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Michael Lewan

Publications and source records attributed to Michael Lewan.

12 recordsLinked to original sources
USGS2020

Position-specific distribution of hydrogen isotopes in natural propane: Effects of thermal cracking, equilibration and biodegradation

Intramolecular isotope distributions, including isotope clumping and position specific fractionation, can provide proxies for the formation temperature and formation and destruction pathways of molecules. In this study, we explore the position-specific hydrogen isotope distribution in propane. We analyzed propane samples from 10 different petroleum systems with high-resolution molecular mass spectrometry. Our results show that the hydrogen isotope fractionation between central and terminal positions of natural propanes ranges from −102‰ to +205‰, a much larger range than that expected for thermodynamic equilibrium at their source and reservoir temperatures (36–63‰). Based on these findings, we propose that the hydrogen isotope structure of catagenic propane is largely controlled by irreversible processes, expressing kinetic isotope effects (KIEs). Kinetic control on hydrogen isotope composition of the products of thermal cracking is supported by a hydrous pyrolysis experiment using the Woodford Shale as substrate, in which we observed isotopic disequilibrium in the early stage of pyrolysis. We make a more general prediction of KIE signatures associated with kerogen cracking by simulating this chemistry in a kinetic Monte Carlo model for different types of kerogens. In contrast, unconventional shale fluids or hot conventional reservoirs contain propane with an isotopic structure close to equilibrium, presumably reflecting internal and/or heterogeneous exchange during high temperature storage (ca. 100–150 °C). In relatively cold (<100 °C) conventional gas accumulations, propane can discharge from its source to a colder reservoir, rapidly enough to preserve disequilibrium signatures even if the source rock thermal maturity is high. These findings imply that long times at elevated temperatures are required to equilibrate the hydrogen isotopic structure of propane in natural gas host rocks and reservoirs. We further defined the kinetics of propane equilibration through hydrogen isotope exchange experiments under hydrous conditions; these experiments show that hydrogen in propane is exchangeable over laboratory timescales when exposed to clay minerals such as kaolinite. This implies rather rapid transfer of propane from sources to cold reservoirs in some of the conventional petroleum systems. Propane is also susceptible to microbial degradation in both oxic and anoxic environments. Biodegradation of propane in the Hadrian and Diana Hoover oil fields (Gulf of Mexico) results in strong increases in central-terminal hydrogen isotope fractionation. This reflects preferential attack on the central position, consistent with previous studies.

Geochimica et Cosmochimica Acta↗
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↗
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↗
USGS2018

Position-specific 13C distributions within propane from experiments and natural gas samples

Site-specific carbon isotope measurements of organic compounds potentially recover information that is lost in a conventional, ‘bulk’ isotopic analysis. Such measurements are useful because isotopically fractionating processes may have distinct effects at different molecular sites, and thermodynamically equilibrated populations of molecules tend to concentrate heavy isotopes in one molecular site versus another. Most recent studies of site-specific 13 C in organics use specialized Nuclear Magnetic Resonance (NMR) techniques or complex chemical degradations prior to mass spectrometric measurements. Herein we present the first application of a new mass spectrometric technique that reconstructs the site-specific carbon isotope composition of propane based on measurements of the 13 C/ 12 C ratios of two or more fragment ions that sample different proportions of the terminal and central carbon sites. We apply this method to propane from laboratory experiments and natural gas samples to explore the relationships between site-specific carbon isotope composition, full-molecular δ 13 C, thermal maturity, and variation in organic matter precursors. Our goal is to advance the understanding of the sources and histories of short-chain alkanes within geologic systems. Our findings suggest that propane varies in its site-specific carbon isotope structure, which is correlated with increasing thermal maturity, first increasing in terminal position δ 13 C and then increasing in both center and terminal position δ 13 C. This pattern is observed in both experimental and natural samples, and is plausibly explained by a combination of site-specific, temperature-dependent isotope effects associated with conversion of different precursor molecules (kerogen, bitumen, and/or oil) to propane, differences in site-specific isotopic contents of those precursors, and possibly distillation of reactive components of those precursors with increasing maturity. We hypothesize that the largest changes in site-specific isotopic content of propane occur when bitumen and/or oil replace kerogen as the dominant precursors. If correct, this phenomenon could have significant utility for understanding gas generation in thermogenic petroleum systems.

Geochimica et Cosmochimica Acta↗
USGS2018

Equilibrium and non-equilibrium controls on the abundances of clumped isotopologues of methane during thermogenic formation in laboratory experiments: Implications for the chemistry of pyrolysis and the origins of natural gases

Multiply isotopically substituted molecules (‘clumped’ isotopologues) can be used as geothermometers because their proportions at isotopic equilibrium relative to a random distribution of isotopes amongst all isotopologues are functions of temperature. This has allowed measurements of clumped-isotope abundances to be used to constrain formation temperatures of several natural materials. However, kinetic processes during generation, modification, or transport of natural materials can also affect their clumped-isotope compositions. Herein, we show that methane generated experimentally by closed-system hydrous pyrolysis of shale or nonhydrous pyrolysis of coal yields clumped-isotope compositions consistent with an equilibrium distribution of isotopologues under some experimental conditions (temperature–time conditions corresponding to ‘low,’ ‘mature,’ and ‘over-mature’ stages of catagenesis), but can have non-equilibrium (i.e., kinetically controlled) distributions under other experimental conditions (‘high’ to ‘over-mature’ stages), particularly for pyrolysis of coal. Non-equilibrium compositions, when present, lead the measured proportions of clumped species to be lower than expected for equilibrium at the experimental temperature, and in some cases to be lower than a random distribution of isotopes (i.e., negative Δ 18 values). We propose that the consistency with equilibrium for methane formed by relatively low temperature pyrolysis reflects local reversibility of isotope exchange reactions involving a reactant or transition state species during demethylation of one or more components of kerogen. Non-equilibrium clumped-isotope compositions occur under conditions where ‘secondary’ cracking of retained oil in shale or wet gas hydrocarbons (C 2-5 , especially ethane) in coal is prominent. We suggest these non-equilibrium isotopic compositions are the result of the expression of kinetic isotope effects during the irreversible generation of methane from an alkyl precursor. Other interpretations are also explored. These findings provide new insights into the chemistry of thermogenic methane generation, and may provide an explanation of the elevated apparent temperatures recorded by the methane clumped-isotope thermometer in some natural gases. However, it remains unknown if the laboratory experiments capture the processes that occur at the longer time and lower temperatures of natural gas formation.

Geochimica et Cosmochimica Acta↗
USGS2018

Understanding and distinguishing reflectance measurements of solid bitumen and vitrinite using hydrous pyrolysis: Implications to petroleum assessment

Solid bitumen is a common organic component of thermally mature shales and typically is identified by embayment against euhedral mineral terminations and by groundmass textures. However, because these textures are not always present, solid bitumen can be easily misidentified as vitrinite. Hydrous-pyrolysis experiments (72 hr, 300°C–360°C) on shale and coal samples show that solid-bitumen reflectance ( BR o ) in shales is less responsive to thermal stress than vitrinite reflectance ( R o ) in coal. This effect is most pronounced at lower experimental temperatures (300°C–320°C), whereas reflectance changes are more similar at higher temperatures (340°C–360°C). Neither a “vitrinite-like” maceral nor “suppressed vitrinite” was identified or measured in our sample set; instead, the experiments show that solid bitumen matures slower than vitrinite. The data may explain some reports of “ R o suppression,” particularly at lower thermal maturity ( R o ≤ 1.0%), as a simple case of solid bitumen being mistaken for vitrinite. Further, the experimental results confirm previous empirical observations that R o and BR o are more similar at higher maturities ( R o > 1.0%). It is suggested that R o suppression, commonly reported from upper Paleozoic marine shales of early to midoil window maturity, is a misnomer. This observation has important implications to petroleum exploration models and resource assessment, because it may change interpretations for the timing and spatial locations of kerogen maturation and petroleum generation.

AAPG Bulletin↗
USGS2017

Reevaluation of thermal maturity and stages of petroleum formation of the Mississippian Barnett Shale, Fort Worth Basin, Texas

New data including measured reflectance (% R o ), programmed open-system pyrolysis data, and kerogen elemental analyses obtained on the Mississippian Barnett Shale in the Fort Worth Basin, Texas, indicate that secondary-gas generation starts at 1.5% R o and not at the previously prescribed 1.1% R o . Oil-cracking kinetic parameters derived from pyrolysis experiments in the presence and absence of water indicate that secondary-gas generation will not occur at a thermal maturity as low as 1.1% R o and requires a minimum thermal maturity of 1.5% R o . This difference is especially important in using the Barnett Shale as an analog for evaluating other possible shale-gas plays. The new reflectance measurements have a good relationship with hydrogen indices (HIs) and compare well with other published data sets. However, the relationship does not compare well with the previously published data used to prescribe 1.1% R o as the start of secondary-gas generation in the Barnett Shale. This discrepancy is attributed to differences in measured % R o values and not attributed to differences in the HI values. Lack of publicly available information on the previously reported % R o values makes it difficult to ascertain the reason for their lower values. These lower % R o values also have impact on the previously prescribed relationship for estimating % R o from the temperature at maximum yield by programmed open-system pyrolysis ( T max ). As a result, the new data do not agree with a previously described relationship, and the considerable scatter makes the new relationship unreliable. However, the relationship between the HI and % R o has less scatter, which indicates that HI offers a better proxy in calculating % R o than T max for the Barnett Shale. Comparison of various programmed open-system pyrolysis methods (i.e., Rock-Eval II, Rock-Eval 6, Source Rock Analyzer, and Hawk) indicates that variations in HI are within ±10% of one another. An HI of at least 44 mg/g total organic carbon is prescribed as a more certain limit for the start of secondary-gas generation and prospective in situ gas-shale accumulations.

Texas↗
USGS2017

Determining quantity and quality of retained oil in mature marly chalk and marlstone of the Cretaceous Niobrara Formation by low-temperature hydrous pyrolysis

Low-temperature hydrous pyrolysis (LTHP) at 300°C (572°F) for 24 h released retained oils from 12- to 20-meshsize samples of mature Niobrara marly chalk and marlstone cores. The released oil accumulated on the water surface of the reactor, and is compositionally similar to oil produced from the same well. The quantities of oil released from the marly chalk and marlstone by LTHP are respectively 3.4 and 1.6 times greater than those determined by tight rock analyses (TRA) on aliquots of the same samples. Gas chromatograms indicated this difference is a result of TRA oils losing more volatiles and volatilizing less heavy hydrocarbons during collection than LTHP oils. Characterization of the rocks before and after LTPH by programmable open-system pyrolysis (HAWK) indicate that under LTHP conditions no significant oil is generated and only preexisting retained oil is released. Although LTHP appears to provide better predictions of quantity and quality of retained oil in a mature source rock, it is not expected to replace the more time and sample-size efficacy of TRA. However, LTHP can be applied to composited samples from key intervals or lithologies originally recognized by TRA. Additional studies on duration, temperature, and sample size used in LTHP may further optimize its utility.

Conference Paper↗
USGS2016

Sulfur species in source rock bitumen before and after hydrous pyrolysis determined by X-ray absorption near-edge structure

The sulfur speciation of source rock bitumen (chloroform-extractable organic matter in sedimentary rocks) was examined using sulfur K-edge X-ray absorption near-edge structure (XANES) spectroscopy for a suite of 11 source rocks from around the world. Sulfur speciation was determined for both the native bitumen in thermally immature rocks and the bitumen produced by thermal maturation of kerogen via hydrous pyrolysis (360 &deg;C for 72 h) and retained within the rock matrix. In this study, the immature bitumens had higher sulfur concentrations than those extracted from samples after hydrous pyrolysis. In addition, dramatic and systematic evolution of the bitumen sulfur moiety distributions following artificial thermal maturation was observed consistently for all samples. Specifically, sulfoxide sulfur (sulfur double bonded to oxygen) is abundant in all immature bitumen samples but decreases substantially following hydrous pyrolysis. The loss in sulfoxide sulfur is associated with a relative increase in the fraction of thiophene sulfur (sulfur bonded to aromatic carbon) to the extent that thiophene is the dominant sulfur form in all post-pyrolysis bitumen samples. This suggests that sulfur moiety distributions might be used for estimating thermal maturity in source rocks based on the character of the extractable organic matter.

Energy & Fuels↗
USGS2014

Thermal-maturity limit for primary thermogenic-gas generation from humic coals as determined by hydrous pyrolysis

Hydrous-pyrolysis experiments at 360°C (680°F) for 72 h were conducted on 53 humic coals representing ranks from lignite through anthracite to determine the upper maturity limit for hydrocarbon-gas generation from their kerogen and associated bitumen (i.e., primary gas generation). These experimental conditions are below those needed for oil cracking to ensure that generated gas was not derived from the decomposition of expelled oil generated from some of the coals (i.e., secondary gas generation). Experimental results showed that generation of hydrocarbon gas ends before a vitrinite reflectance of 2.0%. This reflectance is equivalent to Rock-Eval maximum-yield temperature and hydrogen indices (HIs) of 555°C (1031°F) and 35 mg/g total organic carbon (TOC), respectively. At these maturity levels, essentially no soluble bitumen is present in the coals before or after hydrous pyrolysis. The equivalent kerogen atomic H/C ratio is 0.50 at the primary gas-generation limit and indicates that no alkyl moieties are remaining to source hydrocarbon gases. The convergence of atomic H/C ratios of type-II and -I kerogen to this same value at a reflectance of indicates that the primary gas-generation limits for humic coal and type-III kerogen also apply to oil-prone kerogen. Although gas generation from source rocks does not exceed vitrinite reflectance values greater than , trapped hydrocarbon gases can remain stable at higher reflectance values. Distinguishing trapped gas from generated gas in hydrous-pyrolysis experiments is readily determined by of the hydrocarbon gases when a -depleted water is used in the experiments. Water serves as a source of hydrogen in hydrous pyrolysis and, as a result, the use of -depleted water is reflected in the generated gases but not pre-existing trapped gases.

AAPG Bulletin↗
USGS2006

Petroleum system modeling capabilities for use in oil and gas resource assessments

Summary: Petroleum resource assessments are among the most highly visible and frequently cited scientific products of the U.S. Geological Survey. The assessments integrate diverse and extensive information on the geologic, geochemical, and petroleum production histories of provinces and regions of the United States and the World. Petroleum systems modeling incorporates these geoscience data in ways that strengthen the assessment process and results are presented visually and numerically. The purpose of this report is to outline the requirements, advantages, and limitations of one-dimensional (1-D), two-dimensional (2-D), and three-dimensional (3-D) petroleum systems modeling that can be applied to the assessment of oil and gas resources. Primary focus is on the application of the Integrated Exploration Systems (IES) PetroMod? software because of familiarity with that program as well as the emphasis by the USGS Energy Program on standardizing to one modeling application. The Western Canada Sedimentary Basin (WCSB) is used to demonstrate the use of the PetroMod? software. Petroleum systems modeling quantitatively extends the 'total petroleum systems' (TPS) concept (Magoon and Dow, 1994; Magoon and Schmoker, 2000) that is employed in USGS resource assessments. Modeling allows integration of state-of-the-art analysis techniques, and provides the means to test and refine understanding of oil and gas generation, migration, and accumulation. Results of modeling are presented visually, numerically, and statistically, which enhances interpretation of the processes that affect TPSs through time. Modeling also provides a framework for the input and processing of many kinds of data essential in resource assessment, including (1) petroleum system elements such as reservoir, seal, and source rock intervals; (2) timing of depositional, hiatus, and erosional events and their influences on petroleum systems; (3) incorporation of vertical and lateral distribution and lithologies of strata that compose the petroleum systems; and (4) calculations of pressure-volume-temperature (PVT) histories. As digital data on petroleum systems continue to expand, the models can integrate these data into USGS resource assessments by building and displaying, through time, areas of petroleum generation, migration pathways, accumulations, and relative contributions of source rocks to the hydrocarbon components. IES PetroMod? 1-D, 2-D, and 3-D models are integrated such that each uses the same variables for petroleum systems modeling. 1-D burial history models are point locations, mainly wells. Maps and cross-sections model geologic information in two dimensions and can incorporate direct input of 2-D seismic data and interpretations using various formats. Both 1-D and 2-D models use data essential for assessments and, following data compilation, they can be completed in hours and retested in minutes. Such models should be built early in the geologic assessment process, inasmuch as they incorporate the petroleum system elements of reservoir, source, and seal rock intervals with associated lithologies and depositional and erosional ages. The models can be used to delineate the petroleum systems. A number of 1-D and 2-D models can be constructed across a geologic province and used by the assessment geologists as a 3-D framework of processes that control petroleum generation, migration, and accumulation. The primary limitation of these models is that they only represent generation, migration, and accumulation in two dimensions. 3-D models are generally built at reservoir to basin scales. They provide a much more detailed and realistic representation of petroleum systems than 1-D or 2-D models because they portray more fully the temporal and physical relations among (1) burial history; (2) lithologies and associated changes through burial in porosity, permeability, and compaction; (3) hydrodynamic effects; and (4) other parameters that influence petroleum gen

Open-File Report↗