Geology topics

Aaron M. Jubb

Publications and source records attributed to Aaron M. Jubb.

At least 37 records · Page 2Linked to original sources

USGS2023

Evaluation of portable Raman spectroscopic analysis for source-rock thermal maturity assessments on bulk crushed rock

This study presents a simplified method and empirical relationships for determining organic matter thermal maturity using a portable Raman system equipped with a 785 nm laser, for analysis of crushed, whole-rock samples. Suites of rocks represented by shale and coal samples with various mineralogical composition, thermal maturity, and total organic carbon (TOC) were used to test the method and build correlations between Raman band separation (RBS) values and traditional thermal maturity indicators, organic matter reflectance (Ro), and programmed temperature pyrolysis (Tmax) values. A set of disparate shale samples, where both vitrinite and solid bitumen reflectance values were reported, have Ro values that range from 0.40 to 4.62%. Above 3.35% Ro, the corresponding RBS values plateau at ∼290 cm−1, thus correlations were evaluated with a linear regression (R2 = 0.96) between 0.40 and 3.35% Ro. Shale samples with Ro < 2% and Tmax < 551 were also used to correlate Tmax and RBS, yielding a linear correlation with an R2 of 0.94. For the coal data set, Ro values range from 1.21 to 4.08% and correlated RBS values plateau at ∼250 cm−1 above Ro = 3.0%, suggesting its correlative application below this maturity level. Several sample preparation methods were tested on cuttings material and standard deviation values for RBS were minimized by washing, drying, and hand crushing the material to pass through a 40-mesh sieve, although less preparation can still yield reliable results. The high degrees of correlation between whole-rock RBS data and two thermal maturity indicators demonstrate the utility of this approach for generating source rock thermal maturity data from minimally processed, whole-rock samples which could easily be applied in field or laboratory settings.

International Journal of Coal Geology↗

USGS2023

Mapping ancient sedimentary organic matter molecular structure at nanoscales using optical photothermal infrared spectroscopy

Elucidating the molecular structure of sedimentary organic matter (SOM) is key to understanding petroleum generation processes, as well as ancient sedimentary environments. SOM structure is primarily controlled by biogenic source material (e.g., marine vs. terrigenous), depositional conditions, and subsurface thermal history. Additional factors, e.g., strain, may also impact the molecular structure of SOM. Multiple spatially resolved approaches exist for in situ evaluation of SOM, including Raman and infrared spectroscopies, as well as mass spectrometric methods. While these methods have enabled increased understanding of the occurrence and distribution of SOM functional groups, they suffer from disadvantages including low spatial resolution (infrared spectroscopy), limited molecular information (Raman spectroscopy), and sample destruction (mass spectrometric methods). Recent technological advances have resulted in infrared spectrometers capable of breaking the Abbe diffraction limit, greatly increasing the spatial resolutions accessible for an infrared measurement. Here we utilize optical photothermal infrared spectroscopy (O-PTIR) to record maps of functional group distributions at 500 nm spatial resolution in Tasmanites (algal microfossils) from the Upper Devonian Ohio Shale. These data allow for discrimination between Tasmanites , adjacent SOM, and fine-grained minerals. Additionally, functional group distributions within Tasmanites were found to be generally homogenous, although slight variations exist between the body and fold apices (zones of greatest deformation) which may indicate strain-induced chemical reactions. The data presented here represent the first application of O-PTIR to study SOM, highlighting the promise of this analytical approach for future studies evaluating the molecular composition of geologic materials at sub-micron scales.

Organic Geochemistry↗

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

Maturation study of vitrinite in carbonaceous shales and coals: Insights from hydrous pyrolysis

The presence of vitrinite in sedimentary rocks of post-Silurian age allows its reflectance to be used to estimate the thermal maturation of organic matter in petroleum systems. Increasing reflectance of vitrinite, which is primarily driven by aromaticity, depends primarily on the time and temperature attributes of its evolutionary pathway. This study evaluated carbonaceous shales proximal to coal measures and coal samples via isothermal hydrous pyrolysis (HP) to compare differences in the maturation pathways of vitrinite. Sample residues were analysed via vitrinite reflectance (VRo), geochemical screening tests (organic carbon and programmed temperature pyrolysis), and infrared spectroscopy. The study included samples from Indian and North American basins, to observe differences in vitrinite evolution with respect to enclosing mineral matrix, starting degree of aromaticity, organic matter types, stratigraphic age, and depositional environment. The organic content of HP residues shows an intuitive response to the thermal stress of HP, e.g., a general depletion of total organic carbon (TOC) content, pyrolyzate (S2), and hydrogen index with increasing HP temperature. Infrared proxies including C-factor and CH2/CH3 generally decrease with increasing thermal maturity indicating loss of O via CO2 generation and the thermal cracking of aliphatic organic matter. Tmax, production index (PI), and VRo show intuitive increasing values with respect to HP temperature. The least mature sample (0.48 ± 0.05% VRo) generally experienced the maximum change in these parameters during maturation, whereas the most mature sample (0.99 ± 0.06% VRo) generally showed the least change. This observation is consistent with higher kinetic barriers to reaction in more aromatic vitrinite which contains higher bond dissociation energies. Devolatilization of vitrinite during HP causes formation of gas evacuation vacuoles and contraction cracks in the vitrinite grains of both coal and carbonaceous shale. Similarities in vitrinite response to HP between coal and carbonaceous shale suggest that thermal evolution of the vitrinite maceral is principally controlled by inherent rate-limiting kinetic parameters related to its molecular structure. Whereas, the stratigraphic age, sedimentary environment, surrounding organic matter, lithology, and catalysis by mineral composition have less effect. To further improve our understanding of vitrinite aromatization and kinetic parameters, future studies of vitrinite reflectance thermal evolution with temperature should include coal and carbonaceous shale from the same stratigraphic section and extant woody tissue from modern vascular plants.

International Journal of Coal Geology↗

USGS2022

Relating systematic compositional variability to the textural occurrence of solid bitumen in shales

This study presents Raman spectroscopic data paired with scanning electron microscopy (SEM) images to assess solid bitumen composition as a function of solid bitumen texture and association with minerals. A series of hydrous pyrolysis experiments (1–103 days, 300–370 °C) using a low maturity (0.25% solid bitumen reflectance, BR o ), high total organic carbon [(TOC), 14.0 wt%] New Albany Shale sample as the starting material yielded pyrolysis residues designed to evaluate the evolution of solid bitumen aromaticity with increasing temperature and heating duration. Solid bitumen was analyzed by Raman spectroscopy wherein point data were collected from accumulations that ranged in size and degree of association with the mineral matrix. Raman spectroscopy results show that with increasing temperature and experimental duration, solid bitumen aromaticity increases and compositional variability decreases. With regards to texture and composition, coarser-grained solid bitumen (>1.3 μm from nearest mineral grain) has consistently higher, but less variable aromaticity than thinner, wispy solid bitumen which is more intimately associated with the mineral matrix. Collocated scanning electron microscope images were used to provide qualitative assessments of porosity hosted by the organic matter. These paired data sets suggest that solid bitumen porosity development and molecular composition are linked, and these parameters are related to the textural relationships of the organic matter within the whole rock. These results are discussed with perspective towards understanding how rock fabric and texture can influence organic matter evolution during thermal maturation of organic-rich marine shales and inform our broader understanding of these important energy resources.

International Journal of Coal Geology↗

USGS2022

Molecular mechanisms of solid bitumen and vitrinite reflectance suppression explored using hydrous pyrolysis of artificial source rock

The most commonly used parameter for thermal maturity calibration in basin modelling is mean random vitrinite reflectance (R o ). However, R o suppression has been noted in samples containing a high proportion of liptinite macerals. This phenomenon has been demonstrated empirically using hydrous pyrolysis of artificial source rock containing various proportions of thermally immature Wyodak-Anderson coal and liptinite-rich kerogen from the Parachute Creek Member of the Green River Formation. Analysis of samples pyrolyzed at 330 °C for 72 h demonstrates that R o values of both vitrinite and solid bitumen are suppressed in rocks containing liptinite-rich kerogen. Raman and micro-Fourier transform infrared (µ-FTIR) analyses were performed to investigate the mechanisms of suppression. Raman maturity proxies show decreased aromaticity in samples with suppressed R o , particularly in solid bitumen, with aromaticity decreasing as the proportion of liptinite increases. The µ-FTIR proxy for aliphatic chain length and/or branching ratio is static in solid bitumen, yet increases slightly in vitrinite as the liptinite proportion increases. These spectroscopic results suggest slightly different suppression mechanisms for vitrinite and solid bitumen, with reduced C C bond cleavage and marginally reduced aromaticity in vitrinite with suppressed R o , and strongly reduced aromaticity and C C bond cleavage in solid bitumen with suppressed R o . These results support the hypothesis that the generation of free radicals during maturation slows aromatization and highlight the disadvantages of using solid bitumen R o for maturity calibration in liptinite-rich samples. Furthermore, our results indicate that use of Raman data obtained from liptinite-rich samples may also result in suppressed maturity indicators, particularly if the macerals are not identified prior to analysis.

Organic Geochemistry↗

USGS2022

Dissolved organic matter within oil and gas associated wastewaters from U.S. unconventional petroleum plays: Comparisons and consequences for disposal and reuse

Wastewater generated during petroleum extraction (produced water) may contain high concentrations of dissolved organics due to their intimate association with organic-rich source rocks, expelled petroleum, and organic additives to fluids used for hydraulic fracturing of unconventional (e.g., shale) reservoirs. Dissolved organic matter (DOM) within produced water represents a challenge for treatment prior to beneficial reuse. High salinities characteristic of produced water, often 10× greater than seawater, coupled to the complex DOM ensemble create analytical obstacles with typical methods. Excitation-emission matrix spectroscopy (EEMS) can rapidly characterize the fluorescent component of DOM with little impact from matrix effects. We applied EEMS to evaluate DOM composition in 18 produced water samples from six North American unconventional petroleum plays. Represented reservoirs include the Eagle Ford Shale (Gulf Coast Basin), Wolfcamp/Cline Shales (Permian Basin), Marcellus Shale and Utica/Point Pleasant (Appalachian Basin), Niobrara Chalk (Denver-Julesburg Basin), and the Bakken Formation (Williston Basin). Results indicate that the relative chromophoric DOM composition in unconventional produced water may distinguish different lithologies, thermal maturity of resource types (e.g., heavy oil vs. dry gas), and fracturing fluid compositions, but is generally insensitive to salinity and DOM concentration. These results are discussed with perspective toward DOM influence on geochemical processes and the potential for targeted organic compound treatment for the reuse of produced water.

Colorado, Montana, Nebraska, New York, North Dakot↗

USGS2021

Machine learning can assign geologic basin to produced water samples using major ion geochemistry

Understanding the geochemistry of waters produced during petroleum extraction is essential to informing the best treatment and reuse options, which can potentially be optimized for a given geologic basin. Here, we used the US Geological Survey’s National Produced Waters Geochemical Database (PWGD) to determine if major ion chemistry could be used to classify accurately a produced water sample to a given geologic basin based on similarities to a given training dataset. Two datasets were derived from the PWGD: one with seven features but more samples (PWGD7), and another with nine features but fewer samples (PWGD9). The seven-feature dataset, prior to randomly generating a training and testing (i.e., validation) dataset, had 58,541 samples, 20 basins, and was classified based on total dissolved solids (TDS), bicarbonate (HCO 3 ), Ca, Na, Cl, Mg, and sulfate (SO 4 ). The nine-feature dataset, prior to randomly splitting into a training and testing (i.e., validation) dataset, contained 33,271 samples, 19 basins, and was classified based on TDS, HCO 3 , Ca, Na, Cl, Mg, SO 4 , pH, and specific gravity. Three supervised machine learning algorithms—Random Forest, k-Nearest Neighbors, and Naïve Bayes—were used to develop multi-class classification models to predict a basin of origin for produced waters using major ion chemistry. After training, the models were tested on three different datasets: Validation7, Validation9, and one based on data absent from the PWGD. Prediction accuracies across the models ranged from 23.5 to 73.5% when tested on the two PWGD-based datasets. A model using the Random Forest algorithm predicted most accurately compared to all other models tested. The models generally predicted basin of origin more accurately on the PWGD7-based dataset than on the PWGD9-based dataset. An additional dataset, which contained data not in the PWGD, was used to test the most accurate model; results suggest that some basins may lack geochemical diversity or may not be well described, while others may be geochemically diverse or are well described. A compelling result of this work is that a produced water basin of origin can be determined using major ions alone and, therefore, deep basinal fluid compositions may not be as variable within a given basin as previously thought. Applications include predicting the geochemistry of produced fluid prior to drilling at different intervals and assigning historical produced water data to a producing basin.

Natural Resources Research↗

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

Utica shale play oil and gas brines: Geochemistry and factors influencing wastewater management

The Utica and Marcellus Shale Plays in the Appalachian Basin are the fourth and first largest natural gas producing plays in the United States, respectively. Hydrocarbon production generates large volumes of brine (“produced water”) that must be disposed of, treated, or reused. Though Marcellus brines have been studied extensively, there are few studies from the Utica Shale Play. This study presents new brine chemical analyses from 16 Utica Shale Play wells in Ohio and Pennsylvania. Results from Na–Cl–Br systematics and stable and radiogenic isotopes suggest that the Utica Shale Play brines are likely residual pore water concentrated beyond halite saturation during the formation of the Ordovician Beekmantown evaporative sequence. The narrow range of chemistry for the Utica Shale Play produced waters (e.g., total dissolved solids = 214–283 g/L) over both time and space implies a consistent composition for disposal and reuse planning. The amount of salt produced annually from the Utica Shale Play is equivalent to 3.4% of the annual U.S. halite production. Utica Shale Play brines have radium activities 580 times the EPA maximum contaminant level and are supersaturated with respect to barite, indicating the potential for surface and aqueous radium hazards if not properly disposed of.

Kentucky, Maryland, New York, Ohio, Pennsylvania, ↗

USGS2020

Photoluminescence imaging of whole zircon grains on a petrographic microscope—An underused aide for geochronologic studies

The refractory nature of zircon to temperature and pressure allows even a single zircon grain to preserve a rich history of magmatic, metamorphic, and hydrothermal processes. Isotopic dating of micro-domains exposed in cross-sections of zircon grains allows us to interrogate this history. Unfortunately, our ability to select the zircon grains in a heavy mineral concentrate that records the most geochronologic information is limited by our inability to predict internal zonation from observations of whole grains. Here we document the use of a petrographic microscope to observe and image the photoluminescence (PL) response of whole zircon grains excited under ultraviolet (UV) light, and the utility of this PL response in selecting grains for geochronology. While zircon fluorescence has long been known, there is limited documentation of its utility for and application to geochronologic studies. Our observations of zircon from an un-metamorphosed igneous rock, two meta-igneous rocks, and a placer deposit show that variations in the PL color are readily observable in real-time, both among grains in a population of zircons and within single grains. Analyses of cross-sections of the same grains demonstrate that the changes in PL correlate with zoning in backscattered electron (BSE) and cathodoluminescence (CL) images as well as with changes in U + Th concentration and spectroscopic proxies for radiation damage. In other words, the whole grain PL provides a low-resolution preview of the U + Th zoning expected in a cross-sectioned grain. We demonstrate the usefulness of this “preview” in identifying and selecting the subset of zircon grains in a heavy mineral separate that has metamorphic rims of sufficient width to date by secondary ionization mass spectrometry (SIMS). The data are also used to place preliminary constraints on the age and U + Th concentrations at which a yellow PL response is observed in natural samples. The PL response of zircon is well-known among spectroscopists, and these simple applications demonstrate several ways in which the response might be more effectively used by geochronologists.

Minerals↗

USGS2020

Repetitive sampling and control threshold improve 16S rRNA results from produced waters associated with hydraulically fractured shales

Sequencing microbial DNA from deep subsurface environments is complicated by a number of issues ranging from contamination to non-reproducible results. Many samples obtained from these environments - which are of great interest due to the potential to stimulate microbial methane generation - contain low biomass. Therefore, samples from these environments are difficult to study as sequencing results can be easily impacted by contamination. In this case, the low amount of sample biomass may be effectively swamped by the contaminating DNA and generate misleading results. Additionally, performing field work in these environments can be difficult, as researchers generally have limited access to and time on site. Therefore, optimizing a sampling plan to produce the best results while collecting the greatest number of samples over a short period of time is ideal. This study aimed to recommend an adequate sampling plan for field researchers obtaining microbial biomass for 16S rRNA gene sequencing, applicable specifically to oil and gas-producing environments. Forty-nine different samples were collected by filtering specific volumes of produced water from a hydraulically fractured well producing from the Niobrara Shale. Water was collected in two different sampling events 24 hours apart. Four to five samples were collected from 11 specific volumes. These samples along with eight different blanks were submitted for analysis. DNA was extracted from each sample, and quantitative polymerase chain reaction (qPCR) and 16S rRNA Illumina MiSeq gene sequencing were performed to determine relative concentrations of biomass and microbial community composition, respectively. The qPCR results varied across sampled volumes, while no discernible trend correlated contamination to volume of water filtered. This suggests that collecting a larger volume of sample may not result in larger biomass concentrations or better representation of a sampled environment. Researchers could prioritize collecting many low volume samples over few high-volume samples. Our results suggest that there also may be variability in the concentration of microbial communities present in produced waters over short (i.e., hours) time scales, which warrants further investigation. Submission of multiple blanks is also vital to determining how contamination or low biomass effects may influence a sample set collected from an unknown environment.

Montana, Wyoming, Colorado, New Mexico, Texas, Okl↗

USGS2020

Exploring methane behavior in Marcellus Shale micropores via contrast matching neutron scattering

Petroleum in shale reservoirs is hosted in organic matter and mineral pores as well as in natural fractures and voids. For thermally mature plays, e.g., the Marcellus Shale, methane and other light alkane gases are thought to be primarily contained in organic matter pores with radii ≦50 nm. Thus, in order to understand natural gas occurrence, transport, storage, and recoverability within unconventional reservoirs at the dry-gas stage of thermal maturity, it is critical to characterize the associated organic matter porosity across length scales from 50 nm down to the angstrom level. We utilized wide Q-range neutron total scattering to characterize deuterated methane (CD 4 ) adsorption at 60ºC up to the zero average contrast (ZAC) pressure (~60 MPa) within two mineralogically different samples collected from the same producing interval from the Middle Devonian Marcellus Shale. The neutron scattering approach used here provides structural information from the inter-atomic regime up to a nominal pore radius of ~12.5 nm and, by reaching the CD 4 ZAC pressure (~60 MPa), it is possible to examine the distribution of open versus closed pores within this pore size range in the samples. Our results indicate that ~10% of the largest pores measured are closed to CD 4 for a quartz-rich sample whereas up to 25% of pores with a nominal radius of ~12.5 nm are inaccessible within a sample with an equivalent proportion of quartz, carbonate, and clay. As pore size decreases, accessibility also decreases; all pores with radii ~0.5 nm are effectively closed to CD 4 in both samples. Additionally, up to ~4.5× more CD 4 is adsorbed within the quartz-rich sample at 60 MPa and we see no evidence for densification of CD 4 within the shale pores. These findings suggest that, for shale samples within the dry-gas window, (i) nanometer-scale porosity is primarily located within organic matter, (ii) the amount of available nano-porosity can vary widely over meter scales, and (iii) mineralogy plays a secondary role in dictating methane behavior within these systems.

West Virginia↗

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

Direct trace element determination in oil and gas produced waters with inductively coupled plasma - Optical emission spectrometry (ICP-OES): Advantages of high salinity tolerance

Waters co-produced during petroleum extraction are the largest waste stream from oil and gas development. Reuse or disposal of these waters is difficult due to their high salinities and the sheer volumes generated. Produced waters may also contain valuable mineral commodities. While an understanding of produced water trace element composition is required for evaluating the associated resource and waste potential of these materials, measuring trace elements in brines is challenging due to the dilution requirements of typical methods. Alternatively, inductively coupled plasma-optical emission spectrometry (ICP-OES) has shown promise as being capable of direct measurements of trace elements within produced waters with minimal dilution. Here we evaluate direct ICP-OES trace element quantification in produced waters for 17 trace elements (As, Al, Ba, Be, Cd, Cr, Co, Cu, Hg, Mo, Ni, Pb, Rb, Sb, U, V, and Zn) within 15 produced waters from five U.S. continuous reservoirs. The ICP-OES results are compared against trace element levels determined using inductively coupled plasma-mass spectrometry from the same samples. Our results demonstrate the potential for direct analysis of high salinity waters using ICP-OES with minimal dilution and provide trace element concentrations in waters from several important U.S. petroleum-generating reservoirs where available data is sparse.

Montana, New York, North Dakota, Ohio, Pennsylvani↗

USGS2020

Impacts of mineralogical variation on CO2 behavior in small pores from producing intervals of the Marcellus Shale: Results from neutron scattering

The Near and InterMediate Range Order Diffractometer (NIMROD) was used to examine the potential impact of shale mineralogy on CO 2 behavior within micropores. Two samples with varying mineral compositions were obtained from producing intervals in the dry gas window in the Middle Devonian Marcellus Shale. One of the samples contained relatively high amounts of quartz and clay and low carbonate, the other contained relatively equal amounts of quartz, carbonate, and clay. The samples were probed with CO 2 at subcritical pressures (20–50 bar) and temperature (22 °C) and characterized over a neutron scattering vector ( Q ) range of 0.02 < Q < 50 Å –1 . This Q range provides information from the atomistic length-scale up to pore radii of 10 nm. Mineralogy variations between the samples did not affect scattering ratios over the entire Q range accessible with the NIMROD. Q values for the minimum scattering ratios of both samples at similar pressures are remarkably similar, particularly for Q < ∼0.09 Å –1 , and maximum scattering ratios are similar in both samples suggesting that mineral pores are so uncommon in the pore sizes examined that they cannot be resolved due to the overwhelming amounts of organic pores in these samples. Overall, these findings suggest that mineralogical variations have little effect on CO 2 behavior within organic matter-hosted shale micropores at high thermal maturities and they lend support to the assertion that CO 2 cannot be stored in the vast surface areas of micropores in organic material in shale formations. In addition, CO 2 enhanced oil recovery (EOR) is unlikely to displace petroleum from some of the smaller mesopores (2.5 to ∼3.5 nm) and all of the micropores because they are effectively closed to CO 2 . amples were probed with CO2 at subcritical pressures (20 50 bar) and temperature (22 oC) and characterized over a neutron scattering vector (Q) range of 0.02 < Q < 50 -1. This Q range provides information on nominal pore size radii of around 10 0.5 nm. Mineralogy variations between the samples did not affect scattering ratios over the entire Q range accessible with the NIMROD. Q values for the minimum scattering ratios of both samples at similar pressures are statistically indistinguishable and maximum scattering ratios are similar in both samples suggesting that mineral pores are either absent or are so uncommon that they cannot be resolved due to the overwhelming amounts of organic pores in these samples. Overall, these findings suggest that mineralogical variations have little effect on CO2 behavior within organic matter-hosted shale micropores at high thermal maturities and they lend support to the assertion that CO2 cannot be stored in the vast surface areas of micropores (<2.5 nm) in shale formations. In addition, CO2 enhanced oil recovery (EOR) is unlikely to displace petroleum from some of the smaller mesopores (2.5 10 nm) and all of the micropores because they are effectively closed to CO2.

Energy & Fuels↗