that the future of dispersed organic matter petrography will hold continued development of integrated instrument techniques (e.g., simultaneous or sequential correlative microscopies and/or spectroscopies of the same location), increased instrumental resolution, increased use of multiscale and multimodal organic petrography investigations, and three-dimensional imaging and chemical speciation mapping applications via multiple analytical approaches.

International Journal of Coal Geology↗
USGS2021

Compositional evolution of organic matter in Boquillas Shale across a thermal gradient at the single particle level

The molecular composition of petroliferous organic matter and its compositional evolution throughout thermal maturation provides insight for understanding petroleum generation. This information is critical for understanding hydrocarbon resources in unconventional reservoirs, as source rock organic matter is highly dispersed, in contact with the surrounding mineral matrix, and may occur as multiple organic matter maceral types. Here, Raman spectroscopy and optical microscopy approaches were applied to a marginally mature (vitrinite reflectance ~0.5%) sample of the Late Cretaceous Boquillas Shale before and after hydrous pyrolysis (HP) at 300 °C and 330 °C for 72 h. This analytical approach allowed for correlative examination of micro-scale changes in organic matter compositional properties (e.g., aromaticity) for a variety of organic matter macerals across a thermal gradient (from marginally mature into the late oil/wet gas window) at the single particle level. Results indicate that while the examined amorphous organic matter, solid bitumen, and vitrinite particles exhibit different aromatic signatures in the unheated shale, they effectively progress along a similar trend through composition space with thermal maturation. Examined inertinite fragments were generally insensitive to the applied thermal stress, reinforcing the idea that reservoir temperature may be secondary for dictating the molecular composition of inertinite. Additional analysis of Raman spectra for individual organic matter macerals was performed using multivariate curve resolution (MCR) and correlation of standard Raman and reflectance-derived thermal maturity proxies against MCR parameters shows consistent trends. This trend suggests that MCR may be a fast and statistically robust method for extracting compositional information from Raman spectra of sedimentary organic matter, and can be used to construct thermal maturity relationships. These findings inform our understanding of how different petroliferous organic matter maceral types evolve throughout thermal reactions and further demonstrate that Raman spectroscopy combined with petrographic analysis can provide complementary estimates of organic matter composition and thermal maturity.

International Journal of Coal Geology↗
USGS2021

Water–rock interaction and the concentrations of major, trace, and rare earth elements in hydrocarbon-associated produced waters of the United States

Studies of co-produced waters from hydrocarbon extraction across multiple energy-producing basins have generally focused on major ions or a few select tracers, and studies that examine trace elements and involve laboratory experiments have generally been basin specific. Here, new perspective is sought through a broad analysis of concentration data for 26 elements from three hydrocarbon well types using the U.S. Geological Survey National Produced Waters Geochemical Database (v2.3). Those data are compared to leachates (water, hydrochloric acid, and artificial brine) from 12 energy-resource related shales from across the United States. Both lower pH and higher ionic strength were associated with greater concentrations of many trace elements in produced waters. However, individual effects were difficult to distinguish because higher ionic strengths drive decreases in pH. Water–rock interactions in the leaching experiments generally replicated produced water concentrations for trace elements including Al, As, Cd, Co, Cu, Mo, Ni, Pb, Sb, Si, and Zn. Enhanced middle rare earth element (REE) mobilization relative to shale REE content occurred with low pH leachates. Produced water concentrations of Li, Sr, and Ba were not replicated by the leaching experiments. Patterns of high Li, Sr, and Ba concentrations and ratios relative to other elements across produced waters types indicate controls on these elements in many settings related to pore space pools of salts, brines, and ion-exchange sites affected by diagenetic processes. The size of those pools is diluted and masked by other water–rock interaction processes at the water–rock ratios necessitated by laboratory experiments. The results broadly link water–rock interaction processes and environmental patterns across a wide variety of produced waters and host formations and thus provide context for trace element data from other environmental and laboratory studies of such waters.

Environmental Science: Processes & Impacts↗
USGS2020

Assessment of undiscovered oil and gas resources in the Upper Cretaceous Austin Chalk and Tokio and Eutaw Formations, U.S. Gulf Coast, 2019

Using a geology-based assessment methodology, the U.S. Geological Survey estimated undiscovered, technically recoverable mean resources of 6.9 billion barrels of oil and 41.5 trillion cubic feet of natural gas in conventional and continuous accumulations in the Upper Cretaceous Austin Chalk and Tokio and Eutaw Formations onshore and in State waters of the U.S. Gulf Coast region.

Alabama, Arkansas, Louisiana, Mississippi, Oklahom↗
USGS2020

Assessment of water and proppant quantities associated with petroleum production from the Eagle Ford Group, Gulf Coast, Texas, 2019

Building on a geology-based assessment of undiscovered, technically recoverable petroleum resources in the Eagle Ford Group in south Texas, the U.S. Geological Survey has estimated the required water and proppant demands and formation water production volumes associated with possible future development of these petroleum resources. The results of the water and proppant assessment are presented here, along with related drilling information and relevant water budget volumes for the region.

Texas↗