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 reexamined. 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.
Unconventional reservoirs (e.g., shales) remain poorly understood, compared to conventional reservoirs, due to their complex compositional and structural anisotropy. These heterogeneities profoundly ...influence petrophysical and geomechanical properties of shales. Current advances in correlative multi-scale and multi-modal 2D/3D imaging provide a tremendous opportunity to image and characterize shales across multiple length scales – from core-to pore-scale. In this study, a Mancos Shale rock sample was characterized across multiple length scales – from a few centimeters to a few nanometers via digital rock analysis using correlative micro 3D X-ray computed tomography (micro-CT), micro 3D X-ray microscopy (micro-XRM), light microscopy (LM), scanning electron microscopy (SEM), and focused ion beam (FIB) – SEM (FIB-SEM) image datasets. These multi-scale/-modal 2D/3D image datasets were then correlated with each other and used to reconstruct digital rock 2D/3D models from which petrophysical properties (porosity and mineralogy) were quantified. Additionally, the SEM/FIB-SEM imaged porosity was compared with bulk porosity measured with the traditional laboratory technique of helium porosimetry. The micro-CT, LM, and (low-resolution) SEM indicated that the investigated Mancos Shale rock sample consisted of interlaminated silt- and mud-rich laminae. The silt-rich laminae were characterized further using micro-XRM, whereas mud-rich laminae were characterized in great detail using high-resolution SEM and FIB-SEM. The SEM and FIB-SEM showed the presence of various fine-grained minerals (clay) and micrometer- and nanometer-sized pores within the mud-rich laminae, whereas micro-XRM showed coarse-grained minerals (quartz) cemented with the mud-rich nanoporous matrix within the silt-rich laminae. Furthermore, the results indicated that micro-fractures significantly contributed to the porosity of the investigated core-plug rock sample.
Correlative multi-scale (core- to pore-scale) and multi-modal 2D/3D imaging of shales. Display omitted
•A correlative multi-scale/-modal 2D/3D imaging workflow was developed and applied to study structural and compositional heterogeneity of shales.•Correlative X-ray, light, and electron microscopy 2D/3D image datasets were used for qualitative/quantitative image analysis.•Digital rock 2D/3D models were used for characterization of shale petrophysical properties, such as porosity and mineralogy.
Arrays of natural opening-mode fractures show systematic patterns in size and spatial arrangement. The controls on these factors are enigmatic, but in many cases the depth of formation appears to be ...critical. Physical, potentially depth-dependent factors that could account for these variations include confining stress, fluid pressure, and strain rate; these factors are common inputs to existing fracture models. However, temperature-dependent chemical processes likely exert an equally important control on patterns, and such processes have not yet been rigorously incorporated into models of fracture formation. Here we present a spring-lattice model that simulates fracturing in extending sedimentary rock beds, while explicitly accounting for cementation during opening of fractures, and for rock failure via both elastic and time-dependent failure criteria. Results illustrate three distinct fracturing behaviors having documented natural analogs, which we here term fracture facies. “Exclusionary macrofracturing” occurs at shallow levels and produces large, widely spaced, uncemented fractures; “multi-scale fracturing” occurs at moderate depth and produces partially cemented fractures having a wide range of sizes and spacings; and “penetrative microfracturing” occurs at great depth and produces myriad narrow, sealed fractures that are closely and regularly spaced. The effect of depth is primarily to accelerate both dissolution and precipitation reactions via increased temperature and porewater salinity; the specific depth range of each fracture facies will vary by host-rock lithology, grain size, strain rate, and thermal history.
•Fracture pattern growth is sensitive to depth of formation.•Physical depth effects are imparted through overburden and confining stresses.•Chemical depth effects are thermally activated and include cementation and corrosion.•Numerical model results enable categorization of fracture patterns into fracture facies.
Lithium isotopes (δ7Li) in coals have been shown to increase with thermal maturity, suggesting preferential release of 6Li from kerogen to porefluids. This has important implications for paleoclimate ...studies based on δ7Li of buried marine carbonates, which may incorporate Li from porefluids during recrystallization. Here, the Li content and isotopic composition of macerals from two coal seams intruded by dikes, were studied as a function of temperature across a thermal gradient into the unmetamorphosed coal. Samples were collected in Colorado (USA) from a Vermejo Fm. coal seam intruded by a mafic-lamprophyre dike and compared to a Dutch Creek No.2 coal seam intruded by felsic-porphyry dike; a potential source of Li-rich fluids.
The Li-content and Li-isotope compositions of coal macerals were measured in situ by Secondary Ion Mass Spectrometry (SIMS). The macerals of the Vermejo coal samples, buried to VRo 0.68% (Tmax = 104 °C), contained <1.5 μg/g Li with an average vitrinite δ7Li of −28.4 ± 1.6‰, while liptinite and inertinite were heavier, averaging −15.4 ± 3.6‰ and − 10.5 ± 3.7‰, respectively. The contact metamorphosed vitrinite/coke showed the greatest change with temperature with δ7Li 18 to 37‰ heavier than the unmetamorphosed vitrinite.
The Dutch Creek coal, buried to VRo 1.15% (Tmax = 147 °C), prior to dike emplacement, may have released Li during burial, as less isotopic change was observed between contact metamorphosed and unmetamorphosed macerals. Overall, Li contents were < 1 μg/g, and the vitrinite in metamorphosed coal had δ7Li values 8 to 21‰ heavier than the unmetamorphosed coal. SIMS measurements on macerals near the dike did not show an increase in Li-content indicative of Li derived from dike fluids, however previous bulk measurements that included silicates showed slightly higher (2-3 μg/g) Li-contents near the dike, suggesting possible Li incorporation from dike fluid into metamorphic silicates. A negative correlation was observed between Li-content and 12C+/30Si+ count ratios, indicating that at metamorphic temperatures Li becomes concentrated in silicates.
Chemical sediments of the lacustrine Wilkins Peak Member of the Eocene Green River Formation potentially preserve detailed paleoclimate information relating to the conditions of their formation and ...preservation within the lake basin during the Early Eocene Climatic Optimum. The Green River Formation comprises the world's largest sodium-carbonate evaporite deposit in the form of trona (Na2CO3⋅NaHCO3⋅2H2O) in the Bridger Basin and nahcolite (NaHCO3) in the neighboring Piceance Creek Basin. Modern analogues suggest that these minerals necessitate the existence of an alkaline source water. Detrital provenance geochronometers suggest that the most likely source for volcanic waters to the Greater Green River Basin is the Colorado Mineral Belt, connected to the basin via the Aspen paleoriver.
Here, we test the hypothesis that magmatic waters from the Colorado Mineral Belt could have supplied the Greater Green River Basin with the alkalinity needed to precipitate sodium-carbonate evaporites that are preserved in the Wilkins Peak Member by numerically simulating the evaporation of modern soda spring waters from northwestern Colorado at various temperature and atmospheric pCO2 conditions. The resulting simulated evaporite sequence is then compared to the mineralogy and textures preserved within the Wilkins Peak Member. Simulated evaporation of Steamboat Springs and Mineral Spring waters produce a close match to core observations and mineralogy. These simulations provide constraints on the salinities at which various minerals precipitated in the Wilkins Peak Member as well as insights into the regional temperature (>15 °C for gaylussite and trona; >27° for pirssonite and trona) and pCO2 conditions (<1200 ppm for gaylussite and trona) during the Early Eocene Climatic Optimum.
•Evaporite mineral deposits reflect parent inflow water chemistry and local climate.•The Green River Formation comprises massive Eocene-aged Na-carbonate deposits.•Green River Formation evaporites are records of regional Eocene climate conditions.•Simulated evaporation of waters can be compared to observed mineral sequences.•Matches between simulations and geologic observations constrain Eocene climate.
Bicarbonate-rich source waters were needed to form the largest sodium carbonate evaporite deposits in the geologic record, the early and middle Eocene Green River trona (NaHCO3·Na2CO3·2H2O) in the ...Bridger basin, Wyoming, and nahcolite (NaHCO3) in the Piceance Creek basin, Colorado. Large modern and Pleistocene trona deposits are associated with magmatic activity and Na+-HCO3−-rich hydrothermal inflow waters, either within the depositional basin (Lake Magadi, Kenya) or at great distances (Searles Lake, California). No evidence exists for magmatic sources of CO2 near the Green River Formation. Several regional volcanic centers were active 300km or more to the north, but drainage reconstructions show that waters from these areas did not discharge into the Green River Formation lakes during evaporite deposition. Alternatively, Na+-HCO3−-rich waters could have drained northwestward from the Colorado Mineral belt to the Bridger basin via the proposed Aspen River. A river originating in the Colorado Mineral belt (Sawatch uplift) could also have provided source waters to the Piceance Creek basin. Field evidence, however, has not yet documented these flow paths, and specific Eocene volcanic centers and hydrothermal source areas have yet to be identified.
Other explanations for the elevated alkalinities needed to form thick sodium carbonate evaporites include accelerated silicate mineral weathering rates during a period of high atmospheric pCO2 and Eocene warmth. Amplified chemical weathering may explain the cluster of sodium carbonate evaporites in the USA and China that are Eocene in age. Another possible source of alkalinity to the Green River lakes is fault-controlled upward migration of a deep sedimentary source of CO2. The large amount of organic matter preserved in the evaporitic Wilkins Peak and Parachute Creek Members raises the possibility that decay of organic matter in Green River lakes could have added sufficient CO2 and alkalinity to produce waters capable of precipitating trona and nahcolite, although such degradation of organic matter has not created hyperalkalinity in modern lakes.
Various flow regimes including Knudsen, transition, slip and viscous flows (Darcy’s law), as applied to flow of natural gas through porous conventional rocks, tight formations and shale systems, are ...investigated. Data from the Mesaverde formation in the United States are used to demonstrate that the permeability correction factors range generally between 1 and 10. However, there are instances where the corrections can be between 10 and 100 for gas flow with high Knudsen number in the transition flow regime, and especially in the Knudsen’s flow regime. The results are of practical interest as gas permeability in porous media can be more complex than that of liquid. The gas permeability is influenced by slippage of gas, which is a pressure-dependent parameter, commonly referred to as Klinkenberg’s effect. This phenomenon plays a substantial role in gas flow through porous media, especially in unconventional reservoirs with low permeability, such as tight sands, coal seams, and shale formations. A higher-order permeability correlation for gas flow called Knudsen’s permeability is studied. As opposed to Klinkenberg’s correlation, which is a first-order equation, Knudsen’s correlation is a second-order approximation. Even higher-order equations can be derived based on the concept used in developing this model. A plot of permeability correction factor versus Knudsen number gives a typecurve. This typecurve can be used to generalize the permeability correction in tight porous media. We conclude that Knudsen’s permeability correlation is more accurate than Klinkenberg’s model especially for extremely tight porous media with transition and free molecular flow regimes. The results from this study indicate that Klinkenberg’s model and various extensions developed throughout the past years underestimate the permeability correction especially for the case of fluid flow with the high Knudsen number.
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► Step-scan photoacoustic infrared spectroscopy experiments were performed on Green River oil shale samples obtained from the Piceance Basin located in Colorado, USA. ► Depth ...profiling experiments indicated that there are changes between layers in the oil shale molecular structure at a length scale of micron. ► Comparisons of the light and dark colored oil shale core samples suggest that the light colored regions have high kerogen content with spectra similar to that of isolated kerogen. The dark colored areas contain more mineral components which include clay minerals, dolomite, calcite, and pyrite. ► The mineral components of the oil shale are important in understanding how the kerogen is “trapped” in the oil shale. Comparing in situ kerogen spectra with spectra from isolated kerogen indicate significant band shifts suggesting important nonbonded molecular interactions between the kerogen and mineral matrix.
Step-scan photoacoustic infrared spectroscopy experiments were performed on Green River oil shale samples obtained from the Piceance Basin located in Colorado, USA. We have investigated the molecular nature of light and dark colored areas of the oil shale core using FTIR photoacoustic step-scan spectroscopy. This technique provided us with the means to analyze the oil shale in its original in situ form with the kerogen–mineral interactions intact. All vibrational bands characteristic of kerogen were found in the dark and light colored oil shale samples confirming that kerogen is present throughout the depth of the core. Depth profiling experiments indicated that there are changes between layers in the oil shale molecular structure at a length scale of micron. Comparisons of spectra from the light and dark colored oil shale core samples suggest that the light colored regions have high kerogen content, with spectra similar to that from isolated kerogen, whereas, the dark colored areas contain more mineral components which include clay minerals, dolomite, calcite, and pyrite. The mineral components of the oil shale are important in understanding how the kerogen is “trapped” in the oil shale. Comparing in situ kerogen spectra with spectra from isolated kerogen indicate significant band shifts suggesting important nonbonded molecular interactions between the kerogen and minerals.
Hydrous pyrolysis is a significant laboratory method to investigate oil generation with the presence of water. Generally, distilled water is utilized in hydrous pyrolysis but not natural formation ...water, which is ubiquitous in oilfields and has elevated salinities. To understand the influence of formation water on hydrocarbon generation and stable carbon isotopic ratios of expelled oils, two series of semi-closed hydrous pyrolysis experiments were conducted in a wide temperature range (250–550 °C) for the type I Green River Shale source rocks using distilled water and formation water with a salinity of 76 g/L. Oil generation peak occurred at a lower temperature (325 °C) in experiments using formation water compared to experiments using distilled water (375 °C), suggesting that the presence of formation water has facilitated the oil generation. The presence of formation water also promoted the hydrocarbon expulsion at lower temperatures in hydrous pyrolysis (325–350 °C). Stable carbon isotopic fractionation between unpyrolyzed kerogen and n-alkanes (n-C17 to n-C28) generated during the primary stage of oil generation (325–375 °C) is minor (<2.6‰) in the presence of formation water, but smaller relative to those in experiments using distilled water at individual temperature points. Positive correlations between pyrolysis temperatures and δ13C ratios of n-C17, n-C18 and n-C19 during oil generation were observed in the experiments using formation water, which is consistent with the knowledge that 12C–12C bonds are more readily to be cleaved than 13C–12C bonds. Outcomes of this study not only support that stable carbon isotopic analysis of n-alkanes is a powerful tool for fingerprinting oil source in sedimentary basins, but also highlight the significance of using formation water as a medium in hydrous pyrolysis to improve the understanding of chemical/isotopic variations during hydrocarbon generation.
•Minor carbon isotopic fractionation between kerogen and n-alkanes in pyrolysis.•Oil generation peak occurs earlier in experiments using formation water.•Formation water facilitated oil generation/expulsion in hydrous pyrolysis.•δ13C of n-C17 to n-C19 correlates temperature in experiments using formation water.
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