Fischer Assays of Oil Shale Drill Cores and Rotary Cuttings from the Piceance Basin, Colorado - 2009 Update

USGS Publications Warehouse

Mercier, Tracey J.; Brownfield, Michael E.; Johnson, Ronald C.; Self, Jesse G.

1998-01-01

This CD-ROM includes updated files containing Fischer assays of samples of core holes and cuttings from exploration drill holes drilled in the Eocene Green River Formation in the Piceance Basin of northwestern Colorado. A database was compiled that includes more than 321,380 Fischer assays from 782 boreholes. Most of the oil yield data were analyzed by the former U.S. Bureau of Mines oil shale laboratory in Laramie, Wyoming, and some analyses were made by private laboratories. Location data for 1,042 core and rotary holes, oil and gas tests, as well as a few surface sections are listed in a spreadsheet and included in the CD-ROM. These assays are part of a larger collection of subsurface information held by the U.S. Geological Survey, including geophysical and lithologic logs, water data, and chemical and X-ray diffraction analyses having to do with the Green River oil shale deposits in Colorado, Wyoming, and Utah. Because of an increased interest in oil shale, this CD-ROM disc containing updated Fischer assay data for the Piceance Basin oil shale deposits in northwestern Colorado is being released to the public.

Wellsite, laboratory, and mathematical techniques for determining sorbed gas content of coals and gas shales utilizing well cuttings

USGS Publications Warehouse

Newell, K.D.

2007-01-01

Drill cuttings can be used for desorption analyses but with more uncertainty than desorption analyses done with cores. Drill cuttings are not recommended to take the place of core, but in some circumstances, desorption work with cuttings can provide a timely and economic supplement to that of cores. The mixed lithologic nature of drill cuttings is primarily the source of uncertainty in their analysis for gas content, for it is unclear how to apportion the gas generated from both the coal and the dark-colored shale that is mixed in usually with the coal. In the Western Interior Basin Coal Basin in eastern Kansas (Pennsylvanian-age coals), dark-colored shales with normal (??? 100 API units) gamma-ray levels seem to give off minimal amounts of gas on the order of less than five standard cubic feet per ton (scf/ton). In some cuttings analyses this rule of thumb for gas content of the shale is adequate for inferring the gas content of coals, but shales with high-gamma-ray values (>150 API units) may yield several times this amount of gas. The uncertainty in desorption analysis of drill cuttings can be depicted graphically on a diagram identified as a "lithologic component sensitivity analysis diagram." Comparison of cuttings desorption results from nearby wells on this diagram, can sometimes yield an unique solution for the gas content of both a dark shale and coal mixed in a cuttings sample. A mathematical solution, based on equating the dry, ash-free gas-contents of the admixed coal and dark-colored shale, also yields results that are correlative to data from nearby cores. ?? 2007 International Association for Mathematical Geology.

Noble gases in gas shales : Implications for gas retention and circulating fluids.

NASA Astrophysics Data System (ADS)

Basu, Sudeshna; Jones, Adrian; Verchovsky, Alexander

2016-04-01

Gas shales from three cores of Haynesville-Bossier formation have been analysed simultaneously for carbon, nitrogen and noble gases (He, Ne, Ar, Xe) to constrain their source compositions and identify signatures associated with high gas retention. Ten samples from varying depths of 11785 to 12223 feet from each core, retrieved from their centres, have been combusted from 200-1200°C in incremental steps of 100°C, using 5 - 10 mg of each sample. Typically, Xe is released at 200°C and is largely adsorbed, observed in two of the three cores. The third core lacked any measureable Xe. High 40Ar/36Ar ratio up to 8000, is associated with peak release of nitrogen with distinctive isotopic signature, related to breakdown of clay minerals at 500°C. He and Ne are also mostly released at the same temperature step and predominantly hosted in the pore spaces of the organic matter associated with the clay. He may be produced from the uranium related to the organic matter. The enrichment factors of noble gases defined as (iX/36Ar)sample/(iX/36Ar)air where iX denotes any noble gas isotope, show Ne and Xe enrichment observed commonly in sedimentary rocks including shales (Podosek et al., 1980; Bernatowicz et al., 1984). This can be related to interaction of the shales with circulating fluids and diffusive separation of gases (Torgersen and Kennedy, 1999), implying the possibility of loss of gases from these shales. Interaction with circulating fluids (e.g. crustal fluids) have been further confirmed using 20Ne/N2, 36Ar/N2 and 4He/N2 ratios. Deviations of measured 4He/40Ar* (where 40Ar* represents radiogenic 40Ar after correcting for contribution from atmospheric Ar) from expected values has been used to monitor gas loss by degassing. Bernatowicz, T., Podosek, F.A., Honda, M., Kramer, F.E., 1984. The Atmospheric Inventory of Xenon and Noble Gases in Shales: The Plastic Bag Experiment. Journal of Geophysical Research 89, 4597-4611. Podosek, F.A., Honda, M., Ozima, M., 1980. Sedimentary noble gases. Geochimica Cosmochimica Acta 44, 1875-1884. Torgersen, T., Kennedy, B.M., 1999. Air-Xe enrichments in Oil Field Gases and the Influence of Water during Oil Migration and Storage. Earth and Planetary Science Letters167, 239-253.

Investigating Rare Earth Element Systematics in the Marcellus Shale

NASA Astrophysics Data System (ADS)

Yang, J.; Torres, M. E.; Kim, J. H.; Verba, C.

2014-12-01

The lanthanide series of elements (the 14 rare earth elements, REEs) have similar chemical properties and respond to different chemical and physical processes in the natural environment by developing unique patterns in their concentration distribution when normalized to an average shale REE content. The interpretation of the REE content in a gas-bearing black shale deposited in a marine environment must therefore take into account the paleoredox conditions of deposition as well as any diagenetic remobilization and authigenic mineral formation. We analyzed 15 samples from a core of the Marcellus Shale (Whipkey ST1, Greene Co., PA) for REEs, TOC, gas-producing potential, trace metal content, and carbon isotopes of organic matter in order to determine the REE systematics of a black shale currently undergoing shale gas development. We also conducted a series of sequential leaching experiments targeting the phosphatic fractions in order to evaluate the dominant host phase of REEs in a black shale. Knowledge of the REE system in the Marcellus black shale will allow us to evaluate potential REE release and behavior during hydraulic fracturing operations. Total REE content of the Whipkey ST1 core ranged from 65-185 μg/g and we observed three distinct REE shale-normalized patterns: middle-REE enrichment (MREE/MREE* ~2) with heavy-REE enrichment (HREE/LREE ~1.8-2), flat patterns, and a linear enrichment towards the heavy-REE (HREE/LREE ~1.5-2.5). The MREE enrichment occurred in the high carbonate samples of the Stafford Member overlying the Marcellus Formation. The HREE enrichment occurred in the Union Springs Member of the Marcellus Formation, corresponding to a high TOC peak (TOC ~4.6-6.2 wt%) and moderate carbonate levels (CaCO3 ~4-53 wt%). Results from the sequential leaching experiments suggest that the dominant host of the REEs is the organic fraction of the black shale and that the detrital and authigenic fractions have characteristic MREE enrichments. We present our conclusions on the impact of depositional setting and diagenetic remobilization and authigenic mineral formation on the REE system in the Marcellus Shale.

Nanometer-Scale Pore Characteristics of Lacustrine Shale, Songliao Basin, NE China

PubMed Central

Wang, Min; Yang, Jinxiu; Wang, Zhiwei; Lu, Shuangfang

2015-01-01

In shale, liquid hydrocarbons are accumulated mainly in nanometer-scale pores or fractures, so the pore types and PSDs (pore size distributions) play a major role in the shale oil occurrence (free or absorbed state), amount of oil, and flow features. The pore types and PSDs of marine shale have been well studied; however, research on lacustrine shale is rare, especially for shale in the oil generation window, although lacustrine shale is deposited widely around the world. To investigate the relationship between nanometer-scale pores and oil occurrence in the lacustrine shale, 10 lacustrine shale core samples from Songliao Basin, NE China were analyzed. Analyses of these samples included geochemical measurements, SEM (scanning electron microscope) observations, low pressure CO2 and N2 adsorption, and high-pressure mercury injection experiments. Analysis results indicate that: (1) Pore types in the lacustrine shale include inter-matrix pores, intergranular pores, organic matter pores, and dissolution pores, and these pores are dominated by mesopores and micropores; (2) There is no apparent correlation between pore volumes and clay content, however, a weak negative correlation is present between total pore volume and carbonate content; (3) Pores in lacustrine shale are well developed when the organic matter maturity (Ro) is >1.0% and the pore volume is positively correlated with the TOC (total organic carbon) content. The statistical results suggest that oil in lacustrine shale mainly occurs in pores with diameters larger than 40 nm. However, more research is needed to determine whether this minimum pore diameter for oil occurrence in lacustrine shale is widely applicable. PMID:26285123

Nanometer-Scale Pore Characteristics of Lacustrine Shale, Songliao Basin, NE China.

PubMed

Wang, Min; Yang, Jinxiu; Wang, Zhiwei; Lu, Shuangfang

2015-01-01

In shale, liquid hydrocarbons are accumulated mainly in nanometer-scale pores or fractures, so the pore types and PSDs (pore size distributions) play a major role in the shale oil occurrence (free or absorbed state), amount of oil, and flow features. The pore types and PSDs of marine shale have been well studied; however, research on lacustrine shale is rare, especially for shale in the oil generation window, although lacustrine shale is deposited widely around the world. To investigate the relationship between nanometer-scale pores and oil occurrence in the lacustrine shale, 10 lacustrine shale core samples from Songliao Basin, NE China were analyzed. Analyses of these samples included geochemical measurements, SEM (scanning electron microscope) observations, low pressure CO2 and N2 adsorption, and high-pressure mercury injection experiments. Analysis results indicate that: (1) Pore types in the lacustrine shale include inter-matrix pores, intergranular pores, organic matter pores, and dissolution pores, and these pores are dominated by mesopores and micropores; (2) There is no apparent correlation between pore volumes and clay content, however, a weak negative correlation is present between total pore volume and carbonate content; (3) Pores in lacustrine shale are well developed when the organic matter maturity (Ro) is >1.0% and the pore volume is positively correlated with the TOC (total organic carbon) content. The statistical results suggest that oil in lacustrine shale mainly occurs in pores with diameters larger than 40 nm. However, more research is needed to determine whether this minimum pore diameter for oil occurrence in lacustrine shale is widely applicable.

Fischer Assays of Oil-Shale Drill Cores and Rotary Cuttings from the Greater Green River Basin, Southwestern Wyoming

USGS Publications Warehouse

,

2008-01-01

Chapter 1 of this CD-ROM is a database of digitized Fischer (shale-oil) assays of cores and cuttings from boreholes drilled in the Eocene Green River oil shale deposits in southwestern Wyoming. Assays of samples from some surface sections are also included. Most of the Fischer assay analyses were made by the former U.S. Bureau of Mines (USBM) at its laboratory in Laramie, Wyoming. Other assays, made by institutional or private laboratories, were donated to the U.S. Geological Survey (USGS) and are included in this database as well as Adobe PDF-scanned images of some of the original laboratory assay reports and lithologic logs prepared by USBM geologists. The size of this database is 75.2 megabytes and includes information on 971 core holes and rotary-drilled boreholes and numerous surface sections. Most of these data were released previously by the USBM and the USGS through the National Technical Information Service but are no longer available from that agency. Fischer assays for boreholes in northeastern Utah and northwestern Colorado have been published by the USGS. Additional data include geophysical logs, groundwater data, chemical and X-ray diffraction analyses, and other data. These materials are available for inspection in the office of the USGS Central Energy Resources Team in Lakewood, Colorado. The digitized assays were checked with the original laboratory reports, but some errors likely remain. Other information, such as locations and elevations of core holes and oil and gas tests, were not thoroughly checked. However, owing to the current interest in oil-shale development, it was considered in the public interest to make this preliminary database available at this time. Chapter 2 of this CD-ROM presents oil-yield histograms of samples of cores and cuttings from exploration drill holes in the Eocene Green River Formation in the Great Divide, Green River, and Washakie Basins of southwestern Wyoming. A database was compiled that includes about 47,000 Fischer assays from 186 core holes and 240 rotary drill holes. Most of the oil yield data are from analyses performed by the former U.S. Bureau of Mines oil shale laboratory in Laramie, Wyoming, with some analyses made by private laboratories. Location data for 971 Wyoming oil-shale drill holes are listed in a spreadsheet that is included in the CD-ROM. These Wyoming Fischer assays and histograms are part of a much larger collection of oil-shale information, including geophysical and lithologic logs, water data, chemical and X-ray diffraction analyses on the Green River oil-shale deposits in Colorado, Utah, and Wyoming held by the U.S. Geological Survey. Because of an increased interest in oil shale, this CD-ROM containing Fischer assay data and oil-yield histograms for the Green River oil-shale deposits in southwestern Wyoming is being released to the public. Microsoft Excel spreadsheets included with Chapter 2 contain the Fischer assay data from the 426 holes and data on the company name and drill-hole name, and location. Histograms of the oil yields obtained from the Fischer assays are presented in both Grapher and PDF format. Fischer assay text data files are also included in the CD-ROM.

Core Across the San Andreas Fault at SAFOD - Photographs, Physical Properties Data, and Core-Handling Procedures

NASA Astrophysics Data System (ADS)

Kirschner, D. L.; Carpenter, B.; Keenan, T.; Sandusky, E.; Sone, H.; Ellsworth, B.; Hickman, S.; Weiland, C.; Zoback, M.

2007-12-01

Core samples were obtained that cross three faults of the San Andreas Fault Zone north of Parkfield, California, during the summer of 2007. The cored intervals were obtained by sidetracking off the SAFOD Main Hole that was rotary drilled across the San Andreas in 2005. The first cored interval targeted the pronounced lithologic boundary between the Salinian terrane and the Great Valley and Franciscan formations. Eleven meters of pebbly conglomerate (with minor amounts of fine sands and shale) were obtained from 3141 to 3152 m (measured depth, MD). The two conglomerate units are heavily fractured with many fractures having accommodated displacement. Within this cored interval, there is a ~1m zone with highly sheared, fine-grained material, possibly ultracataclasite in part. The second cored interval crosses a creeping segment of a fault that has been deforming the cemented casing of the adjacent Main Hole. This cored interval sampled the fault 100 m above a seismogenic patch of M2 repeating earthquakes. Thirteen meters of core were obtained across this fault from 3186 to 3199 m (MD). This fault, which is hosted primarily in siltstones and shales, contains a serpentinite body embedded in a highly sheared shale and serpentinite-bearing fault gouge unit. The third cored interval crosses a second creeping fault that has also been deforming the cemented casing of the Main Hole. This fault, which is the most rapidly shearing fault in the San Andreas fault zone based on casing deformation, contains multiple fine- grained clay-rich fault strands embedded in highly sheared shales and lesser deformed sandstones. Initial processing of the cores was carried out at the drill site. Each core came to the surface in 9 meter-long aluminum core barrels. These were cut into more manageable three-foot sections. The quarter-inch-thick aluminum liner of each section was cut and then split apart to reveal the 10 cm diameter cores. Depending on the fragility and porosity of the rock, the drilling fluid was removed either by washing with dilute calcium chloride brine (to approximately match the salinity of the formation fluids) or by gently scraping away drilling mud on the core surface. Once cleaned, each core section was photographed to very high resolution on a Geotek Multi- Sensor Core Logging (MSCL) system. This system was also used to determine the bulk density and magnetic susceptibility of each section. The 25 MB high-resolution photographs and the raw and processed physical properties data were then uploaded to the ICDP web server in Potsdam for public access (http://safod.icdp- online.org). The cores will be archived at the Gulf Coast Repository of the Integrated Ocean Drilling Program in College Station, TX. The MSCL photographs, physical property measurements, and other related data, such as geophysical logs, will be integrated using CoreWall, and will be on display at the meeting. All samples, data, and imagery are available to the science community.

Heterogeneity of shales in different scales and its implications to laboratory analyses - examples from sedimentology and organic geochemistry study of the Lower Paleozoic shales from shale gas exploration well located in the Baltic Basin, Poland.

NASA Astrophysics Data System (ADS)

Roszkowska-Remin, Joanna; Janas, Marcin

2017-04-01

We present the litho-sedimentological, organic geochemical results and organic porosity estimation of the Ordovician and Silurian shales in the SeqWell (shale gas exploration well located in the Pomerania region, Poland). The most perspective black and bituminous shales of the Upper Ordovician and the Lower Silurian may seem to be homogeneous. However, our results reveal that these shales show heterogeneity at different scales (m to mm). For example, in most cases the decrease of TOC content in the m scale is related to pyroclastic rock intercalations and "dark bioturbations" with no color difference when compared with surrounding sediments. While in cm scale heterogeneity is related to bioturbations, density of organic-rich laminas, or abundance of carbonates and pyrite. Without a detailed sedimentological study of polished core surfaces and Rock-Eval analyses those observations are rather invisible. The correct interpretation of results requires the understanding of rock's heterogeneity in different scales. It has a critical importance for laboratory tests applied on few cm long samples, especially if the results are to be extrapolated to wider intervals. Therefore in ShaleSeq project, a detailed sedimentological core logging and analysis of geochemical parameters of perspective formations in m to mm scale was performed for the first time. The results show good correlation between bioturbation index (BI) and organic geochemical indicators like organic carbon content (TOC) or oxic deposition conditions indicator (oxygen index - OI) leading to the assumption that environmental conditions may have played a crucial role in organic carbon preservation. The geochemical analyses of 12 samples showed that even within the few cm long sections shale can be really diversified. Eight out of twelve analyzed samples were considered geochemically mostly homogeneous, whilst four of them showed evident heterogeneity. Concluding, the sampling should be preceded by detailed sedimentological study, as it allows to control if the chosen samples are representative for wider intervals and give opportunity to place the laboratory results in the wider context. An attempt to estimate organic porosity using Rock-Eval data was based on Marathon Oil company study of the Polish Lower Paleozoic shales. The results of this study and suggested equations were used to calculate hypothetical organic porosity of the most perspective shales in the SeqWell. Calculated organic porosities in % bulk volume of rock suggested that organic porosity for Upper Ordovician and Lower Silurian shales in SeqWell may be at the level of 0,1-2,9% in bulk volume of rock. These results would suggest that organic porosity doesn't play a major role in total porosity system in these shales at the certain thermal maturity level. The hypothetical organic porosity values were not validated by the microscopic study though. Our study are part of the ShaleSeq Project co-funded by Norway Grants of the Polish-Norwegian Research Programme operated by the National Centre for Research and Development.

A Collection of Chemical, Mineralogical, and Stable Isotopic Compositional Data for Green River Oil Shale from Depositional Center Cores in Colorado, Utah, and Wyoming

USGS Publications Warehouse

Tuttle, Michele L.W.

2009-01-01

For over half a century, the U.S. Geological Survey and collaborators have conducted stratigraphic and geochemical studies on the Eocene Green River Formation, which is known to contain large oil shale resources. Many of the studies were undertaken in the 1970s during the last oil shale boom. One such study analyzed the chemistry, mineralogy, and stable isotopy of the Green River Formation in the three major depositional basins: Piceance basin, Colo.; Uinta basin, Utah; and the Green River basin, Wyo. One depositional-center core from each basin was sampled and analyzed for major, minor, and trace chemistry; mineral composition and sulfide-mineral morphology; sulfur, nitrogen, and carbon forms; and stable isotopic composition (delta34S, delta15N, delta13C, and delta18O). Many of these data were published and used to support interpretative papers (see references herein). Some bulk-chemical and carbonate-isotopic data were never published and may be useful to studies that are currently exploring topics such as future oil shale development and the climate, geography, and weathering in the Eocene Epoch. These unpublished data, together with most of the U.S. Geological Survey data already published on these samples, are tabulated in this report.

Histograms showing variations in oil yield, water yield, and specific gravity of oil from Fischer assay analyses of oil-shale drill cores and cuttings from the Piceance Basin, northwestern Colorado

USGS Publications Warehouse

Dietrich, John D.; Brownfield, Michael E.; Johnson, Ronald C.; Mercier, Tracey J.

2014-01-01

Recent studies indicate that the Piceance Basin in northwestern Colorado contains over 1.5 trillion barrels of oil in place, making the basin the largest known oil-shale deposit in the world. Previously published histograms display oil-yield variations with depth and widely correlate rich and lean oil-shale beds and zones throughout the basin. Histograms in this report display oil-yield data plotted alongside either water-yield or oil specific-gravity data. Fischer assay analyses of core and cutting samples collected from exploration drill holes penetrating the Eocene Green River Formation in the Piceance Basin can aid in determining the origins of those deposits, as well as estimating the amount of organic matter, halite, nahcolite, and water-bearing minerals. This report focuses only on the oil yield plotted against water yield and oil specific gravity.

Carbon Dioxide Sealing Capacity: Textural or Compositional Controls?

DOE Office of Scientific and Technical Information (OSTI.GOV)

Cranganu, Constantin; Soleymani, Hamidreza; Sadiqua, Soleymani

2013-11-30

This research project is aiming to assess the carbon dioxide sealing capacity of most common seal-rocks, such as shales and non-fractured limestones, by analyzing the role of textural and compositional parameters of those rocks. We hypothesize that sealing capacity is controlled by textural and/or compositional pa-rameters of caprocks. In this research, we seek to evaluate the importance of textural and compositional parameters affecting the sealing capacity of caprocks. The conceptu-al framework involves two testable end-member hypotheses concerning the sealing ca-pacity of carbon dioxide reservoir caprocks. Better understanding of the elements controlling sealing quality will advance our knowledge regarding the sealingmore » capacity of shales and carbonates. Due to relatively low permeability, shale and non-fractured carbonate units are considered relatively imper-meable formations which can retard reservoir fluid flow by forming high capillary pres-sure. Similarly, these unites can constitute reliable seals for carbon dioxide capture and sequestration purposes. This project is a part of the comprehensive project with the final aim of studying the caprock sealing properties and the relationship between microscopic and macroscopic characteristics of seal rocks in depleted gas fields of Oklahoma Pan-handle. Through this study we examined various seal rock characteristics to infer about their respective effects on sealing capacity in special case of replacing reservoir fluid with super critical carbon dioxide (scCO{sub 2}). To assess the effect of textural and compositional properties on scCO{sub 2} maximum reten-tion column height we collected 30 representative core samples in caprock formations in three counties (Cimarron, Texas, Beaver) in Oklahoma Panhandle. Core samples were collected from various seal formations (e.g., Cherokee, Keys, Morrowan) at different depths. We studied the compositional and textural properties of the core samples using several techniques. Mercury Injection Porosimetry (MIP), Scanning Electron Microsco-py SEM, and Sedigraph measurements are used to assess the pore-throat-size distribu-tion, sorting, texture, and grain size of the samples. Also, displacement pressure at 10% mercury saturation (Pd) and graphically derived threshold pressure (Pc) were deter-mined by MIP technique. SEM images were used for qualitative study of the minerals and pores texture of the core samples. Moreover, EDS (Energy Dispersive X-Ray Spec-trometer), BET specific surface area, and Total Organic Carbon (TOC) measurements were performed to study various parameters and their possible effects on sealing capaci-ty of the samples. We found that shales have the relatively higher average sealing threshold pressure (Pc) than carbonate and sandstone samples. Based on these observations, shale formations could be considered as a promising caprock in terms of retarding scCO{sub 2} flow and leak-age into above formations. We hypothesized that certain characteristics of shales (e.g., 3 fine pore size, pore size distribution, high specific surface area, and strong physical chemical interaction between wetting phase and mineral surface) make them an effi-cient caprock for sealing super critical CO{sub 2}. We found that the displacement pressure at 10% mercury saturation could not be the ultimate representative of the sealing capacity of the rock sample. On the other hand, we believe that graphical method, introduced by Cranganu (2004) is a better indicator of the true sealing capacity. Based on statistical analysis of our samples from Oklahoma Panhandle we assessed the effects of each group of properties (textural and compositional) on maximum supercriti-cal CO{sub 2} height that can be hold by the caprock. We conclude that there is a relatively strong positive relationship (+.40 to +.69) between supercritical CO{sub 2} column height based on Pc and hard/ soft mineral content index (ratio of minerals with Mohs hardness more than 5 over minerals with Mohs hardness less than 5) in both shales and limestone samples. Average median pore radius and porosity display a strong negative correlation with supercritical CO{sub 2} retention column height. Also, increasing bulk density is positive-ly correlated with the supercritical CO{sub 2} retention column height. One of the most im-portant factors affecting sealing capacity and consequently the height of supercritical CO{sub 2} column is sorting of the pore throats. We observed a strong positive correlation be-tween pore throat sorting and height of CO{sub 2} retention column, especially in shales. This correlation could not be observed in limestone samples. It suggests that the pore throat sorting is more controlling the sealing capacity in shales and shales with well sorted pore throats are the most reliable lithology as seal. We observed that Brunauer–Emmett–Teller (BET) surface area shows a very strong correlation with CO{sub 2} retention column height in limestone samples while BET surface area did not display significant correlation in shales. Pore structure based on SEM mi-crographs exhibits strong correlation with CO{sub 2} retention column height in limestones. Both intercrystalline and vuggy structures have negative correlations while intergranu-lar texture has positive correlation in limestone with respect to CO{sub 2} retention column height. Textural effects observed on SEM micrographs did not show statistically signifi-cant correlation with supercritical CO{sub 2} retention column height in shale samples. Finally, we showed that increasing hard/soft mineral index is strongly correlated with the displacement pressure in limestone samples. Vuggy texture displays a relatively strong and negative correlation with displacement pressure values at 10% mercury satu-ration in shale samples.« less

Visual classification of very fine-grained sediments: Evaluation through univariate and multivariate statistics

USGS Publications Warehouse

Hohn, M. Ed; Nuhfer, E.B.; Vinopal, R.J.; Klanderman, D.S.

1980-01-01

Classifying very fine-grained rocks through fabric elements provides information about depositional environments, but is subject to the biases of visual taxonomy. To evaluate the statistical significance of an empirical classification of very fine-grained rocks, samples from Devonian shales in four cored wells in West Virginia and Virginia were measured for 15 variables: quartz, illite, pyrite and expandable clays determined by X-ray diffraction; total sulfur, organic content, inorganic carbon, matrix density, bulk density, porosity, silt, as well as density, sonic travel time, resistivity, and ??-ray response measured from well logs. The four lithologic types comprised: (1) sharply banded shale, (2) thinly laminated shale, (3) lenticularly laminated shale, and (4) nonbanded shale. Univariate and multivariate analyses of variance showed that the lithologic classification reflects significant differences for the variables measured, difference that can be detected independently of stratigraphic effects. Little-known statistical methods found useful in this work included: the multivariate analysis of variance with more than one effect, simultaneous plotting of samples and variables on canonical variates, and the use of parametric ANOVA and MANOVA on ranked data. ?? 1980 Plenum Publishing Corporation.

A Paleomagnetic and Diagenetic Study of the Woodford Shale, Oklahoma, U.S.A.: The Timing of Hydrothermal Alteration

NASA Astrophysics Data System (ADS)

Roberts, J.; Elmore, R. D.

2017-12-01

An oriented Woodford Shale core from the Ardmore Basin near the Ouachita thrust zone (Core B) was sampled to identify diagenetic events and interpret their origin, and to test if a magnetization was present that can be used to date the altering event(s). The shale is extensively altered, exhibiting a complex paragenesis with multiple fractures and brecciated intervals. Multiple hydrothermal minerals, including biotite, magnesite, norsethite, witherite, gorceixite, potassium feldspar, sphalerite, chalcopyrite, and saddle dolomite, are present in and around fractures and in the matrix. Vitrinite and bitumen reflectance measurements indicate VRo values of 1.82% ( 230°C). Two other Woodford Shale cores (A and C) from the Anadarko Basin also contain hydrothermal minerals. Vitrinite and bitumen reflectance data reveal trends between thermal maturity and the level of hydrothermal alteration, with Core A (0.80% VRo ( 125°C) displaying the lowest alteration, and Core C ( 1.5% VRo ( 210°C) displaying intermediate alteration compared to core B. Paleomagnetic analysis of Core B reveals the presence of a characteristic remanent magnetization (ChRM) with south-southeasterly declinations and shallow inclinations that is unblocked by 450°C and is interpreted to reside in magnetite. This ChRM is interpreted to be either a chemical remanent magnetization (CRM) or a thermochemical remanent magnetization (TCRM) acquired during the Late Permian based on the pole position. The presence of specimens with the CRM/TCRM in altered rock and high thermal maturities suggests that this CRM/TCRM originated from alteration by hydrothermal fluids. These results suggest that the Woodford Shale evolved into an open diagenetic system. In addition to causing heightened thermal maturities, these hydrothermal fluids both increased porosity through dissolution and decreased porosity through precipitation of minerals. The Late Permian timing agrees with the dating of hydrothermal alteration found within the Ouachita and Arbuckle Mountains in other studies. The timing for these events is postcollisional, and the most consistent model for the origin of the hydrothermal minerals is fluid flow as a result of faulting that accessed reservoir(s) of warm fluids.

Shale Gas characteristics of Permian black shales (Ecca group, Eastern Cape, South Africa)

NASA Astrophysics Data System (ADS)

Geel, Claire; Booth, Peter; Schulz, Hans-Martin; Horsfield, Brian; de Wit, Maarten

2013-04-01

This study involves a comprehensive and detailed lithological, sedimentalogical, structural and geochemical description of the lower Ecca Group in the Eastern Cape, South Africa. The Ecca group hosts a ~ 245 million year old organic-rich black shale, which has recently been the focus of interest of petroleum companies worldwide. The shale was deposited under anoxic conditions in a setting which formed as a consequence of retro-arc foreland basin development related to the Cape Fold Belt. This sedimentary/tectonic environment provided the conditions for deeply buried black shales to reach maturity levels for development in the gas window. The investigation site is called the Greystone Area and is situated north of Wolwefontein en route to Jansenville. The area has outcrops of the Dwyka, the Ecca and the lower Beaufort Groups. The outcrops were mapped extensively and the data was used in conjunction with GIS software to produce a detailed geological map. North-south cross sections were drawn to give indication of bed thicknesses and formation depths. Using the field work, data two boreholes were accurately sited on the northern limb of a shallow easterly plunging syncline. The first borehole reached 100m and the second was drilled to 292m depth (100m percussion and 192m core). The second borehole was drilled 200m south of the first, to penetrate the formations at a greater depth and to avoid surface weathering. Fresh core from the upper Dwyka Group, the Prince Albert Formation, the Whitehill Formation, Collingham Formation and part of the Ripon Formation were successfully extracted and a detailed stratigraphic log has been drawn up. The core was sampled during extraction and the samples were immediately sent to the GFZ in Potsdam, Germany, for geochemical analyses. As suspected the black shales of the the Whitehill Formation are high in organic carbon and have an average TOC value of 4.5%, whereas the Prince Albert and Collingham Formation are below 1%. Tmax values and the evolution of organic material to bitumen characterise these sediments as overmature. The HI and OI results reveal that the Collingham and Whitehill sediments are type II kerogen and the Prince Albert is type III kerogen sediment. XRD data shows major rock forming minerals of the black shales to be quartz, illite, muscovite and chlorite with some plagioclase and large amounts of accessory pyrite. Average meso-and macro-porosity of these black shales is 1.5% and SEM images confirm that these sediments are tightly packed. The samples are highly affected by the Cape Fold Belt due to its location so far south and is unlikely to hold gas at this position, however this ongoing investigation will give greater insight to the gas potential of these black shales which are found more north of the region. At the GFZ open system pyrolyses and thermovaporization analyses are still underway.

Pyrolysis gas chromatography-mass spectrometry to characterize organic matter and its relationship to uranium content of Appalachian Devonian black shales

USGS Publications Warehouse

Leventhal, J.S.

1981-01-01

Gas Chromatographic analysis of volatile products formed by stepwise pyrolysis of black shales can be used to characterize the kerogen by relating it to separated, identified precursors such as land-derived vitrinite and marine-source Tasmanites. Analysis of a Tasmanites sample shows exclusively n-alkane and -alkene pyrolysis products, whereas a vitrinite sample shows a predominance of one- and two-ring substituted aromatics. For core samples from northern Tennessee and for a suite of outcrop samples from eastern Kentucky, the organic matter type and the U content (<10-120ppm) show variations that are related to precursor organic materials. The samples that show a high vitrinite component in their pyrolysis products are also those samples with high contents of U. ?? 1981.

Hydrocarbon source potential of the Tanezzuft Formation, Murzuq Basin, south-west Libya: An organic geochemical approach

NASA Astrophysics Data System (ADS)

El Diasty, W. Sh.; El Beialy, S. Y.; Anwari, T. A.; Batten, D. J.

2017-06-01

A detailed organic geochemical study of 20 core and cuttings samples collected from the Silurian Tanezzuft Formation, Murzuq Basin, in the south-western part of Libya has demonstrated the advantages of pyrolysis geochemical methods for evaluating the source-rock potential of this geological unit. Rock-Eval pyrolysis results indicate a wide variation in source richness and quality. The basal Hot Shale samples proved to contain abundant immature to early mature kerogen type II/III (oil-gas prone) that had been deposited in a marine environment under terrigenous influence, implying good to excellent source rocks. Strata above the Hot Shale yielded a mixture of terrigenous and marine type III/II kerogen (gas-oil prone) at the same maturity level as the Hot Shale, indicating the presence of only poor to fair source rocks.

Chemical analysis and geochemical associations in Devonian black shale core samples from Martin County, Kentucky; Carroll and Washington counties, Ohio; Wise County, Virginia; and Overton County, Tennessee

USGS Publications Warehouse

Leventhal, Joel S.

1979-01-01

Core samples from Devonian shales from five localities in the Appalachian Basin have been analyzed for major, minor, and trace constituents. The contents of major elements are rather similar; however, the minor constituents, organic C, S, PO4, and CO3, show variations by a factor of 10. Trace elements Mo, Ni, Cu, V, Co, U, Zn, Hg, As, and Mn show variations that can be related graphically and statistically to the minor constituents. Down-hole plots show the relationships most clearly. Mn is associated with CO3 content, the other trace elements are strongly Controlled by organic C. Amounts of organic C are generally in the range of 3-6 percent, and S is in the range of 2-5 percent. Trace-element amounts show the following general ranges (ppm, parts per million)- Co, 20-40; Cu,40-70; U, 10-40; As, 20-40, V, 150-300; Ni, 80-150; high values are as much as twice these values. The organic C was probably the concentrating agent, whereas the organic C and sulfide S created an environment for preservation or immobilization of trace elements. Closely spaced samples showing an abrupt transition in color from black to gray and gray to black shale show similar effects of trace-element changes, that is, black shale contains enhanced amounts of organic C and trace elements. Ratios of trace elements to organic C or sulfide S were relatively constant even though deposition rates varied from 10 to 300 meters in 5 million years.

Thermal maturity and organic composition of Pennsylvanian coals and carbonaceous shales, north-central Texas: Implications for coalbed gas potential

USGS Publications Warehouse

Hackley, P.C.; Guevara, E.H.; Hentz, T.F.; Hook, R.W.

2009-01-01

Thermal maturity was determined for about 120 core, cuttings, and outcrop samples to investigate the potential for coalbed gas resources in Pennsylvanian strata of north-central Texas. Shallow (< 600??m; 2000??ft) coal and carbonaceous shale cuttings samples from the Middle-Upper Pennsylvanian Strawn, Canyon, and Cisco Groups in Archer and Young Counties on the Eastern Shelf of the Midland basin (northwest and downdip from the outcrop) yielded mean random vitrinite reflectance (Ro) values between about 0.4 and 0.8%. This range of Ro values indicates rank from subbituminous C to high volatile A bituminous in the shallow subsurface, which may be sufficient for early thermogenic gas generation. Near-surface (< 100??m; 300??ft) core and outcrop samples of coal from areas of historical underground coal mining in the region yielded similar Ro values of 0.5 to 0.8%. Carbonaceous shale core samples of Lower Pennsylvanian strata (lower Atoka Group) from two deeper wells (samples from ~ 1650??m; 5400??ft) in Jack and western Wise Counties in the western part of the Fort Worth basin yielded higher Ro values of about 1.0%. Pyrolysis and petrographic data for the lower Atoka samples indicate mixed Type II/Type III organic matter, suggesting generated hydrocarbons may be both gas- and oil-prone. In all other samples, organic material is dominated by Type III organic matter (vitrinite), indicating that generated hydrocarbons should be gas-prone. Individual coal beds are thin at outcrop (< 1??m; 3.3??ft), laterally discontinuous, and moderately high in ash yield and sulfur content. A possible analog for coalbed gas potential in the Pennsylvanian section of north-central Texas occurs on the northeast Oklahoma shelf and in the Cherokee basin of southeastern Kansas, where contemporaneous gas-producing coal beds are similar in thickness, quality, and rank.

Measuring Concentrations of Dissolved Methane and Ethane and the 13 C of Methane in Shale and Till.

PubMed

Hendry, M Jim; Barbour, S Lee; Schmeling, Erin E; Mundle, Scott O C

2017-01-01

Baseline characterization of concentrations and isotopic values of dissolved natural gases is needed to identify contamination caused by the leakage of fugitive gases from oil and gas activities. Methods to collect and analyze baseline concentration-depth profiles of dissolved CH 4 and C 2 H 6 and δ 13 C-CH 4 in shales and Quaternary clayey tills were assessed at two sites in the Williston Basin, Canada. Core and cuttings samples were stored in Isojars ® in a low O 2 headspace prior to analysis. Measurements and multiphase diffusion modeling show that the gas concentrations in core samples yield well-defined and reproducible depth profiles after 31-d equilibration. No measurable oxidative loss or production during core sample storage was observed. Concentrations from cuttings and mud gas logging (including IsoTubes ® ) were much lower than from cores, but correlated well. Simulations suggest the lower concentrations from cuttings can be attributed to drilling time, and therefore their use to define gas concentration profiles may have inherent limitations. Calculations based on mud gas logging show the method can provide estimates of core concentrations if operational parameters for the mud gas capture cylinder are quantified. The δ 13 C-CH 4 measured from mud gas, IsoTubes ® , cuttings, and core samples are consistent, exhibiting slight variations that should not alter the implications of the results in identifying the sources of the gases. This study shows core and mud gas techniques and, to a lesser extent, cuttings, can generate high-resolution depth profiles of dissolved hydrocarbon gas concentrations and their isotopes. © 2016, National Ground Water Association.

Physical properties of sidewall cores from Decatur, Illinois

USGS Publications Warehouse

Morrow, Carolyn A.; Kaven, Joern; Moore, Diane E.; Lockner, David A.

2017-10-18

To better assess the reservoir conditions influencing the induced seismicity hazard near a carbon dioxide sequestration demonstration site in Decatur, Ill., core samples from three deep drill holes were tested to determine a suite of physical properties including bulk density, porosity, permeability, Young’s modulus, Poisson’s ratio, and failure strength. Representative samples of the shale cap rock, the sandstone reservoir, and the Precambrian basement were selected for comparison. Physical properties were strongly dependent on lithology. Bulk density was inversely related to porosity, with the cap rock and basement samples being both least porous (

Preliminary report on the geology, geophysics and hydrology of USBM/AEC Colorado core hole No. 2, Piceance Creek Basin, Rio Blanco County, Colorado

USGS Publications Warehouse

Ege, J.R.; Carroll, R.D.; Welder, F.A.

1967-01-01

Approximately 1,400 feet of continuous core was taken .between 800-2,214 feet in depth from USBM/AEC Colorado core hole No. 2. The drill, site is located in the Piceance Creek basin, Rio Blanco County, Colorado. From ground surface the drill hole penetrated 1,120 feet of the Evacuation Creek Member and 1,094 feet of oil shale in the Parachute Creek Member of the Green River Formation. Oil shale yielding more than 20 gallons per ton occurs between 1,260-2,214 feet in depth. A gas explosion near the bottom of the hole resulted in abandonment of the exploratory hole which was still in oil shale. The top of the nahcolite zone is at 1,693 feet. Below this depth the core contains common to abundant amounts of sodium bicarbonate salt intermixed with oil shale. The core is divided into seven structural zones that reflect changes in joint intensity, core loss and broken core due to natural causes. The zone of poor core recovery is in the Interval between 1,300-1,450 feet. Results of preliminary geophysical log analyses indicate that oil yields determined by Fischer assay compare favorably with yields determined by geophysical log analyses. There is strong evidence that analyses of complete core data from Colorado core holes No. 1 and No. 2 reveal a reliable relationship between geophysical log response and oil yield. The quality of the logs is poor in the rich shale section and the possibility of repeating the logging program should be considered. Observations during drilling, coring, and hydrologic testing of USBM/AEC Colorado core hole No. 2 reveal that the Parachute Creek Member of the Green River Formation is the principal aquifer water in the Parachute Creek Member is under artesian pressure. The upper part of the aquifer has a higher hydrostatic head than, and is hydrologically separated from the lower part of the aquifer. The transmissibility of the aquifer is about 3500 gpd per foot. The maximum water yield of the core hole during testing was about 500 gpm. Chemical analyses of water samples indicate that the content of dissolved solids is low, the principal ions being sodium and bicarbonate. Although the hole was originally cored, to a depth of 2,214 feet, ,the present depth is about 2,100 feet. This report presents a preliminary evaluation of core examination, geophysical log interpretation and hydrological tests from the USBM/AEC Colorado core hole No. 2. The cooperation of the U.S. Bureau of Mines is gratefully acknowledged. The reader is referred to Carroll and others (1967) for comparison of USBM/AEC Col0rado core hole No. 1 with USBM/AEC Colorado core hole No. 2.

Geochemical and mineralogical characterization of the Eagle Ford Shale: Results from the USGS Gulf Coast #1 West Woodway core

USGS Publications Warehouse

Birdwell, Justin E.; Boehlke, Adam; Paxton, Stanley T.; Whidden, Katherine J.; Pearson, Ofori N.

2017-01-01

The Eagle Ford shale is a major continuous oil and gas resource play in southcentral Texas and a source for other oil accumulations in the East Texas Basin. As part of the U.S. Geological Survey’s (USGS) petroleum system assessment and research efforts, a coring program to obtain several immature, shallow cores from near the outcrop belt in central Texas has been undertaken. The first of these cores, USGS Gulf Coast #1 West Woodway, was collected near Waco, Texas, in September 2015 and has undergone extensive geochemical and mineralogical characterization using routine methods to ascertain variations in the lithologies and chemofacies present in the Eagle Ford at this locale. Approximately 270 ft of core was examined for this study, focusing on the Eagle Ford Group interval between the overlying Austin Chalk and underlying Buda Limestone (~20 ft of each). Based on previous work to identify the stratigraphy of the Eagle Ford Group in the Waco area and elsewhere (Liro et al., 1994; Robison, 1997; Ratcliffe et al., 2012; Boling and Dworkin, 2015; Fairbanks et al., 2016, and references therein), several lithological units were expected to be present, including the Pepper Shale (or Woodbine), the Lake Waco Formation (or Lower Eagle Ford, including the Bluebonnet, Cloice, and Bouldin or Flaggy Cloice members), and the South Bosque Member (Upper Eagle Ford). The results presented here indicate that there are three major chemofacies present in the cored interval, which are generally consistent with previous descriptions of the Eagle Ford Group in this area. The relatively high-resolution sampling (every two ft above the Buda, 432.8 ft depth, and below the Austin Chalk, 163.5 ft depth) provides great detail in terms of geochemical and mineralogical properties supplementing previous work on immature Eagle Ford Shale near the outcrop belt.

Helium release during shale deformation: Experimental validation

DOE PAGES

Bauer, Stephen J.; Gardner, W. Payton; Heath, Jason E.

2016-07-01

This paper describes initial experimental results of helium tracer release monitoring during deformation of shale. Naturally occurring radiogenic 4He is present in high concentration in most shales. During rock deformation, accumulated helium could be released as fractures are created and new transport pathways are created. We present the results of an experimental study in which confined reservoir shale samples, cored parallel and perpendicular to bedding, which were initially saturated with helium to simulate reservoir conditions, are subjected to triaxial compressive deformation. During the deformation experiment, differential stress, axial, and radial strains are systematically tracked. Release of helium is dynamically measuredmore » using a helium mass spectrometer leak detector. Helium released during deformation is observable at the laboratory scale and the release is tightly coupled to the shale deformation. These first measurements of dynamic helium release from rocks undergoing deformation show that helium provides information on the evolution of microstructure as a function of changes in stress and strain.« less

Developing a shale heterogeneity index to predict fracture response in the Mancos Shale

NASA Astrophysics Data System (ADS)

DeReuil, Aubry; Birgenheier, Lauren; McLennan, John

2017-04-01

The interplay between sedimentary heterogeneity and fracture propagation in mudstone is crucial to assess the potential of low permeability rocks as unconventional reservoirs. Previous experimental research has demonstrated a relationship between heterogeneity and fracture of brittle rocks, as discontinuities in a rock mass influence micromechanical processes such as microcracking and strain localization, which evolve into macroscopic fractures. Though numerous studies have observed heterogeneity influencing fracture development, fundamental understanding of the entire fracture process and the physical controls on this process is still lacking. This is partly due to difficulties in quantifying heterogeneity in fine-grained rocks. Our study tests the hypothesis that there is a correlation between sedimentary heterogeneity and the manner in which mudstone is fractured. An extensive range of heterogeneity related to complex sedimentology is represented by various samples from cored intervals of the Mancos Shale. Samples were categorized via facies analysis consisting of: visual core description, XRF and XRD analysis, SEM and thin section microscopy, and reservoir quality analysis that tested porosity, permeability, water saturation, and TOC. Systematic indirect tensile testing on a broad variety of facies has been performed, and uniaxial and triaxial compression testing is underway. A novel tool based on analytically derived and statistically proven relationships between sedimentary geologic and geomechanical heterogeneity is the ultimate result, referred to as the shale heterogeneity index. Preliminary conclusions from development of the shale heterogeneity index reveal that samples with compositionally distinct bedding withstand loading at higher stress values, while texturally and compositionally homogeneous, bedded samples fail at lower stress values. The highest tensile strength results from cemented Ca-enriched samples, medial to high strength samples have approximately equivalent proportions of Al-Ca-Si compositions, while Al-rich samples have consistently low strength. Moisture preserved samples fail on average at approximately 5 MPa lower than dry samples of similar facies. Additionally, moisture preserved samples fail in a step-like pattern when tested perpendicular to bedding. Tensile fractures are halted at heterogeneities and propagate parallel to bedding planes before developing a through-going failure plane, as opposed to the discrete, continuous fractures that crosscut dry samples. This result suggests that sedimentary heterogeneity plays a greater role in fracture propagation in moisture preserved samples, which are more indicative of in-situ reservoir conditions. Stress-strain curves will be further analyzed, including estimation of an energy released term based on post-failure response, and an estimation of volume of cracking measure on the physical fracture surface.

DOE Office of Scientific and Technical Information (OSTI.GOV)

Kalyoncu, R.S.; Boyer, J.P.; Snyder, M.J.

Partial data on the characterization of Well 0-1 (Christian County, Kentucky) shales were first reported in the Fifth Quarterly Technical Progress Report on January 1978. This report presents all the characterization data and its analysis on the 0-1 shales. Coring of Well 0-1 was accomplished in October 1976. A total of 17 samples were obtained, 13 for Battelle and 4 for other DOE Contractors. Methane is almost the sole hydrocarbon gas present in these shales, with higher chain hydrocarbon gases nearly nonexistent. An apparent increase in hydrocarbon gas contents with shale depth is observed. Other organic contents (in the formmore » of carbon and hydrogen) also show an increase with increasing shale depth. An increase in hydrocarbon gas contents with carbon and hydrogen contents is also noticeable. Natural gas, carbon and hydrogen contents all vary inversely with bulk densities. 0-1 shales show low mercury intrusion porosities and very low to negligible gas permeabilities. Lithology of these shales is very similar to those previously reported, quartz being the most abundant single mineral. Illite and kaolin are the major clay minerals with a number of carbonates (nahcolite, sortite, siderite) present in moderate quantities. Pyrite is also observed in significant quantities.« less

Attenuation of Chemical Reactivity of Shale Matrixes following Scale Precipitation

NASA Astrophysics Data System (ADS)

Li, Q.; Jew, A. D.; Kohli, A. H.; Alalli, G.; Kiss, A. M.; Kovscek, A. R.; Zoback, M. D.; Brown, G. E.; Maher, K.; Bargar, J.

2017-12-01

Introduction of fracture fluids into shales initiates a myriad of fluid-rock reactions that can strongly influence migration of fluid and hydrocarbon through shale/fracture interfaces. Due to the extremely low permeability of shale matrixes, studies on chemical reactivity of shales have mostly focused on shale surfaces. Shale-fluid interactions inside within shale matrixes have not been examined, yet the matrix is the primary conduit through which hydrocarbons and potential contaminants are transmitted. To characterize changes in matrix mineralogy, porosity, diffusivity, and permeability during hydraulic stimulation, we reacted Marcellus (high clay and low carbonate) and Eagle Ford (low clay and high carbonate) shale cores with fracture fluids for 3 weeks at elevated pressure and temperature (80 oC, and 77 bars). In the carbonate-poor Marcellus system, fluid pH increased from 2 to 4, and secondary Fe(OH)3 precipitates were observed in the fluid. Sulfur X-ray fluorescence maps show that fluids had saturated and reacted with the entire 1-cm-diameter core. In the carbonate-rich Eagle Ford system, pH increased from 2 to 6 due to calcite dissolution. When additional Ba2+ and SO42- were present (log10(Q/K)=1.3), extensive barite precipitation was observed in the matrix of the Eagle Ford core (and on the surface). Barite precipitation was also observed on the surface of the Marcellus core, although to a lesser extent. In the Marcellus system, the presence of barite scale attenuated diffusivity in the matrix, as demonstrated by sharply reduced Fe leaching and much less sulfide oxidation. Systematic studies in homogeneous solution show that barite scale precipitation rates are highly sensitive to pH, salinity, and the presence of organic compounds. These findings imply that chemical reactions are not confined to shale/fluid interfaces but can penetrate into shale matrices, and that barite scale formation can clog diffusion pathways for both fluid and hydrocarbon.

Organic / inorganic carbon content and isotope analysis of 3.1Ga Cleaverville Formation in Pilbara, Australia: Result of DXCL project

NASA Astrophysics Data System (ADS)

Miki, T.; Kiyokawa, S.; Ito, T.; Yamaguchi, K. E.; Ikehara, M.

2014-12-01

DXCL project was targeted for 3.2-3.1 Ga hydrothermal chert-black shale (Dixon Island Formation) and black shale-banded iron formation (Cleaverville Formation). CL3 core (200m long) was drilled from 1) upper part of Black Shale Member (35m thick) to 2) lower part of BIF Member (165m thick) of the Cleaverville Formation. Here, the BIF Member can be divided into three submembers; Greenish shale-siderite (50m thick), Magnetite-siderite (55m thick) and Black shale-siderite (60m) submembers. In this study, we used bulk samples and samples treated by hot hydrochloric acid in order to extract organic carbon. 　The Black shale Member consists of black carbonaceous　matter and fine grain quartz (< 100μm). Organic carbon content (Corg) of black shale is 1.2% in average and organic carbon isotope ratio (δ13Corg) is -31.4 to -28.7‰. On the other hand, inorganic carbon isotope ratio of siderite (δ13Ccarb) was -5.2 to +12.6‰. 　In the BIF Member, the Greenish shale-siderite submember is composed of well laminated greenish sideritic shale and white chert (<7mm thick), which is gradually increase from black shale of the Black shale Member through about 10m. Magnetite-siderite submember contains very fine magnetite lamination with inter-bedded greenish sideritic shale and siderite lamination. Hematite is identified near fractured part. The Black shale-siderite submember is composed of black shale, siderite and chert bands. 　1) Siderite layers of these three submembers showedδ13Ccarb value of -14.6 to -3.8‰. Corg and δ13Corg content are 0.2% and -18.3 to -0.3‰. 2) Siderite grains within greenish sideritic shales showedδ13Ccarb value of -12.9 to +15.0‰. 3) Black shale of Corg and δ13Corg content in the BIF Member are 0.1% and -36.3 to -17.1‰ respectively. 　We found great difference in values of δ13Ccarb of siderite. One is Corg-rich shale (up to +15.0‰) and the other is Corg-poor siderite layers (up to -3.8‰). The lighter value of siderite layers may be originated from precursor organic carbon which is strongly affected by biological activity.

The effect of deformation on two-phase flow through proppant-packed fractured shale samples: A micro-scale experimental investigation

NASA Astrophysics Data System (ADS)

Arshadi, Maziar; Zolfaghari, Arsalan; Piri, Mohammad; Al-Muntasheri, Ghaithan A.; Sayed, Mohammed

2017-07-01

We present the results of an extensive micro-scale experimental investigation of two-phase flow through miniature, fractured reservoir shale samples that contained different packings of proppant grains. We investigated permeability reduction in the samples by conducting experiments under a wide range of net confining pressures. Three different proppant grain distributions in three individual fractured shale samples were studied: i) multi-layer, ii) uniform mono-layer, and iii) non-uniform mono-layer. We performed oil-displacing-brine (drainage) and brine-displacing-oil (imbibition) flow experiments in the proppant packs under net confining pressures ranging from 200 to 6000 psi. The flow experiments were performed using a state-of-the-art miniature core-flooding apparatus integrated with a high-resolution, X-ray microtomography system. We visualized fluid occupancies, proppant embedment, and shale deformation under different flow and stress conditions. We examined deformation of pore space within the proppant packs and its impact on permeability and residual trapping, proppant embedment due to changes in net confining stress, shale surface deformation, and disintegration of proppant grains at high stress conditions. In particular, geometrical deformation and two-phase flow effects within the proppant pack impacting hydraulic conductivity of the medium were probed. A significant reduction in effective oil permeability at irreducible water saturation was observed due to increase in confining pressure. We propose different mechanisms responsible for the observed permeability reduction in different fracture packings. Samples with dissimilar proppant grain distributions showed significantly different proppant embedment behavior. Thinner proppant layer increased embedment significantly and lowered the onset confining pressure of embedment. As confining stress was increased, small embedments caused the surface of the shale to fracture. The produced shale fragments were then entrained by the flow and partially blocked pore-throat connections within the proppant pack. Deformation of proppant packs resulted in significant changes in waterflood residual oil saturation. In-situ contact angles measured using micro-CT images showed that proppant grains had experienced a drastic alteration of wettability (from strong water-wet to weakly oil-wet) after the medium had been subjected to flow of oil and brine for multiple weeks. Nanometer resolution SEM images captured nano-fractures induced in the shale surfaces during the experiments with mono-layer proppant packing. These fractures improved the effective permeability of the medium and shale/fracture interactions.

Stress-dependent elastic properties of shales—laboratory experiments at seismic and ultrasonic frequencies

NASA Astrophysics Data System (ADS)

Szewczyk, Dawid; Bauer, Andreas; Holt, Rune M.

2018-01-01

Knowledge about the stress sensitivity of elastic properties and velocities of shales is important for the interpretation of seismic time-lapse data taken as part of reservoir and caprock surveillance of both unconventional and conventional oil and gas fields (e.g. during 4-D monitoring of CO2 storage). Rock physics models are often developed based on laboratory measurements at ultrasonic frequencies. However, as shown previously, shales exhibit large seismic dispersion, and it is possible that stress sensitivities of velocities are also frequency dependent. In this work, we report on a series of seismic and ultrasonic laboratory tests in which the stress sensitivity of elastic properties of Mancos shale and Pierre shale I were investigated. The shales were tested at different water saturations. Dynamic rock engineering parameters and elastic wave velocities were examined on core plugs exposed to isotropic loading. Experiments were carried out in an apparatus allowing for static-compaction and dynamic measurements at seismic and ultrasonic frequencies within single test. For both shale types, we present and discuss experimental results that demonstrate dispersion and stress sensitivity of the rock stiffness, as well as P- and S-wave velocities, and stiffness anisotropy. Our experimental results show that the stress-sensitivity of shales is different at seismic and ultrasonic frequencies, which can be linked with simultaneously occurring changes in the dispersion with applied stress. Measured stress sensitivity of elastic properties for relatively dry samples was higher at seismic frequencies however, the increasing saturation of shales decreases the difference between seismic and ultrasonic stress-sensitivities, and for moist samples stress-sensitivity is higher at ultrasonic frequencies. Simultaneously, the increased saturation highly increases the dispersion in shales. We have also found that the stress-sensitivity is highly anisotropic in both shales and that in some of the cases higher stress-sensitivity of elastic properties can be seen in the direction parallel to the bedding plane.

Weathering of the New Albany Shale, Kentucky, USA: I. Weathering zones defined by mineralogy and major-element composition

USGS Publications Warehouse

Tuttle, M.L.W.; Breit, G.N.

2009-01-01

Comprehensive understanding of chemical and mineralogical changes induced by weathering is valuable information when considering the supply of nutrients and toxic elements from rocks. Here minerals that release and fix major elements during progressive weathering of a bed of Devonian New Albany Shale in eastern Kentucky are documented. Samples were collected from unweathered core (parent shale) and across an outcrop excavated into a hillside 40 year prior to sampling. Quantitative X-ray diffraction mineralogical data record progressive shale alteration across the outcrop. Mineral compositional changes reflect subtle alteration processes such as incongruent dissolution and cation exchange. Altered primary minerals include K-feldspars, plagioclase, calcite, pyrite, and chlorite. Secondary minerals include jarosite, gypsum, goethite, amorphous Fe(III) oxides and Fe(II)-Al sulfate salt (efflorescence). The mineralogy in weathered shale defines four weathered intervals on the outcrop-Zones A-C and soil. Alteration of the weakly weathered shale (Zone A) is attributed to the 40-a exposure of the shale. In this zone, pyrite oxidization produces acid that dissolves calcite and attacks chlorite, forming gypsum, jarosite, and minor efflorescent salt. The pre-excavation, active weathering front (Zone B) is where complete pyrite oxidation and alteration of feldspar and organic matter result in increased permeability. Acidic weathering solutions seep through the permeable shale and evaporate on the surface forming abundant efflorescent salt, jarosite and minor goethite. Intensely weathered shale (Zone C) is depleted in feldspars, chlorite, gypsum, jarosite and efflorescent salts, but has retained much of its primary quartz, illite and illite-smectite. Goethite and amorphous FE(III) oxides increase due to hydrolysis of jarosite. Enhanced permeability in this zone is due to a 14% loss of the original mass in parent shale. Denudation rates suggest that characteristics of Zone C were acquired over 1 Ma. Compositional differences between soil and Zone C are largely attributed to illuvial processes, formation of additional Fe(III) oxides and incorporation of modern organic matter.

Re-Os Geochronology Pins Age and Os Isotope Composition of Middle Triassic Black Shales and Seawater, Barents Sea and Spitsbergen (Svalbard)

NASA Astrophysics Data System (ADS)

Xu, G.; Hannah, J. L.; Bingen, B.; Stein, H. J.; Yang, G.; Zimmerman, A.; Weitschat, W.; Weiss, H. M.

2008-12-01

Absolute age control throughout the Triassic is extraordinarily sparse. Two "golden spikes" have been added recently (http://www.stratigraphy.org/cheu.pdf) within the otherwise unconstrained Triassic, but ages of stage boundaries remain controversial. Here we report two Re-Os isochrons for Anisian (Middle Triassic) black shales from outcrop in western Svalbard and drill core from the Svalis Dome about 600 km to the SE in the Barents Sea. Black shales of the Blanknuten Member, Botneheia Formation, from the type section at Botneheia, western Spitsbergen (Svalbard), have total organic carbon (TOC) contents of 2.6 to 6.0 wt%. Rock-Eval data suggest moderately mature (Tmax = 440-450° C) Type II-III kerogens (Hydrogen Index (HI) = 232-311 mg HC/g TOC). Re-Os data yield a well-constrained Model 3 age of 241 Ma and initial 187Os/188Os (Osi) of 0.83 (MSWD = 16, n = 6). Samples of the possibly correlative Steinkobbe Formation from IKU core hole 7323/07-U-04 into the Svalis Dome in the Barents Sea (at about 73°30'N, 23°15'E) have TOC contents of 1.4 to 2.4%. Rock-Eval data suggest immature (Tmax = 410-430°) Type II-III kerogens (HI = 246-294 mg HC/g TOC). Re-Os data yield a precise Model 1 age of 239 Ma and Osi of 0.776 (MSWD = 0.2, n = 5). The sampled section of Blanknuten shale underlies a distinctive Frechitas (formerly Ptychites) layer, and is therefore assumed to be middle Anisian. The Steinkobbe core was sampled at 99-100 m, just above the Olenekian-Anisian transition. It is therefore assumed to be lower Anisian. The two isochron ages overlap within uncertainty, and fall within constraints provided by biozones and the current ICS-approved stage boundary ages. The Re-Os ages support the correlation of the Botneheia and Steinkobbe formations. The nearly identical Osi ratios suggest regional homogeneity of seawater and provide new information for the Os seawater curve, marking a relatively high 187Os/188Os ratio during profound ocean anoxia in the Middle Triassic.

Characterization of Unconventional Reservoirs: CO2 Induced Petrophysics

NASA Astrophysics Data System (ADS)

Verba, C.; Goral, J.; Washburn, A.; Crandall, D.; Moore, J.

2017-12-01

As concerns about human-driven CO2 emissions grow, it is critical to develop economically and environmentally effective strategies to mitigate impacts associated with fossil energy. Geologic carbon storage (GCS) is a potentially promising technique which involves the injection of captured CO2 into subsurface formations. Unconventional shale formations are attractive targets for GCS while concurrently improving gas recovery. However, shales are inherently heterogeneous, and minor differences can impact the ability of the shale to effectively adsorb and store CO2. Understanding GCS capacity from such endemic heterogeneities is further complicated by the complex geochemical processes which can dynamically alter shale petrophysics. We investigated the size distribution, connectivity, and type (intraparticle, interparticle, and organic) of pores in shale; the mineralogy of cores from unconventional shale (e.g. Bakken); and the changes to these properties under simulated GCS conditions. Electron microscopy and dual beam focused ion beam scanning electron microscopy were used to reconstruct 2D/3D digital matrix and pore structures. Comparison of pre and post-reacted samples gives insights into CO2-shale interactions - such as the mechanism of CO2 sorption in shales- intended for enhanced oil recovery and GCS initiatives. These comparisons also show how geochemical processes proceed differently across shales based on their initial diagenesis. Results show that most shale pore sizes fall within meso-macro pore classification (> 2 nm), but have variable porosity and organic content. The formation of secondary minerals (calcite, gypsum, and halite) may play a role in the infilling of fractures and pore spaces in the shale, which may reduce permeability and inhibit the flow of fluids.

Cretaceous shales from the western interior of North America: sulfur/carbon ratios and sulfur-isotope composition.

USGS Publications Warehouse

Gautier, D.L.

1986-01-01

Sulphur/carbon ratios in cores of selected Cretaceous marine shales average 0.67, a value greater than that observed in recent marine sediments and much higher than global values calculated for the Cretaceous. This may be ascribed to generally low levels of bioturbation and enhanced efficiency of sulphate reduction due to low oxygen levels in Cretaceous seaways. Isotopic compositions of pyrite sulphur vary systematically with level of oxygenation of the depositional environment and therefore with organic carbon abundance and type of organic matter. Samples with >4% organic carbon are extremely depleted in 34S (mean delta 34S -31per mille) and contain hydrogen-rich organic matter. Samples containing <1.5% organic carbon display relatively 'heavy' but wide-ranging delta 34S values (-34.6 to +16.8per mille) and contain hydrogen-poor organic matter. Samples with intermediate amounts of organic carbon have average delta 34S of -25.9per mille and contain both types of organic matter. Relations between the nature of these shales, and their sedimentation rate and depositional environment are discussed.-L.C.H.

Re-assessing the Molybdenum Isotope Composition of Pre-GOE Seawater: Evidence for Dynamic Ocean Redox

NASA Astrophysics Data System (ADS)

Ostrander, C. M.; Kendall, B.; Roy, M.; Romaniello, S. J.; Nunn, S. J.; Gordon, G. W.; Olson, S. L.; Lyons, T. W.; Zheng, W.; Anbar, A. D.

2016-12-01

Molybdenum (Mo) isotope compositions of Archean shales can provide important insights into ocean and atmosphere redox dynamics prior to the Great Oxidation Event (GOE). Unfortunately, the relatively limited Mo isotope database and small number of sample sets for Archean shales do not allow for in-depth reconstructions and specifically make it difficult to differentiate global from local effects. To accurately estimate the Mo isotope composition of Archean seawater and better investigate the systematics of local and global redox, more complete sample sets are needed. We carried out a Mo isotope analysis of the euxinic 2.65 Ga Roy Hill Shale sampled in two stratigraphically correlated cores, and revisited the well-studied euxinic 2.5 Ga Mt. McRae Shale in higher resolution. Our data show contrasting Mo isotope values in the 2.65 Ga Roy Hill Shale between near- and offshore depositional environments, with systematically heavier isotope values in the near-shore environment. High-resolution analysis of the Mt. McRae Shale yields oscillating Mo concentrations and isotope values at the cm- to dm-scale during the well-characterized "whiff of O2" interval, with the heaviest isotope values measured during euxinic deposition. Variations in the measured isotope values within each section are primarily associated with redox changes in the local depositional environment and amount of detrital content. Both non-quantitative removal of Mo associated with incorporation into non-euxinic sediments and large detrital Mo contributions shift some measured isotopic compositions toward lighter values. This is readily apparent in the near-shore Roy Hill Shale section and the Mt. McRae Shale, but may not fully explain variations observed in the offshore Roy Hill Shale deposit. Here, euxinic deposition is not accompanied by Mo enrichments or isotopic compositions as heavy as the near-shore equivalent, even after detrital correction. This disparity between the near- and offshore environment could signify spatial variation in the Mo isotope composition of 2.65 Ga seawater and highlights the need for multi-site and high-resolution studies in order to best assess paleoenvironmental conditions.

43 CFR 3931.80 - Core or test hole samples and cuttings.

Code of Federal Regulations, 2011 CFR

2011-10-01

... OF LAND MANAGEMENT, DEPARTMENT OF THE INTERIOR RANGE MANAGEMENT (4000) MANAGEMENT OF OIL SHALE.... The records must include a log of all strata penetrated and conditions encountered, such as water, gas... operation or any deposit of oil, gas, other mineral substances, or ground water. (c) Operators may convert...

43 CFR 3931.80 - Core or test hole samples and cuttings.

Code of Federal Regulations, 2013 CFR

2013-10-01

... OF LAND MANAGEMENT, DEPARTMENT OF THE INTERIOR MINERALS MANAGEMENT (3000) MANAGEMENT OF OIL SHALE.... The records must include a log of all strata penetrated and conditions encountered, such as water, gas... operation or any deposit of oil, gas, other mineral substances, or ground water. (c) Operators may convert...

43 CFR 3931.80 - Core or test hole samples and cuttings.

Code of Federal Regulations, 2012 CFR

2012-10-01

... OF LAND MANAGEMENT, DEPARTMENT OF THE INTERIOR MINERALS MANAGEMENT (3000) MANAGEMENT OF OIL SHALE.... The records must include a log of all strata penetrated and conditions encountered, such as water, gas... operation or any deposit of oil, gas, other mineral substances, or ground water. (c) Operators may convert...

43 CFR 3931.80 - Core or test hole samples and cuttings.

Code of Federal Regulations, 2014 CFR

2014-10-01

... OF LAND MANAGEMENT, DEPARTMENT OF THE INTERIOR MINERALS MANAGEMENT (3000) MANAGEMENT OF OIL SHALE.... The records must include a log of all strata penetrated and conditions encountered, such as water, gas... operation or any deposit of oil, gas, other mineral substances, or ground water. (c) Operators may convert...

Geochemical Comparison of Four Cores from the Manson Impact Structure

NASA Technical Reports Server (NTRS)

Korotev, Randy L.; Rockow, Kaylynn M.; Jolliff, Bradley L.; Haskin, Larry A.; McCarville, Peter; Crossey, Laura J.

1996-01-01

Concentrations of 33 elements were determined in relatively unaltered, matrix-rich samples of impact breccia at approximately 3-m-depth intervals in the M-1 core from the Manson impact structure, Iowa. In addition, 46 matrix-rich samples from visibly altered regions of the M-7, M-8, and M-10 cores were studied, along with 42 small clasts from all four cores. Major element compositions were determined for a subset of impact breccias from the M-1 core, including matrix-rich impact-melt breccia. Major- and trace-element compositions were also determined for a suite of likely target rocks. In the M-1 core, different breccia units identified from lithologic examination of cores are compositionally distinct. There is a sharp compositional discontinuity at the boundary between the Keweenawan-shale-clast breccia and the underlying unit of impact-melt breccia (IMB) for most elements, suggesting minimal physical mixing between the two units during emplacement. Samples from the 40-m-thick IMB (M-1) are all similar to each other in composition, although there are slight increases in concentration with depth for those elements that have high concentrations in the underlying fragmental-matrix suevite breccia (SB) (e.g., Na, Ca, Fe, Sc), presumably as a result of greater clast proportions at the bottom margin of the unit of impact-melt breccia. The high degree of compositional similarity we observe in the impact-melt breccias supports the interpretation that the matrix of this unit represents impact melt. That our analyses show such compositional similarity results in part from our technique for sampling these breccias: for each sample we analyzed a few small fragments (total mass: approximately 200 mg) selected to be relatively free of large clasts and visible signs of alteration instead of subsamples of powders prepared from a large mass of breccia. The mean composition of the matrix-rich part of impact-melt breccia from the M-1 core can be modeled as a mixture of approximately 35% shale and siltstone (Proterozoic "Red Clastics"), 23% granite, 40% hornblende-biotite gneiss, and a small component (less than 2%) of mafic-dike rocks.

Deep-Time drilling in the Australian Archean: the Agouron Institute geobiological drilling project. (Invited)

NASA Astrophysics Data System (ADS)

Buick, R.

2010-12-01

The Agouron Institute has sponsored deep-time drilling across the South African Archean-Proterozoic boundary, investigating the rise of oxygen over an onshore-offshore environmental transect. It is now supporting a drilling program in the Australian Archean of the Pilbara Craton, addressing a similar theme but with the added goal of resolving controversy over the age and origin of hydrocarbon biomarker molecules in ancient kerogenous shales. As these have been claimed to provide evidence for the evolution of oxygenic photosynthesis long before the rise of atmospheric oxygen to persistently high levels during the ~2.3 Ga “Great Oxidation Event”, their syngenesis with their host shales is thus of critical importance for the interpretation of Earth’s early oxygenation history. During the first drilling season, 3 holes were drilled using techniques and equipment to minimize organic geochemical contamination (new drill-string components cleaned before drilling potentially biomarker-bearing rocks, pre-contamination of drilling fluid with a synthetic organic compound of similar geochemical characteristics to biomarkers, sterile cutting and storage of samples immediately upon retrieval from the core-barrel). The initial hole was a blank control for organic geochemistry, drilled into rocks too metamorphosed to retain biomarker molecules. These rocks, cherts, carbonates and pelites of the 3.52 Ga Coucal Formation, Coonterunah Group, have been metamorphosed to upper greenschist facies at temperatures near 500°C and so should have had any ancient soluble hydrocarbons destroyed. However, because they contain both carbonate and organic carbon, these rocks can instead provide isotopic information about the earliest evolution of biological metabolism as they possess residues of both the reactant and product sides of the carbon-fixation reaction. The second hole sampled an on-shore section of carbonates and kerogenous shales in the ~2.65 Ga Carawine Dolomite and Lewin Shale of the Hamersley Group near Yilgalong Creek. This location had been previously drilled by a mining company in the 1980’s and the core provided the highest biomarker yields of any Archean rocks thus far sampled. As it has been suggested that these biomarkers are non-indigenous contaminants, one possibility is that they were introduced into the drill-core at some time between drilling and sampling, so this hole tests that hypothesis. If biomarker concentrations and ratios differ significantly between the two adjacent holes with differing exposures to post-drilling contaminants, then clearly contamination has affected one or other of the cores. The third hole sampled an off-shore equivalent, through banded irons and kerogenous shales of the ~2.65 Ga Marra Mamba and Jeerinah Formations of the Hamersley Group near Cowcumba Creek. Another opportunity for contamination may arise during post-depositional but pre-drilling hydrocarbon migration, when biomarkers can potentially be introduced into previously barren rocks by younger oils, so this hole tests that possibility. As it was drilled through the same stratigraphic interval and structural domain as the second hole but in a different environment, biomarker ratios should be similar if contaminated but different if indigenous.

Changes in porosity and organic matter phase distribution monitored by NMR relaxometry following hydrous pyrolysis under uniaxial confinement

USGS Publications Warehouse

Washburn, Kathryn E.; Birdwell, Justin E.; Lewan, Michael D.; Miller, Michael; Baez, Luis; Beeney, Ken; Sonnenberg, Steve

2013-01-01

Artificial maturation methods are used to induce changes in source rock thermal maturity without the uncertainties that arise when comparing natural samples from a particular basin that often represent different levels of maturation and different lithofacies. A novel uniaxial confinement clamp was used on Woodford Shale cores in hydrous pyrolysis experiments to limit sample expansion by simulating the effect of overburden present during thermal maturation in natural systems. These samples were then subjected to X-ray computed tomography (X-CT) imaging and low-field nuclear magnetic resonance (LF-NMR) relaxometry measurements. LF-NMR relaxometry is a noninvasive technique commonly used to measure porosity and pore-size distributions in fluid-filled porous media, but may also measure hydrogen present in hydrogen-bearing organic solids. Standard T1 and T2 relaxation distributions were determined and two dimensional T1-T2 correlation measurements were performed on the Woodford Shale cores. The T1-T2 correlations facilitate resolution of organic phases in the system. The changes observed in NMR-relaxation times correspond to bitumen and lighter hydrocarbon production that occur as source rock organic matter matures. The LF-NMR porosities of the core samples at maximum oil generation are significantly higher than porosities measured by other methods. This discrepancy likely arises from the measurement of highly viscous organic constituents in addition to fluid-filled porosity. An unconfined sample showed shorter relaxation times and lower porosity. This difference is attributed to the lack of fractures observed in the unconfined sample by X-CT.

Characterization and growth mechanism of a peculiar nodular structure in shale: Comprehensive study over the Sitakund anticline, Bengal basin.

NASA Astrophysics Data System (ADS)

Gazi, M. Y.; Kabir, S. M. M.; Imam, M. B.

2017-12-01

Nodular shales commonly occur in comparatively older and silty shales near the axial (proximity to core) region of Sitakund Anticline (Study area), Sitapahar Anticline, Patharia Structure, Sylhet Anticline and Mirinja Anticline as observed. Stratigraphically, they are pronounced in the Surma group of Neogene succession. They are less abundant in limb portion. In many outcrop, they are found in the incompetent bed with the obliterated bedding bounded by well bedded competent beds. Their occurrence are sporadic rather than continuous along and across the strike of the bed. At some places huge number cluster of small and big nodular shales occur while in the other places, they occur as isolated mass in the highly disturbed or obliterated beds. The Surma group is the prime startigraphic unit in Bangladesh with major economic and academic importance. Yet there is a lack of comprehensive characterization of mudrocks of Surma group. This has prompted the present research to be undertaken. An initial field based study has been followed by detail textural, mineralogical, petrological and geochemical by using upscale laboratory techniques that include Thin Section Microscopy, Laser Particle Size Analyses, X-ray Diffraction (XRD), Scanning Electron Microscopy (SEM), and X-ray Florescence (XRF). From laser diffraction analysis, it is evident that nodular shales are silty in nature containing approximately 60% silt (Mainly quartz). XRD pattern shows that Nodular shale contains clay minerals, predominantly illite, Kaolinite, Chlorite and expandable mixed layer clay mineral. Detail geochemical analysis of some nodular shale samples shows that there are no significant variation from other samples in major and trace element concentration. Microcrack's within the quartz grains were observed in nodular shale. Projection of 15 nodular shale long axes in outcrop shows their orientation in NNW-SSE that is parallel to the fold axis. The study suggests a new name of conventionally called nodular shales. The proposed name is "Clay Cabbage". A new model naming as "Tectono-Diagenetic (TD) Model" is proposed in this study concerning the origin of nodular shale.

Early Archean spherule beds of possible impact origin from Barberton, South Africa: A detailed mineralogical and geochemical study

NASA Technical Reports Server (NTRS)

Koeberl, Christian; Reimold, Wolf Uwe; Boer, Rudolf H.

1992-01-01

The Barberton Greenstone belt is a 3.5- to 3.2-Ga-old formation situated in the Swaziland Supergroup near Barberton, northeast Transvaal, South Africa. The belt includes a lower, predominantly volcanic sequence, and an upper sedimentary sequence (e.g., the Fig Tree Group). Within this upper sedimentary sequence, Lowe and Byerly identified a series of different beds of spherules with diameters of around 0.5-2 mm. Lowe and Byerly and Lowe et al. have interpreted these spherules to be condensates of rock vapor produced by large meteorite impacts in the early Archean. We have collected a series of samples from drill cores from the Mt. Morgan and Princeton sections near Barberton, as well as samples taken from underground exposures in the Sheba and Agnes mines. These samples seem much better preserved than the surface samples described by Lowe and Byerly and Lowe et al. Over a scale of just under 30 cm, several well-defined spherule beds are visible, interspaced with shales and/or layers of banded iron formation. Some spherules have clearly been deposited on top of a sedimentary unit because the shale layer shows indentions from the overlying spherules. Although fresher than the surface samples (e.g., spherule bed S-2), there is abundant evidence for extensive alteration, presumably by hydrothermal processes. In some sections of the cores sulfide mineralization is common. For our mineralogical and petrographical studies we have prepared detailed thin sections of all core and underground samples (as well as some surface samples from the S-2 layer for comparison). For geochemical work, layers with thicknesses in the order of 1-5 mm were separated from selected core and underground samples. The chemical analyses are being performed using neutron activation analysis in order to obtain data for about 35 trace elements in each sample. Major elements are being determined by XRF and plasma spectrometry. To clarify the history of the sulfide mineralization, sulfur isotopic compositions are being determined.

DOE Office of Scientific and Technical Information (OSTI.GOV)

Malhotra, Vivak

The USA is embarking upon tackling the serious environmental challenges posed to the world by greenhouse gases, especially carbon dioxide (CO2). The dimension of the problem is daunting. In fact, according to the Energy Information Agency, nearly 6 billion metric tons of CO2 were produced in the USA in 2007 with coal-burning power plants contributing about 2 billion metric tons. To mitigate the concerns associated with CO2 emission, geological sequestration holds promise. Among the potential geological storage sites, unmineable coal seams and shale formations in particular show promise because of the probability of methane recovery while sequestering the CO2. However.more » the success of large-scale sequestration of CO2 in coal and shale would hinge on a thorough understanding of CO2's interactions with host reservoirs. An important parameter for successful storage of CO2 reservoirs would be whether the pressurized CO2 would remain invariant in coal and shale formations under reasonable internal and/or external perturbations. Recent research has brought to the fore the potential of induced seismicity, which may result in caprock compromise. Therefore, to evaluate the potential risks involved in sequestering CO2 in Illinois bituminous coal seams and shale, we studied: (i) the mechanical behavior of Murphysboro (Illinois) and Houchin Creek (Illinois) coals, (ii) thermodynamic behavior of Illinois bituminous coal at - 100oC ≤ T ≤ 300oC, (iii) how high pressure CO2 (up to 20.7 MPa) modifies the viscosity of the host, (iv) the rate of emission of CO2 from Illinois bituminous coal and shale cores if the cores, which were pressurized with high pressure (≤ 20.7 MPa) CO2, were exposed to an atmospheric pressure, simulating the development of leakage pathways, (v) whether there are any fractions of CO2 stored in these hosts which are resistance to emission by simply exposing the cores to atmospheric pressure, and (vi) how compressive shockwaves applied to the coal and shale cores, which were pressurized with high pressure CO2, determine the fate of sequestered CO2 in these cores. Our results suggested that Illinois bituminous coal in its unperturbed state, i.e., when not pressurized with CO2, showed large variations in the mechanical properties. Modulus varied from 0.7 GPa to 3.4 GPa even though samples were extracted from a single large chunk of coal. We did not observe any glass transition for Illinois bituminous coal at - 100oC ≤ T ≤ 300oC, however, when the coal was pressurized with CO2 at ambient ≤ P ≤ 20.7 MPa, the viscosity of the coal decreased and inversely scaled with the CO2 pressure. The decrease in viscosity as a function of pressure could pose CO2 injection problems for coal as lower viscosity would allow the solid coal to flow to plug the fractures, fissures, and cleats. Our experiments also showed a very small fraction of CO2 was absorbed in coal; and when CO2 pressurized coals were exposed to atmospheric conditions, the loss of CO2 from coals was massive. Half of the sequestered gas from the coal cores was lost in less than 20 minutes. Our shockwave experiments on Illinois bituminous coal, New Albany shale (Illinois), Devonian shale (Ohio), and Utica shale (Ohio) presented clear evidence that the significant emission of the sequestered CO2 from these formations cannot be discounted during seismic activity, especially if caprock is compromised. It is argued that additional shockwave studies, both compressive and transverse, would be required for successfully mapping the risks associated with sequestering high pressure CO2 in coal and shale formations.« less

Assessing the utility of FIB-SEM images for shale digital rock physics

NASA Astrophysics Data System (ADS)

Kelly, Shaina; El-Sobky, Hesham; Torres-Verdín, Carlos; Balhoff, Matthew T.

2016-09-01

Shales and other unconventional or low permeability (tight) reservoirs house vast quantities of hydrocarbons, often demonstrate considerable water uptake, and are potential repositories for fluid sequestration. The pore-scale topology and fluid transport mechanisms within these nanoporous sedimentary rocks remain to be fully understood. Image-informed pore-scale models are useful tools for studying porous media: a debated question in shale pore-scale petrophysics is whether there is a representative elementary volume (REV) for shale models? Furthermore, if an REV exists, how does it differ among petrophysical properties? We obtain three dimensional (3D) models of the topology of microscale shale volumes from image analysis of focused ion beam-scanning electron microscope (FIB-SEM) image stacks and investigate the utility of these models as a potential REV for shale. The scope of data used in this work includes multiple local groups of neighboring FIB-SEM images of different microscale sizes, corresponding core-scale (milli- and centimeters) laboratory data, and, for comparison, series of two-dimensional (2D) cross sections from broad ion beam SEM images (BIB-SEM), which capture a larger microscale field of view than the FIB-SEM images; this array of data is larger than the majority of investigations with FIB-SEM-derived microscale models of shale. Properties such as porosity, organic matter content, and pore connectivity are extracted from each model. Assessments of permeability with single phase, pressure-driven flow simulations are performed in the connected pore space of the models using the lattice-Boltzmann method. Calculated petrophysical properties are compared to those of neighboring FIB-SEM images and to core-scale measurements of the sample associated with the FIB-SEM sites. Results indicate that FIB-SEM images below ∼5000 μm3 volume (the largest volume analyzed) are not a suitable REV for shale permeability and pore-scale networks; i.e. field of view is compromised at the expense of detailed, but often unconnected, nanopore morphology. Further, we find that it is necessary to acquire several local FIB-SEM or BIB-SEM images and correlate their extracted geometric properties to improve the likelihood of achieving representative values of porosity and organic matter volume. Our work indicates that FIB-SEM images of microscale volumes of shale are a qualitative tool for petrophysical and transport analysis. Finally, we offer alternatives for quantitative pore-scale assessments of shale.

Duvernay shale lithofacies distribution analysis in the West Canadian Sedimentary Basin

NASA Astrophysics Data System (ADS)

Zhu, Houqin; Kong, Xiangwen; Long, Huashan; Huai, Yinchao

2018-02-01

In the West Canadian Sedimentary Basin (WCSB), Duvernay shale is considered to contribute most of the Canadian shale gas reserve and production. According to global shale gas exploration and development practice, reservoir property and well completion quality are the two key factors determining the shale gas economics. The two key factors are strongly depending on shale lithofacies. On the basis of inorganic mineralogy theory, all available thin section, X-ray diffraction, scanning electron microscope (SEM), energy dispersive spectrometer (EDS) data were used to assist lithofacies analysis. Gamma ray (GR), acoustic (AC), bulk density (RHOB), neutron porosity (NPHI) and photoelectric absorption cross-section index (PE) were selected for log response analysis of various minerals. Reservoir representative equation was created constrained by quantitative core analysis results, and matrix mineral percentage of quartz, carbonate, feldspar and pyrite were calculated to classify shale lithofacies. Considering the horizontal continuity of seismic data, rock physics model was built, and acoustic impedance integrated with core data and log data was used to predict the horizontal distribution of different lithofacies. The results indicate that: (1) nine lithofacies can be categorized in Duvernay shale, (2) the horizontal distribution of different lithofacies is quite diversified, siliceous shale mainly occurs in Simonette area, calcareous shale is prone to develop in the vicinity of reef, while calcareous-siliceous shale dominates in Willesdon Green area.

Numerical modeling of oil shale fragmentation experiments

DOE Office of Scientific and Technical Information (OSTI.GOV)

Kuszmaul, J.S.

The economic development of modified in situ oil shale retorting will benefit from the ability to design a blasting scheme that creates a rubble bed of uniform permeability. Preparing such a design depends upon successfully predicting how a given explosive charge and firing sequence will fracture the oil shale. Numerical models are used to predict the extent of damage caused by a particular explosive charge. Recent single-blastwell cratering tests provided experimental measurements of the extent of damage induced by an explosion. Measuring rock damage involved crater excavation, rubble screening, crater elevation surveys, and posttest extraction of cores. These measurements weremore » compared to the damage calculated by the numerical model. Core analyses showed that the damage varied greatly from layer to layer. The numerical results also show this effect, indicating that rock damage is highly dependent on oil shale grade. The computer simulation also calculated particle velocities and dynamic stress amplitudes in the rock; predicted values agree with experimental measurements. Calculated rock fragmentation compared favorably with fragmentation measured by crater excavation and by core analysis. Because coring provides direct inspection of rock fragmentation, the use of posttest coring in future experiments is recommended.« less

Chemical Degradation of Polyacrylamide during Hydraulic Fracturing

NASA Astrophysics Data System (ADS)

Xiong, B.; Tasker, T.; Miller, Z.; Roman-White, S.; Farina, B.; Piechowicz, B.; Burgos, W.; Joshi, P.; Zhu, L.; Gorski, C.; Zydney, A.; Kumar, M.

2017-12-01

Polyacrylamide (PAM) based friction reducers are a primary ingredient of slickwater hydraulic fracturing fluids. Little is known regarding the fate of these polymers under downhole conditions, which could have important environmental impacts including strategies for reuse or treatment of flowback water. The objective of this study was to evaluate the chemical degradation of high molecular weight PAM, including the effects of shale, oxygen, temperature, pressure, and salinity. Data were obtained with a slickwater fracturing fluid exposed to both a shale sample collected from a Marcellus shale outcrop and to Marcellus core samples at high pressures/temperatures (HPT) simulating downhole conditions. Based on size exclusion chromatography analyses, the peak molecular weight of the PAM was reduced by two orders of magnitude, from roughly 10 MDa to 200 kDa under typical HPT fracturing conditions. The rate of degradation was independent of pressure and salinity but increased significantly at high temperatures and in the presence of oxygen dissolved in fracturing fluid. Results were consistent with a free radical chain scission mechanism, supported by measurements of sub-M hydroxyl radical concentrations. The shale sample adsorbed some PAM ( 30%), but importantly it catalyzed the chemical degradation of PAM, likely due to dissolution of Fe2+ at low pH. These results provide the first evidence of radical-induced degradation of PAM under HPT hydraulic fracturing conditions without additional oxidative breaker.

Preliminary report on Bureau of Mines Yellow Creek core hole No. 1, Rio Blanco County, Colorado

USGS Publications Warehouse

Carroll, R.D.; Coffin, D.L.; Ege, J.R.; Welder, F.A.

1967-01-01

Analysis of geologic, hydrologic , and geophysical data obtained in and around Yellow Creek core hole No. 1, Rio Blanco County, Colorado, indicate a 1,615-foot section of oil shale was penetrated by the hole. Geophysical log data indicate the presence of 25 gallons per ton shale for a thickness of 500 feet my be marginal. The richest section of oil shale is indicated to be centered around a depth of 2,260 feet. Within the oil shale the interval 1,182 to 1,737 feet is indicated to be relatively structurally incompetent and probably permeable. Extension of available regional hydrologic data indicate the oil shale section is probably water bearing and may yield as much as 1,000 gallons per minute. Hydrologic testing in the hole is recommended.

CT Scanning and Geophysical Measurements of the Marcellus Formation from the Tippens 6HS Well

DOE Office of Scientific and Technical Information (OSTI.GOV)

Crandall, Dustin; Paronish, Thomas; Brown, Sarah

The computed tomography (CT) facilities and the Multi-Sensor Core Logger (MSCL) at the National Energy Technology Laboratory (NETL) Morgantown, West Virginia site were used to characterize core of the Marcellus Shale from a vertical well drilled in Eastern Ohio. The core is from the Tippens 6HS Well in Monroe County, Ohio and is comprised primarily of the Marcellus Shale from depths of 5550 to 5663 ft.

Reservoir characteristics of coal-shale sedimentary sequence in coal-bearing strata and their implications for the accumulation of unconventional gas

NASA Astrophysics Data System (ADS)

Wang, Yang; Zhu, Yanming; Liu, Yu; Chen, Shangbin

2018-04-01

Shale gas and coalbed methane (CBM) are both considered unconventional natural gas and are becoming increasingly important energy resources. In coal-bearing strata, coal and shale are vertically adjacent as coal and shale are continuously deposited. Research on the reservoir characteristics of coal-shale sedimentary sequences is important for CBM and coal-bearing shale gas exploration. In this study, a total of 71 samples were collected, including coal samples (total organic carbon (TOC) content >40%), carbonaceous shale samples (TOC content: 6%-10%), and shale samples (TOC content <6%). Combining techniques of field emission scanning electron microscopy (FE-SEM), x-ray diffraction, high-pressure mercury intrusion porosimetry, and methane adsorption, experiments were employed to characterize unconventional gas reservoirs in coal-bearing strata. The results indicate that in the coal-shale sedimentary sequence, the proportion of shale is the highest at 74% and that of carbonaceous shale and coal are 14% and 12%, respectively. The porosity of all measured samples demonstrates a good positive relationship with TOC content. Clay and quartz also have a great effect on the porosity of shale samples. According to the FE-SEM image technique, nanoscale pores in the organic matter of coal samples are much more developed compared with shale samples. For shales with low TOC, inorganic minerals provide more pores than organic matter. In addition, TOC content has a positive relationship with methane adsorption capacity, and the adsorption capacity of coal samples is more sensitive than the shale samples to temperature.

GEOCHEMICAL INVESTIGATIONS OF CO₂-BRINE-ROCK INTERACTIONS OF THE KNOX GROUP IN THE ILLINOIS BASIN

DOE Office of Scientific and Technical Information (OSTI.GOV)

Yoksoulian, Lois; Berger, Peter; Freiburg, Jared

Increased output of greenhouse gases, particularly carbon dioxide (CO₂), into the atmosphere from anthropogenic sources is of great concern. A potential technology to reduce CO₂ emissions is geologic carbon sequestration. This technology is currently being evaluated in the United States and throughout the world. The geology of the Illinois Basin exhibits outstanding potential as a carbon sequestration target, as demonstrated by the ongoing Illinois Basin – Decatur Project that is using the Mt. Simon Sandstone reservoir and Eau Claire Shale seal system to store and contain 1 million tonnes of CO₂. The Knox Group-Maquoketa Shale reservoir and seal system, locatedmore » stratigraphically above the Mt. Simon Sandstone-Eau Claire Shale reservoir and seal system, has little economic value as a resource for fossil fuels or as a potable water source, making it ideal as a potential carbon sequestration target. In order for a reservoir-seal system to be effective, it must be able to contain the injected CO₂ without the potential for the release of harmful contaminants liberated by the reaction between CO₂-formation fluids and reservoir and seal rocks. This study examines portions of the Knox Group (Potosi Dolomite, Gunter Sandstone, New Richmond Sandstone) and St. Peter Sandstone, and Maquoketa Shale from various locations around the Illinois Basin. A total of 14 rock and fluid samples were exposed to simulated sequestration conditions (9101–9860 kPa [1320–1430 psi] and 32°–42°C [90°– 108°F]) for varying amounts of time (6 hours to 4 months). Knox Group reservoir rocks exhibited dissolution of dolomite in the presence of CO₂ as indicated by petrographic examination, X-ray diffraction analysis, and fluid chemistry analysis. These reactions equilibrated rapidly, and geochemical modeling confirmed that these reactions reached equilibrium within the time frames of the experiments. Pre-reaction sample mineralogy and postreaction fluid geochemistry from this study suggests only limited potential for the release of United States Environmental Protection Agency regulated inorganic contaminants into potable water sources. Short-term core flood experiments further verify that the carbonate reactions occurring in Knox Group reservoir samples reach equilibrium rapidly. The core flood experiments also lend insight to pressure changes that may occur during CO₂ injection. The Maquoketa Shale experiments reveal that this rock is initially chemically reactive when in contact with CO₂ and brine. However, due to the conservative nature of silicate and clay reaction kinetics and the rapid equilibration of carbonate reactions that occur in the shale, these reactions would not present a significant risk to the competency of the shale as an effective seal rock.« less

Fractographic logging for determination of pre-core and core-induced fractures: Nicholas Combs No. 7239 well, Hazard, Kentucky

DOE Office of Scientific and Technical Information (OSTI.GOV)

Kulander, B.R.; Dean, S.L.; Barton, C.C.

1977-01-01

Methods results, and conclusions formulated during a prototype fractographic logging study of seventy-five feet of oriented Devonian shale core are summarized. The core analyzed is from the Nicholas Combs No. 7239 well located twelve miles due north of Hazard, Kentucky. The seventy-five foot core length was taken from a cored section lying between 2369.0 feet (subsea) and 2708.0 feet (subsea). Total core length is 339.0 feet. The core was extracted from the upper Devonian Ohio and Olentangy shale formations. Results indicate that there are few tectonic (pre-core) fractures within the studied core section. The region may nevertheless be cut atmore » core sample depth by well-defined vertical or inclined tectonic fractures that the vertically drilled test core didn't intersect. This is likely since surface Plateau systematic fractures in other Plateau areas are vertical to sub-vertical and seldom have a frequency of less than one major fracture per foot. The remarkable directional preference of set three fractures about strikes of N 40/sup 0/ E, N 10/sup 0/ W, N 45/sup 0/ W, suggests some incipient pre-core rock anisotropy or stored directional strain energy. If this situation exists, the anisotropy strike change or stored strain variance from N 40/sup 0/ E to N 45/sup 0/ W downcore remains an unanswered question. Tectonic features, indicating local and/or regional movement plans, are present on and within the tectonichorizontal fracture set one. Slickensides had a preferred orientation within several core levels, and fibrous-nonfibrous calcite serves as fracture fillings.« less

Evaluation of core data, physical properties, and oil yield USBM/AEC Colorado Core Hole no. 3 (Bronco BR-1)

USGS Publications Warehouse

Ege, John R.; Carroll, R.D.; Way, R.J.; Magner, J.E.

1969-01-01

USBM/AEC Colorado Core Hole No. 3 (Bronco BR-1) is located in the SW1/4SW1/4SW1/4 sec. 14, T. 1 N., R. 98 W., Rio Blanco County, Colorado. The collar is at a ground elevation of 6,356 feet. The hole was core drilled between depths of 964 and 3,325 feet with a total depth of 3,797 feet. The hole was drilled to investigate geologic, geophysical and hydrological conditions at a possible in situ oil-shale retorting experiment site. The drill hole passed through 1,157 feet of alluvium and the Evacuation Creek Member of the Green River Formation, 1,603 feet of the Parachute Creek Member and penetrated into the Garden Gulch Member of the Green River Formation. In-bole density log/oil yield ratio interpretation indicates that two oil-shale zones exist which yield more than 20 gallons of shale oil per ton of rock; an upper zone lying between 1,271 and 1,750 feet in depth and a lower zone lying between 1,900 and 2,964 feet. Halite (sodium chloride salt) is found between 2,140 and 2,185 feet and nahcolite (sodium bicarbonate salt) between 2,195 and 2,700 feet. Nahcolite was present at one time above 2,195 feet but has been subsequently dissolved out by ground water. The core can be divided into six structural units based upon degree of fracturing. A highly fractured interval is found between 1,646 and 1,899 feet, which coincides with the dissolution or leached nahcolite zone. Physical property tests made on core samples between 1,356 and 3,253 feet give average values of 11,988 psi for uniaxial compressive strength, 1.38 X 10[superscript]6[superscript] psi for static Young's modulus and 11,809 fps for compressional velocity.

A comprehensive method for the fracability evaluation of shale combined with brittleness and stress sensitivity

NASA Astrophysics Data System (ADS)

Wang, Xiaoqiong; Ge, Hongkui; Wang, Daobing; Wang, Jianbo; Chen, Hao

2017-12-01

An effective fracability evaluation on the fracture network is key to the whole process of shale gas exploitation. At present, neither a standard criteria nor a generally accepted evaluation method exist. Well log and laboratory results have shown that the commonly used brittleness index calculated from the mineralogy composition is not entirely consistent with that obtained from the elastic modulus of the rock, and is sometimes even contradictory. The brittle mineral reflects the brittleness of the rock matrix, and the stress sensitivity of the wave velocity reflects the development degree of the natural fracture system. They are both key factors in controlling the propagating fracture morphology. Thus, in this study, a novel fracability evaluation method of shale was developed combining brittleness and stress sensitivity. Based on this method, the fracability of three shale gas plays were evaluated. The cored cylindrical samples were loaded under uniaxial stress up to 30 MPa and the compressional wave velocities were obtained along the axis stress direction at each MPa stress. From the stress velocity evolution, the stress sensitivity coefficients could be obtained. Our results showed that the fracability of Niutitang shale is better than that of Lujiaping shale, and the fracability of Lujiaping shale is better than Longmaxi shale. This result is in good agreement with acoustic emission activity measurements. The new fracability evaluation method enables a comprehensive reflection of the characteristics of rock matrix brittleness and the natural fracture system. This work is valuable for the evaluation of hydraulic fracturing effects in unconventional oil and gas reservoirs in the future.

Oil-source correlations between the Mississippian Heath Shales and the reservoired oils in the Pennsylvanian Tyler Sands, Montana

DOE Office of Scientific and Technical Information (OSTI.GOV)

Cole, G.A.; Drozd, R.J.; Daniel, J.A.

The Mississippi Heath Formation exposed in Fergus County, central Montana, is comprised predominantly of nearshore, marine, black, calcareous shales and carbonates with minor anhydrite and coal beds. The black shales and limestones have been considered as sources for shale oil via Fischer Assay and pyrolysis analysis. These shales are potential source units for the oils reservoired in the overlying Pennsylvanian Tyler Formation sands located 50 mi (80 km) to the east of the Fergus County Heath sediment studied. Heath Formation rocks from core holes were selectively sampled in 2-ft increments and analyzed for their source rock characteristics. Analyses include percentmore » total organic carbon (%TOC), Rock-Eval pyrolysis, pyrolysis-gas chromatography, and characterization of the total soluble extracts using carbon isotopes and gas chromatography-mass Spectrometry. Results indicated that the Heath was an excellent potential source unit that contained oil-prone, organic-rich (maximum of 17.6% TOC), calcareous, black shale intervals. The Heath and Tyler formations also contained intervals dominated by gas-prone, organic-rich shales of terrestrial origin. Three oils from the Tyler Formation sands in Musselshell and Rosebud counties were characterized by similar methods as the extracts. The oils were normally mature, moderate API gravity, moderate sulfur, low asphaltene crudes. Oil to source correlations between the Heath shale extracts and the oils indicated the Heath was an excellent candidate source rock for the Tyler reservoired oils. Conclusions were based on excellent matches between the carbon isotopes of the oils and the kerogen-kerogen pyrolyzates, and from the biomarkers.« less

Characteristics and geological significance of Re-Os isotopic system of evaporites in Mboukoumassi deposit, the Republic of Congo

NASA Astrophysics Data System (ADS)

Zhao, Xianfu; Wang, Zongqi; Liu, Chenglin; Li, Chao; Jiao, Pengcheng; Zhao, Yanjun; Zhang, Fan

2018-02-01

Evaporite dating has been an open problem. The study investigates the Re-Os isotopic system in the organic-rich sedimentary rocks to constrain the infilling of sedimentary basin and related geological events. In the Mboukoumassi potash deposit in the Republic of Congo (Congo-Brazzaville) in West Africa, several layers of organic-rich dark shale were found in the evaporite series. Through drilling core, the dark shale in the evaporite is found to satisfy the requirements of Re-Os isotope test. The result shows that the Re-Os isochron age of the dark shale in the study area ranges from 78.7 ± 1.1 to 96 ± 7 Ma, which is the first precise age of the Mboukoumassi potash deposit in the Republic of Congo (Congo-Brazzaville), West Africa. Therefore, the age of deposition of this set of evaporite may be Cenomanian-Turonian, which is younger than the age previously thought (around 113-125Ma, Aptian). The Re-Os isotopic dating technique used for the pioneering study on the precise dating of the Mboukoumassi potash deposit provides a new approach to the study of the sedimentary age of ancient evaporite deposits. The initial 187Os/188Os value decreasing from 2.02 ± 0.21 to 0.982 ± 0.03 for the core sample reflects the source rock chang along the core, and this is consistent with the geological evolution of the basin.

Compaction bands in shale revealed through digital volume correlation of time-resolved X-ray tomography scans

NASA Astrophysics Data System (ADS)

McBeck, J.; Kobchenko, M.; Hall, S.; Tudisco, E.; Cordonnier, B.; Renard, F.

2017-12-01

Previous studies have identified compaction bands primarily within sandstones, and in fewer instances, within other porous rocks and sediments. Using Digital Volume Correlation (DVC) of X-ray microtomography scans, we find evidence of localized zones of high axial contraction that form tabular structures sub-perpendicular to maximum compression, σ1, in Green River shale. To capture in situ strain localization throughout loading, two shale cores were deformed in the HADES triaxial deformation apparatus installed on the X-ray microtomography beamline ID19 at the European Synchrotron Radiation Facility. In these experiments, we increase σ1 in increments of two MPa, with constant confining pressure (20 MPa), until the sample fails in macroscopic shear. After each stress step, a 3D image of the sample inside the rig is acquired at a voxel resolution of 6.5 μm. The evolution of lower density regions within 3D reconstructions of linear attenuation coefficients reveal the development of fractures that fail with some opening. If a fracture produces negligible dilation, it may remain undetected in image segmentation of the reconstructions. We use the DVC software TomoWarp2 to identify undetected fractures and capture the 3D incremental displacement field between each successive pair of microtomography scans acquired in each experiment. The corresponding strain fields reveal localized bands of high axial contraction that host minimal shear strain, and thus match the kinematic definition of compaction bands. The bands develop sub-perpendicular to σ1 in the two samples in which pre-existing bedding laminations were oriented parallel and perpendicular to σ1. As the shales deform plastically toward macroscopic shear failure, the number of bands and axial contraction within the bands increase, while the spacing between the bands decreases. Compaction band development accelerates the rate of overall axial contraction, increasing the mean axial contraction throughout the sample, and strengthens the shale sufficiently to localize shear faults. These results are critical to robust assessment of deformation patterns in shale rocks in contexts such as nuclear waste storage, hydrocarbon recovery and groundwater access.

Speciation and weathering of selenium in upper cretaceous chalk and shale from South Dakota and Wyoming, USA

NASA Astrophysics Data System (ADS)

Kulp, Thomas R.; Pratt, Lisa M.

2004-09-01

In geologic materials, petroleum, and the environment, selenium occurs in various oxidation states (VI, IV, 0, -II), mineralized forms, and organo-Se complexes. Each of these forms is characterized by specific chemical and biochemical properties that control the element's solubility, toxicity, and environmental behavior. The organic rich chalks and shales of the Upper Cretaceous Niobrara Formation and the Pierre Shale in South Dakota and Wyoming are bentoniferous stratigraphic intervals characterized by anomalously high concentrations of naturally occurring Se. Numerous environmental problems have been associated with Se derived from these geological units, including the development of seleniferous soils and vegetation that are toxic to livestock and the contamination of drinking water supplies by Se mobilized in groundwater. This study describes a sequential extraction protocol followed by speciation treatments and quantitative analysis by Hydride Generation-Atomic Absorption Spectroscopy. This protocol was utilized to investigate the geochemical forms and the oxidation states in which Se occurs in these geologic units. Organic Se and di-selenide minerals are the predominant forms of Se present in the chalks, shales, and bentonites, but distinctive variations in these forms were observed between different sample types. Chalks contain significantly greater proportions of Se in the form of di-selenide minerals (including Se associated with pyrite) than the shales where base-soluble, humic, organo-Se complexes are more prevalent. A comparison between unweathered samples collected from lithologic drill cores and weathered samples collected from outcrop suggest that the humic, organic-Se compounds in shale are formed during oxidative weathering and that Se oxidized by weathering is more likely to be retained by shale than by chalk. Selenium enrichment in bentonites is inferred to result from secondary processes including the adsorption of Se mobilized by groundwater from surrounding organic rich sediments to clay mineral and iron hydroxide surfaces, as well as microbial reduction of Se within the bentonitic intervals. Distinct differences are inferred for the biogeochemical pathways that affected sedimentary Se sequestration during periods of chalk accumulation compared to shale deposition in the Cretaceous seaway. Mineralogy of sediment and the nature of the organic matter associated with each of these rock types have important implications for the environmental chemistry and release of Se to the environment during weathering.

Shale gas characterization based on geochemical and geophysical analysis: Case study of Brown shale, Pematang formation, Central Sumatra Basin

NASA Astrophysics Data System (ADS)

Haris, A.; Nastria, N.; Soebandrio, D.; Riyanto, A.

2017-07-01

Geochemical and geophysical analyses of shale gas have been carried out in Brown Shale, Middle Pematang Formation, Central Sumatra Basin. The paper is aimed at delineating the sweet spot distribution of potential shale gas reservoir, which is based on Total Organic Carbon (TOC), Maturity level data, and combined with TOC modeling that refers to Passey and Regression Multi Linear method. We used 4 well data, side wall core and 3D pre-stack seismic data. Our analysis of geochemical properties is based on well log and core data and its distribution are constrained by a framework of 3D seismic data, which is transformed into acoustic impedance. Further, the sweet spot of organic-rich shale is delineated by mapping TOC, which is extracted from inverted acoustic impedance. Our experiment analysis shows that organic materials contained in the formation of Middle Pematang Brown Shale members have TOC range from 0.15 to 2.71 wt.%, which is classified in the quality of poor to very good. In addition, the maturity level of organic material is ranging from 373°C to 432°C, which is indicated by vitrinite reflectance (Ro) of 0.58. In term of kerogen type, this Brown shale formation is categorized as kerogen type of II I III, which has the potential to generate a mixture of gasIoil on the environment.

Computed Tomography Scanning and Geophysical Measurements of Core from the Coldstream 1MH Well

DOE Office of Scientific and Technical Information (OSTI.GOV)

Crandall, Dustin M.; Brown, Sarah; Moore, Johnathan E.

The computed tomography (CT) facilities and the Multi-Sensor Core Logger (MSCL) at the National Energy Technology Laboratory (NETL) Morgantown, West Virginia site were used to characterize core of the Marcellus Shale from a vertical well, the Coldstream 1MH Well in Clearfield County, PA. The core is comprised primarily of the Marcellus Shale from a depth of 7,002 to 7,176 ft. The primary impetus of this work is a collaboration between West Virginia University (WVU) and NETL to characterize core from multiple wells to better understand the structure and variation of the Marcellus and Utica shale formations. As part of thismore » effort, bulk scans of core were obtained from the Coldstream 1MH well, provided by the Energy Corporation of America (now Greylock Energy). This report, and the associated scans, provide detailed datasets not typically available from unconventional shales for analysis. The resultant datasets are presented in this report, and can be accessed from NETL's Energy Data eXchange (EDX) online system using the following link: https://edx.netl.doe.gov/dataset/coldstream-1mh-well. All equipment and techniques used were non-destructive, enabling future examinations to be performed on these cores. None of the equipment used was suitable for direct visualization of the shale pore space, although fractures and discontinuities were detectable with the methods tested. Low resolution CT imagery with the NETL medical CT scanner was performed on the entire core. Qualitative analysis of the medical CT images, coupled with x-ray fluorescence (XRF), P-wave, and magnetic susceptibility measurements from the MSCL were useful in identifying zones of interest for more detailed analysis as well as fractured zones. En echelon fractures were observed at 7,100 ft and were CT scanned using NETL’s industrial CT scanner at higher resolution. The ability to quickly identify key areas for more detailed study with higher resolution will save time and resources in future studies. The combination of methods used provided a multi-scale analysis of this core and provides both a macro and micro description of the core that is relevant for many subsurface energy-related examinations that have traditionally been performed at NETL.« less

Utica Shale Energy and Environment Laboratory (USEEL)

NASA Astrophysics Data System (ADS)

Cole, D. R.

2017-12-01

Despite the rapid growth of the UOG industry in the Appalachian Basin of Pennsylvania and neighboring states, there are still fundamental concerns regarding the environmentally sound and cost efficient extraction of this unique asset. To address these concerns, Ohio State University has established the Department of Energy-funded Utica Shale Energy and Environment Laboratory, a dedicated research program where scientists from the university will work with the U.S. Department of Energy (DOE) National Energy Technology Laboratory (NETL), academia, industry, and regulatory partners, to measure and monitor reservoir response to UOG development and any associated environmental concerns. The USEEL site will be located in Greene County, Pennsylvania, in the heart of the deep Utica-Pt. Pleasant Shale play of the Appalachian Basin. The USEEL project team will characterize and quantify the gas-producing attributes of one of the deepest portions of the Utica-Pt. Pleasant formations in the Appalachian Basin via a multi-disciplinary collaboration that leverages state-of-the-art capabilities in geochemistry, core assessment, well design and logging, 3-D and micro-seismic, DTS and DAS fiber optics, and reservoir modelling. Fracture and rock strength analyses will be complemented by a comprehensive suite of geophysical and geochemical logs, water and chip samples, and cores (pressure sidewall and whole core) to evaluate fluids, mineral alteration, microbes, pore structure, and hydrocarbon formation and alteration in the shale pore space. Located on an existing Marcellus drill pads in southwestern Pennsylvania, USEEL will provide an unprecedented opportunity to evaluate the economic and environmental effects of Marcellus pad expansion on the integrity of near-by existing production wells, ground disruption and slope stability, and ultimate efforts to conduct site reclamation. Combined with the overall goal of an improved understanding of the Utica-Pt. Pleasant system, USEEL findings will decrease the number of drill pads and improve the efficacy of UOG development across the Appalachian Basin.

Shale gas development: a smart regulation framework.

PubMed

Konschnik, Katherine E; Boling, Mark K

2014-01-01

Advances in directional drilling and hydraulic fracturing have sparked a natural gas boom from shale formations in the United States. Regulators face a rapidly changing industry comprised of hundreds of players, operating tens of thousands of wells across 30 states. They are often challenged to respond by budget cuts, a brain drain to industry, regulations designed for conventional gas developments, insufficient information, and deeply polarized debates about hydraulic fracturing and its regulation. As a result, shale gas governance remains a halting patchwork of rules, undermining opportunities to effectively characterize and mitigate development risk. The situation is dynamic, with research and incremental regulatory advances underway. Into this mix, we offer the CO/RE framework--characterization of risk, optimization of mitigation strategies, regulation, and enforcement--to design tailored governance strategies. We then apply CO/RE to three types of shale gas risks, to illustrate its potential utility to regulators.

Effects of weathering on biological marker and aromatic hydrocarbon composition of organic matter in Phosphoria shale outcrop

USGS Publications Warehouse

Clayton, J.L.; King, J.D.

1987-01-01

GC-MS analyses were performed on core samples collected from a shale outcrop of the Permian Phosphoria Formation in Utah, U.S.A., to study effects of weathering on selected biological marker and aromatic (phenanthrene) hydrocarbon compounds. Among the biological markers, the most important weathering effects are a decrease in the 20S 20R diastereomer ratio of the C29 steranes and loss of low molecular weight triaromatic steroids. A decrease in the C19 through C22 tricylcic terpanes occurs relative to the total C19-C26 tricyclic fraction. Pronounced loss of methyl-substituted phenanthrenes occurs relative to phenanthrene. No major effect on the overall distribution of pentacyclic terpanes is evident. ?? 1987.

A Thermoplasticity Model for Oil Shale

DOE PAGES

White, Joshua A.; Burnham, Alan K.; Camp, David W.

2016-03-31

Several regions of the world have abundant oil shale resources, but accessing this energy supply poses a number of challenges. One particular difficulty is the thermomechanical behavior of the material. When heated to sufficient temperatures, thermal conversion of kerogen to oil, gas, and other products takes place. This alteration of microstructure leads to a complex geomechanical response. In this work, we develop a thermoplasticity model for oil shale. The model is based on critical state plasticity, a framework often used for modeling clays and soft rocks. The model described here allows for both hardening due to mechanical deformation and softeningmore » due to thermal processes. In particular, the preconsolidation pressure—defining the onset of plastic volumetric compaction—is controlled by a state variable representing the kerogen content of the material. As kerogen is converted to other phases, the material weakens and plastic compaction begins. We calibrate and compare the proposed model to a suite of high-temperature uniaxial and triaxial experiments on core samples from a pilot in situ processing operation in the Green River Formation. In conclusion, we also describe avenues for future work to improve understanding and prediction of the geomechanical behavior of oil shale operations.« less

Multiscale Porosity and Mechanical Properties of Mancos Shale: Evaluation of REV and Scale Separation

NASA Astrophysics Data System (ADS)

Heath, J. E.; Dewers, T. A.; Yoon, H.; Mozley, P.

2016-12-01

Heterogeneity from the nanometer to core and larger length scales is a major challenge to understanding coupled processes in shale. To develop methods to address this challenge, we present application of high throughput multi-beam scanning electron microscopy (mSEM) and nano-to-micro-scale mechanics to the Mancos Shale. We use a 61-beam mSEM to collect 6 nm resolution SEM images at the scale of several square millimeters. These images are analyzed for pore size and shape characteristics including spatial correlation and structure. Nano-indentation, micropillar compression, and axisymmetric testing at multiple length scales allows for examining the influence of sampling size on mechanical response. The combined data set is used to: investigate representative elementary volumes (and areas for the 2D images) for the Mancos Shale; determine if scale separation occurs; and determine if transport and mechanical properties at a given length scale can be statistically defined. Sandia National Laboratories is a multi-program laboratory managed and operated by Sandia Corporation, a wholly owned subsidiary of Lockheed Martin Corporation, for the U.S. Department of Energy's National Nuclear Security Administration under contract DE-AC04-94AL85000.

The 1997 core drilling through Ordovician and Silurian strata at Röstånga, S. Sweden: preliminary stratigraphic assessment and regional comparison

USGS Publications Warehouse

Bergstrom, Stig M.; Huff, W.D.; Koren', T.; Larsson, K.; Ahlberg, P.; Kolata, Dennis R.

1999-01-01

A core drilling at Ro??sta??nga, the first such drilling ever undertaken in this classical Lower Paleozoic outcrop area in W-central Scania, penetrated an approximately 96 m thick succession of Lower Silurian-upper Middle Ordovician marine rocks. The drilling was stopped at a depth of 132.59 m in an interval of crushed rocks, probably a prominent fault zone, that proved impossible to drill through. The core contains a stratigraphical sequence from the basal Upper Llandoverian (Telychian Stage) to the upper Middle Ordovician (Harjuan Stage). The following units are recognized in descending stratigraphic order (approximate thickness in parenthesis): Kallholn Formation (35 m), Lindega??rd Mudstone (27 m), Fja??cka Shale (13 m), Mossen Formation (0.75 m), Skagen Formation (2.5 m), and Sularp Shale (19 m+). Except for the Skagen Formation, the drilled sequence consists of shales and mudstones with occasional thin limestone interbeds and is similar to coeval successions elsewhere in Scania. There are 11 K-bentonite beds in the Kallholn Formation, 2(3?) in the Lindega??rd Mudstone, 1 in the Mossen Formation, 7 in the Skagen Formation, and 33 in the Sularp Shale. The core serves as an excellent Lower Silurian-upper Middle Ordovician reference standard not only for the Ro??sta??nga area but also for southernmost Sweden in general because the cored sequence is the stratigraphically most complete one known anywhere in this region.

Distribution and variation of the inorganic fraction of Devonian to Bashkirian black shales in the north-western part of the Dniepr-Donets Basin, Ukraine

NASA Astrophysics Data System (ADS)

Wegerer, Eva; Sachsenhofer, Reinhard; Misch, David; Aust, Nicolai

2016-04-01

Mineralogical data of 112 core samples from 12 wells are used to investigate lateral and vertical variations in the lithofacies of Devonian to Bashkirian black shales in the north-western part of the Dniepr-Donets-Basin. Sulphur and carbonate contents as well as organic geochemical parameters, including TOC and Hydrogen Index have been determined on the same sample set within the frame of an earlier study (Sachsenhofer et al. 2010). This allows the correlation of inorganic and organic composition of the black shales. Aims of the study are to distinguish between detrital and authigenic minerals, to relate the lithofacies of the black shales with the tectono-stratigraphic sequences of the Dniepr-Donets Basin, to contribute to the reconstruction of the depositional environment and to relate diagenetic processes with the thermal history of the basin. Mineral compositions were determined primarily using XRD-measurements applying several measurement procedures, e.g. chemical and temperature treatment, and specific standards. Major differences exist in the mineralogical composition of the black shales. For example, clay mineral contents range from less than 20 to more than 80 Vol%. Kaolinite contents are significantly higher in rocks with a Tournaisian or Early Visean age than in any other stratigraphic unit. This is also true for two Lower Visean coal samples from the shallow north-westernmost part of the basin. Chlorite contents reach maxima in uppermost Visean and overlying rocks. Quartz contents are often high in Upper Visean rocks and reach maxima in Bashkirian units. Feldspar-rich rocks are observed in Devonian sediments from the north-western part of the study area and may reflect the proximity to a sediment source. Carbonate contents are typically low, but reach very high values in some Tournaisian, Lower Visean and Serpukhovian samples. Pyrite contents reach maxima along the basin axis in Tournaisian and Visean rocks reflecting anoxic conditions. Mixed layer minerals are dominated by illite. Their presence in samples from depth exceeding 5 km reflects the low thermal overprint of Paleozoic rocks in the north-western Dniepr-Donets-Basin.

Applications and benefits of technology in naturally fractured, low permeability reservoirs with special emphasis on results from GRI`s devonian shale and berea sand research in the appalachian basin

DOE Office of Scientific and Technical Information (OSTI.GOV)

Jochen, J.E.; Hopkins, C.W.

1993-12-31

;Contents: Naturally fractured reservoir description; Geologic considerations; Shale-specific log model; Stress profiles; Berea reasearch; Benefits analysis; Summary of technologies; Novel well test methods; Natural fracture identification; Reverse drilling; Production data analysis; Fracture treatment quality control; Novel core analysis methods; and Shale well cleanouts.

Review of rare earth element concentrations in oil shales of the Eocene Green River Formation

USGS Publications Warehouse

Birdwell, Justin E.

2012-01-01

Concentrations of the lanthanide series or rare earth elements and yttrium were determined for lacustrine oil shale samples from the Eocene Green River Formation in the Piceance Basin of Colorado and the Uinta Basin of Utah. Unprocessed oil shale, post-pyrolysis (spent) shale, and leached shale samples were examined to determine if oil-shale processing to generate oil or the remediation of retorted shale affects rare earth element concentrations. Results for unprocessed Green River oil shale samples were compared to data published in the literature on reference materials, such as chondritic meteorites, the North American shale composite, marine oil shale samples from two sites in northern Tibet, and mined rare earth element ores from the United States and China. The Green River oil shales had lower rare earth element concentrations (66.3 to 141.3 micrograms per gram, μg g-1) than are typical of material in the upper crust (approximately 170 μg g-1) and were also lower in rare earth elements relative to the North American shale composite (approximately 165 μg g-1). Adjusting for dilution of rare earth elements by organic matter does not account for the total difference between the oil shales and other crustal rocks. Europium anomalies for Green River oil shales from the Piceance Basin were slightly lower than those reported for the North American shale composite and upper crust. When compared to ores currently mined for rare earth elements, the concentrations in Green River oil shales are several orders of magnitude lower. Retorting Green River oil shales led to a slight enrichment of rare earth elements due to removal of organic matter. When concentrations in spent and leached samples were normalized to an original rock basis, concentrations were comparable to those of the raw shale, indicating that rare earth elements are conserved in processed oil shales.

Geological implications and controls on the determination of water saturation in shale gas reservoirs

NASA Astrophysics Data System (ADS)

Hartigan, David; Lovell, Mike; Davies, Sarah

2014-05-01

A significant challenge to the petrophysical evaluation of shale gas systems can be attributed to the conductivity behaviour of clay minerals and entrained clay bound waters. This is compounded by centimetre to sub-millimetre vertical and lateral heterogeneity in formation composition and structure. Where despite significant variation in formation geological and therefore petrophysical properties, we routinely rely on conventional resistivity methods for the determination of water saturation (Sw), and hence the free gas saturation (Sg) in gas bearing mudstones. The application of resistivity based methods is the subject of continuing debate, and there is often significant uncertainty in both how they are applied and the saturation estimates they produce. This is partly a consequence of the view that "the quantification of the behaviour of shale conductivity....has only limited geological significance" (Rider 1986). As a result, there is a separation between our geological understanding of shale gas systems and the petrophysical rational and methods employed to evaluate them. In response to this uncertainty, many petrophysicists are moving away from the use of more complex 'shaly-sand' based evaluation techniques and returning to traditional Archie methods for answers. The Archie equation requires various parameter inputs such as porosity and saturation exponents (m and n), as well as values for connate fluid resistivity (Rw). Many of these parameters are difficult to determine in shale gas systems, where obtaining a water sample, or carrying out laboratory experiments on recovered core is often technically impractical. Here we assess the geological implications and controls on variations in pseudo Archie parameters across two geological formations, using well data spanning multiple basinal settings for a prominent shale gas play in the northern Gulf of Mexico basin. The results, of numerical analysis and systematic modification of parameter values to minimise the error between core derived Sw (Dean Stark analysis) and computed Sw, links sample structure with composition, highlighting some unanticipated impacts of clay minerals on the effective bulk fluid resistivity (Rwe) and thus formation resistivity (Rt). In addition, it highlights simple corrective empirical adaptations that can significantly reduce the error in Sw estimation for some wells. Observed results hint at the possibility of developing a predictive capability in selecting Archie parameter values based on geological facies association and log composition indicators (i.e. V Clay), establishing a link between formation depositional systems and their petrophysical properties in gas bearing mudstones. Rider, M.H., 1986. The Geological Interpretation of Well Logs, Blackie.

Mesoarchean Banded Iron Formation sequences in Dixon Island-Cleaverville Formation, Pilbara Australia: Oxygenic signal from DXCL project

NASA Astrophysics Data System (ADS)

Kiyokawa, S.; Ito, T.; Ikehara, M.; Yamaguchi, K. E.; Naraoka, H.; Onoue, T.; Horie, K.; Sakamoto, R.; Aihara, Y.; Miki, T.

2013-12-01

The 3.2-3.1 Ga Dixon island-Cleaverville formations are well-preserved Banded Iron Formation (BIF) within hydrothermal oceanic sequence at oceanic island arc setting (Kiyokawa et al., 2002, 2006, 2012). The stratigraphy of the Dixon Island (3195+15Ma) -Cleaverville (3108+13Ma) formations shows the well preserved environmental condition at the Mesoarchean ocean floor. The stratigraphy of these formations are formed about volcano-sedimentary sequences with hydrothermal chert, black shale and banded iron formation to the top. Based on the scientific drilling of DXCL project at 2007 and 2011, detail lithology between BIF sequence was clearly understood. Four drilling holes had been done at coastal sites; the Dixon Island Formation is DX site (100m) and the Cleaverville Formation is CL2 (40m), CL1 (60m) and CL3 (200m) sites and from stratigraphic bottom to top. Coarsening and thickening upward black shale-BIF sequences are well preserved of the stratigraphy form the core samples. The Dixon Island Formation consists komatiite-rhyolite sequences with many hydrothermal veins and very fine laminated cherty rocks above them. The Cleaverville Formation contains black shale, fragments-bearing pyroclastic beds, white chert, greenish shale and BIF. The CL3 core, which drilled through BIF, shows siderite-chert beds above black shale identified before magnetite lamination bed. U-Pb SHRIMP data of the tuff in lower Dixon Island Formation is 3195+15 Ma and the pyroclastic sequence below the Cleaverville BIF is 3108+13 Ma. Sedimentation rate of these sequence is 2-8 cm/ 1000year. The hole section of the organic carbon rich black shales below BIF are similar amount of organic content and 13C isotope (around -30per mill). There are very weak sulfur MIF signal (less 0.2%) in these black shale sequence. Our result show that thick organic rich sediments may be triggered to form iron rich siderite and magnetite iron beds. The stratigraphy in this sequence quite resemble to other Iron formation (eg. Hamersley BIF). So we investigate that the Cleaverville iron formation, which is one of the best well known Mesoarchean iron formation, was already started cyanobacteria oxygen production system to used pre-syn iron sedimentation at anoxic oceanic condition.

Preliminary view of geotechnical properties of soft rocks of Semanggol formation at Pokok Sena, Kedah

NASA Astrophysics Data System (ADS)

Ahmad, N. R.; Jamin, N. H.

2018-04-01

The research was inspired by series of geological studies on Semanggol formation found exposed at North Perak, South Kedah and North Kedah. The chert unit comprised interbedded chert-shale rocks are the main lithologies sampled in a small-scale outcrop of Pokok Sena area. Black shale materials were also observed associated with these sedimentary rocks. The well-known characteristics of shale that may swell when absorb water and leave shrinkage when dried make the formation weaker when load is applied on it. The presence of organic materials may worsen the condition apart from the other factors such as the history of geological processes and depositional environment. Thus, this research is important to find the preliminary relations of the geotechnical properties of soft rocks and the geological reasoning behind it. Series of basic soil tests and 1-D compression tests were carried out to obtain the soil parameters. The results obtained gave some preliminary insight to mechanical behaviour of these two samples. The black shale and weathered interbedded chert-shale were classified as sandy-clayey-SILT and clayey-silty-SAND respectively. The range of specific gravity of black shale and interbedded chert/shale 2.3 – 2.6 and fall in the common range of shale and chert specific gravity value. In terms of degree of plasticity, the interbedded chert/shale samples exhibit higher plastic degree compared to the black shale samples. Results from oedometer tests showed that black shale samples had higher overburden pressure (Pc) throughout its lifetime compare to weathered interbedded chert-shale, however the compression index (Cc) of black shale were 0.15 – 0.185 which was higher than that found in interbedded chert-shale. The geotechnical properties of these two samples were explained in correlation with their provenance and their history of geological processes involved which predominantly dictated the mechanical behaviour of these two samples.

Chemical Degradation of Polyacrylamide during Hydraulic Fracturing.

PubMed

Xiong, Boya; Miller, Zachary; Roman-White, Selina; Tasker, Travis; Farina, Benjamin; Piechowicz, Bethany; Burgos, William D; Joshi, Prachi; Zhu, Liang; Gorski, Christopher A; Zydney, Andrew L; Kumar, Manish

2018-01-02

Polyacrylamide (PAM) based friction reducers are a primary ingredient of slickwater hydraulic fracturing fluids. Little is known regarding the fate of these polymers under downhole conditions, which could have important environmental impacts including decisions on strategies for reuse or treatment of flowback water. The objective of this study was to evaluate the chemical degradation of high molecular weight PAM, including the effects of shale, oxygen, temperature, pressure, and salinity. Data were obtained with a slickwater fracturing fluid exposed to both a shale sample collected from a Marcellus outcrop and to Marcellus core samples at high pressures/temperatures (HPT) simulating downhole conditions. Based on size exclusion chromatography analyses, the peak molecular weight of the PAM was reduced by 2 orders of magnitude, from roughly 10 MDa to 200 kDa under typical HPT fracturing conditions. The rate of degradation was independent of pressure and salinity but increased significantly at high temperatures and in the presence of oxygen dissolved in fracturing fluids. Results were consistent with a free radical chain scission mechanism, supported by measurements of sub-μM hydroxyl radical concentrations. The shale sample adsorbed some PAM (∼30%), but importantly it catalyzed the chemical degradation of PAM, likely due to dissolution of Fe 2+ at low pH. These results provide the first evidence of radical-induced degradation of PAM under HPT hydraulic fracturing conditions without additional oxidative breaker.

An improved evaluation method for measuring TOC of the Longmaxi Formation shale in the Sichuan Basin, south China

NASA Astrophysics Data System (ADS)

Zhang, Y.; Hu, C.; Wang, M.

2017-12-01

The evaluation of total organic carbon (TOC) in shale using logging data is one of the most crucial steps in shale gas exploration. However, it didn't achieve the ideal effect for the application of `ΔlogR' method in the Longmaxi Formation shale of Sichuan Basin.The reason may be the organic matter carbonization in Longmaxi Formation. An improved evaluation method, using the classification by lithology and sedimentary structure: 1) silty mudstone (wellsite logging data show silty); 2) calcareous mudstone (calcareous content > 25%); 3) laminated mudstone (laminations are recognized by core and imaging logging technology); 4) massive mudstone (massive textures are recognized by core and imaging logging technology, was proposed. This study compares two logging evaluation methods for measuring TOC in shale: the △logR method and the new proposed method. The results showed that the correlation coefficient between the calculated TOC and the tested TOC, based on the △logR method, was only 0.17. The correlation coefficient obtained according to the new method reached 0.80. The calculation results illustrated that, because of the good correlation between lithologies and sedimentary structure zones and TOC of different types of shale, the shale reservoirs could be graded according to four shale types. The new proposed method is more efficient, faster, and has higher vertical resolution than the △logR method. In addition, a new software had been completed. It was found to be especially effective under conditions of insufficient data during the early stages of shale gas exploration in the Silurian Longmaxi Formation, Muai Syncline Belt, south of the Sichuan Basin.

Environmental consequences of shale gas exploitation and the crucial role of rock microfracturing

NASA Astrophysics Data System (ADS)

Renard, Francois

2015-04-01

The growing exploitation of unconventional gas and oil resources has dramatically changed the international market of hydrocarbons in the past ten years. However, several environmental concerns have also been identified such as the increased microseismicity, the leakage of gas into freshwater aquifers, and the enhanced water-rock interactions inducing the release of heavy metals and other toxic elements in the produced water. In all these processes, fluids are transported into a network of fracture, ranging from nanoscale microcracks at the interface between minerals and the kerogen of the source rock, to well-developed fractures at the meter scale. Characterizing the fracture network and the mechanisms of its formation remains a crucial goal. A major difficulty when analyzing fractures from core samples drilled at depth is that some of them are produced by the coring process, while some other are produced naturally at depth by the coupling between geochemical and mechanical forces. Here, I present new results of high resolution synchrotron 3D X-ray microtomography imaging of shale samples, at different resolutions, to characterize their microfractures and their mechanisms of formation. The heterogeneities of rock microstructure are also imaged, as they create local stress concentrations where cracks may nucleate or along which they propagate. The main results are that microcracks form preferentially along kerogen-mineral interfaces and propagate along initial heterogeneities according to the local stress direction, connecting to increase the total volume of fractured rock. Their lifetime is also an important parameter because they may seal by fluid circulation, fluid-rock interactions, and precipitation of a cement. Understanding the multi-scale processes of fracture network development in shales and the coupling with fluid circulation represents a key challenge for future research directions.

Paleoceanographic Inferences from Carbon and Nitrogen Isotopic Compositions of Cenomanian Black Shales from DSDP/ODP Sites 367, 530, 603, 641, 1257-1261, and 1276 in the Atlantic Ocean

NASA Astrophysics Data System (ADS)

Yum, J.; Meyers, P. A.; Bernasconi, S. M.; Arnaboldi, M.

2005-12-01

The mid-Cretaceous (Cenomanian- Turonian) was characterized as a peak global greenhouse period with highest sea level, highest CO2 concentration in atmosphere and low thermal gradients from the poles to the equator. The depositional environment of the organic-carbon-rich black shales that typify this period remains an open question. A total of 180 Cenomanian- Turonian core samples were selected from multiple ODP and DSDP sites in the Atlantic Ocean: 530 (Cape Basin), 603 (Hatteras Rise), 641 (Galicia Bank), 1257-1261 (Demerara Rise), 1276 (Newfoundland Basin). Total organic carbon and nitrogen concentrations and isotopic compositions were measured to investigate variations in the proto-Atlantic Ocean paleoceanographic conditions that contributed to the origin of the black shales for this period. These new data were combined with existing data from Sites 367 (Senegal Rise), 530, and 603. Both the black shales and the organic-carbon-poor background sediments (less than 1 percent) have carbon isotope values between -29 to -22 permil. The C/N ratios of the background sediments are low (less than 20) compared to those of the black shales (20-40). Nitrogen isotope values range from 0 to 4 permil in the background samples. All black shales have similarly low nitrogen isotope values that range between -4 to 0 permil. These exceptionally low values are inferred to reflect the productivity of blue green algae and cyanobacteria under strongly surface stratified oceanic conditions. Although carbon isotope and C/N values of black shales show almost similar patterns at each location, there are site-specific shifts in these data that could be related to the amount of continental run off and/or the effect of latitude. Our multi-site comparison suggests that specially stratified depositional environments that could produce and accumulate the abnormally high carbon concentrations in sediments occurred throughout the proto-Atlantic ocean during the mid-Cretaceous. However, regional factors affected the amount and origin of organic matter delivered to each location.

Computerized X-ray Microtomography Observations and Fluid Flow Measurements of the Effect of Effective Stress on Fractured Reservoir Seal Shale

NASA Astrophysics Data System (ADS)

Welch, N.; Crawshaw, J.; Boek, E.

2014-12-01

The successful storage of carbon dioxide in geologic formations requires an in-depth understanding of all reservoir characteristics and morphologies. An intact and substantial seal formation above a storage reservoir is required for a significant portion of the initial sealing mechanisms believed to occur during carbon dioxide storage operations. Shales are a common seal formation rock types found above numerous hydrocarbon reservoirs, as well as potential saline aquifer storage locations. Shales commonly have very low permeability, however they also have the tendency to be quite fissile, and the formation of fractures within these seals can have a significant detrimental effect on the sealing potential of a reservoir and amount to large areas of high permeability and low capillary pressures compared to the surrounding intact rock. Fractured shales also have an increased current interest due to the increasing development of shale gas reservoirs using hydraulic fracturing techniques. This work shows the observed changes that occur within fractured pieces of reservoir seal shale samples, along with quarry analogues, using an in-situ micro-CT fluid flow imaging apparatus with a Hassler type core holder. Changes within the preferential flow path under different stress regimes as well as physical changes to the fracture geometry are reported. Lattice Boltzmann flow simulations were then performed on the extracted flow paths and compared to experiment permeability measurements. The preferential flow path of carbon dioxide through the fracture network is also observed and compared to the results two-phase Lattice Boltzmann fluid flow simulations.

Heterogeneity of shale documented by micro-FTIR and image analysis.

PubMed

Chen, Yanyan; Mastalerz, Maria; Schimmelmann, Arndt

2014-12-01

In this study, four New Albany Shale Devonian and Mississippian samples, with vitrinite reflectance [Ro ] values ranging from 0.55% to 1.41%, were analyzed by micro-FTIR mapping of chemical and mineralogical properties. One additional postmature shale sample from the Haynesville Shale (Kimmeridgian, Ro = 3.0%) was included to test the limitation of the method for more mature substrates. Relative abundances of organic matter and mineral groups (carbonates, quartz and clays) were mapped across selected microscale regions based on characteristic infrared peaks and demonstrated to be consistent with corresponding bulk compositional percentages. Mapped distributions of organic matter provide information on the organic matter abundance and the connectivity of organic matter within the overall shale matrix. The pervasive distribution of organic matter mapped in the New Albany Shale sample MM4 is in agreement with this shale's high total organic carbon abundance relative to other samples. Mapped interconnectivity of organic matter domains in New Albany Shale samples is excellent in two early mature shale samples having Ro values from 0.55% to 0.65%, then dramatically decreases in a late mature sample having an intermediate Ro of 1.15% and finally increases again in the postmature sample, which has a Ro of 1.41%. Swanson permeabilities, derived from independent mercury intrusion capillary pressure porosimetry measurements, follow the same trend among the four New Albany Shale samples, suggesting that micro-FTIR, in combination with complementary porosimetric techniques, strengthens our understanding of porosity networks. In addition, image processing and analysis software (e.g. ImageJ) have the capability to quantify organic matter and total organic carbon - valuable parameters for highly mature rocks, because they cannot be analyzed by micro-FTIR owing to the weakness of the aliphatic carbon-hydrogen signal. © 2014 The Authors Journal of Microscopy © 2014 Royal Microscopical Society.

Towards the development of rapid screening techniques for shale gas core properties

NASA Astrophysics Data System (ADS)

Cave, Mark R.; Vane, Christopher; Kemp, Simon; Harrington, Jon; Cuss, Robert

2013-04-01

Shale gas has been produced for many years in the U.S.A. and forms around 8% of total their natural gas production. Recent testing for gas on the Fylde Coast in Lancashire UK suggests there are potentially large reserves which could be exploited. The increasing significance of shale gas has lead to the need for deeper understanding of shale behaviour. There are many factors which govern whether a particular shale will become a shale gas resource and these include: i) Organic matter abundance, type and thermal maturity; ii) Porosity-permeability relationships and pore size distribution; iii) Brittleness and its relationship to mineralogy and rock fabric. Measurements of these properties require sophisticated and time consuming laboratory techniques (Josh et al 2012), whereas rapid screening techniques could provide timely results which could improve the efficiency and cost effectiveness of exploration. In this study, techniques which are portable and provide rapid on-site measurements (X-ray Fluorescence (XRF) and Infra-red (IR) spectroscopy) have been calibrated against standard laboratory techniques (Rock-Eval 6 analyser-Vinci Technologies) and Powder whole-rock XRD analysis was carried out using a PANalytical X'Pert Pro series diffractometer equipped with a cobalt-target tube, X'Celerator detector and operated at 45kV and 40mA, to predict properties of potential shale gas material from core material from the Bowland shale Roosecote, south Cumbria. Preliminary work showed that, amongst various mineralogical and organic matter properties of the core, regression models could be used so that the total organic carbon content could be predicted from the IR spectra with a 95 percentile confidence prediction error of 0.6% organic carbon, the free hydrocarbons could be predicted with a 95 percentile confidence prediction error of 0.6 mgHC/g rock, the bound hydrocarbons could be predicted with a 95 percentile confidence prediction error of 2.4 mgHC/g rock, mica content with a 95 percentile confidence prediction error of 14% and quartz content with a 95 percentile confidence prediction error of 14% . References M. Josh *, L. Esteban, C. Delle Piane, J. Sarout, D.N. Dewhurst, M.B. Clennell 2012. Journal of Petroleum Science and Engineering , 88-89, 107-124.

Analysis of Mancos shale failure in light of localization theory for transversely isotropic materials.

NASA Astrophysics Data System (ADS)

Ingraham, M. D.; Dewers, T. A.; Heath, J. E.

2016-12-01

Utilizing the localization conditions laid out in Rudnicki 2002, the failure of a series of tests performed on Mancos shale has been analyzed. Shale specimens were tested under constant mean stress conditions in an axisymmetric stress state, with specimens cored both parallel and perpendicular to bedding. Failure data indicates that for the range of pressures tested the failure surface is well represented by a Mohr- Coulomb failure surface with a friction angle of 34.4 for specimens cored parallel to bedding, and 26.5 for specimens cored perpendicular to bedding. There is no evidence of a yield cap up to 200 MPa mean stress. Comparison with the theory shows that the best agreement in terms of band angles comes from assuming normality of the plastic strain increment. Sandia National Laboratories is a multi-program laboratory managed and operated by Sandia Corporation, a wholly owned subsidiary of Lockheed Martin Corporation, for the U.S. Department of Energy's National Nuclear Security Administration under contract DE-AC04-94AL85000.

Deposition of sedimentary organic matter in black shale facies indicated by the geochemistry and petrography of high-resolution samples, blake nose, western North Atlantic

USGS Publications Warehouse

Barker, C.E.; Pawlewicz, M.; Cobabe, E.A.

2001-01-01

A transect of three holes drilled across the Blake Nose, western North Atlantic Ocean, retrieved cores of black shale facies related to the Albian Oceanic Anoxic Events (OAE) lb and ld. Sedimentary organic matter (SOM) recovered from Ocean Drilling Program Hole 1049A from the eastern end of the transect showed that before black shale facies deposition organic matter preservation was a Type III-IV SOM. Petrography reveals that this SOM is composed mostly of degraded algal debris, amorphous SOM and a minor component of Type III-IV terrestrial SOM, mostly detroinertinite. When black shale facies deposition commenced, the geochemical character of the SOM changed from a relatively oxygen-rich Type III-IV to relatively hydrogen-rich Type II. Petrography, biomarker and organic carbon isotopic data indicate marine and terrestrial SOM sources that do not appear to change during the transition from light-grey calcareous ooze to the black shale facies. Black shale subfacies layers alternate from laminated to homogeneous. Some of the laminated and the poorly laminated to homogeneous layers are organic carbon and hydrogen rich as well, suggesting that at least two SOM depositional processes are influencing the black shale facies. The laminated beds reflect deposition in a low sedimentation rate (6m Ma-1) environment with SOM derived mostly from gravity settling from the overlying water into sometimes dysoxic bottom water. The source of this high hydrogen content SOM is problematic because before black shale deposition, the marine SOM supplied to the site is geochemically a Type III-IV. A clue to the source of the H-rich SOM may be the interlayering of relatively homogeneous ooze layers that have a widely variable SOM content and quality. These relatively thick, sometimes subtly graded, sediment layers are thought to be deposited from a Type II SOM-enriched sediment suspension generated by turbidities or direct turbidite deposition.

Geochemical changes and fracture development in Woodford Shale cores following hydrous pyrolysis under uniaxial confinement

USGS Publications Warehouse

Birdwell, Justin E.; Lewan, Michael D.; Miller, Michael; Baez, Luis; Beeney, Ken; Sonnenberg, Steve

2013-01-01

A uniaxial confinement clamp was used on Woodford Shale cores in hydrous pyrolysis experiments to study fracture development during thermal maturation. The clamp simulates overburden in that it prevents cores from expanding perpendicular to bedding fabric during the volume-increasing reactions associated with petroleum generation. Cores were cut from a slab of immature Woodford Shale and subjected to hydrous pyrolysis under confinement at 300, 330, and 365 °C for 72 hours to induce thermal maturities ranging from early bitumen to maximum expelled-oil generation. Two additional cores were used as experimental controls: (1) a confined core was saturated with water by heating it to 100 °C under hydrous pyrolysis conditions for 72 hours to use for characterization of the original rock, and (2) an unconfined core was heated at 365 °C for 72 hours to evaluate the effects of confinement on petroleum generation and expulsion. X-ray computed tomography (X-CT) imaging and other analyses identified five distinct beds within the cored interval. Using a tentative classification system, beds 1, 2, and 3 are described as dolomitic marlstone (DM) with total organic carbon (TOC) contents of 7.7, 5.8, and 7.7 wt. %, respectively; bed 4 is a cherty quartzose claystone (CQC) with TOC content of 5.5 wt. %; and bed 5 is a quartzose claystone with TOC content of 10.9 wt. %. Bed samples all had similar Rock-Eval hydrogen indices (600 ± 46 mg S2/g-TOC) and Tmax values (433 ± 2 °C), demonstrating organic matter uniformity and low thermal maturity. The X-CT scan of the core heated to 100 °C showed preexisting fractures that were nearly perpendicular to the bedding fabric primarily in the low-TOC DM bed 2 and CQC bed 4. Heating led to enhancement of preexisting fractures in the confined cores with the greatest enhancement occurring in CQC bed 4. The fractures increased in size and intensity with temperature. This is attributed to the internal pressure generated by volume-increasing reactions during the conversion of kerogen to bitumen and bitumen to oil and gas. The unconfined core heated to 365 °C showed no enhanced fracturing and its X-CT-scan resembled that of the 100 °C confined core. Comparison of the oil and gas yields from the confined and unconfined cores heated to 365 °C showed no significant differences, indicating that product expulsion is not inhibited by the procedure used in this study. These results also indicate that fracturing during thermal maturation is driven primarily by the enhancement of existing fractures.

Properties of Silurian shales from the Barrandian Basin, Czech Republic

NASA Astrophysics Data System (ADS)

Weishauptová, Zuzana; Přibyl, Oldřich; Sýkorová, Ivana

2017-04-01

Although shale gas-bearing deposits have a markedly lower gas content than coal deposits, great attention has recently been paid to shale gas as a new potential source of fossil energy. Shale gas extraction is considered to be quite economical, despite the lower sorption capacity of shales, which is only about 10% of coal sorption capacities The selection of a suitable locality for extracting shale gas requires the sorption capacity of the shale to be determined. The sorption capacity is determined in the laboratory by measuring the amount of methane absorbed in a shale specimen at a pressure and a temperature corresponding to in situ conditions, using high pressure sorption. According to the principles of reversibility of adsorption/desorption, this amount should be roughly related to the amount of gas released by forced degassing. High pressure methane sorption isotherms were measured on seven representative samples of Silurian shales from the Barrandian Basin, Czech Republic. Excess sorption measurements were performed at a temperature of 45oC and at pressures up to 15 MPa on dry samples, using a manometric method. Experimental methane high-pressure isotherms were fitted to a modified Langmuir equation. The maximum measured excess sorption parameter and the Langmuir sorption capacity parameter were used to study the effect of TOC content, organic maturity, inorganic components and porosity on the methane sorption capacity. The studied shale samples with random reflectance of graptolite 0.56 to 1.76% had a very low TOC content and dominant mineral fractions. Illite was the prevailing clay mineral. The sample porosity ranged from 4.6 to 18.8%. In most samples, the micropore volumes were markedly lower than the meso- and macropore volumes. In the Silurian black shales, the occurrence of fractures parallel with the original sedimentary bending was highly significant. A greater proportion of fragments of carbonaceous particles of graptolites and bitumens in the Barrandian Silurian shales had a smooth surface without pores. No relation has been proven between TOC-normalized excess sorption capacities or the TOC-normalized Langmuir sorption capacities and thermal maturation of the shales. The methane sorption capacities of shale samples show a positive correlation with TOC and a positive correlation with the clay content. The highest sorption capacity was observed in shale samples with the highest percentage of micropores, indicating that the micropore volume in the organic matter and clay minerals is a principal factor affecting the sorption capacity of the shale samples.

Updated methodology for nuclear magnetic resonance characterization of shales

NASA Astrophysics Data System (ADS)

Washburn, Kathryn E.; Birdwell, Justin E.

2013-08-01

Unconventional petroleum resources, particularly in shales, are expected to play an increasingly important role in the world's energy portfolio in the coming years. Nuclear magnetic resonance (NMR), particularly at low-field, provides important information in the evaluation of shale resources. Most of the low-field NMR analyses performed on shale samples rely heavily on standard T1 and T2 measurements. We present a new approach using solid echoes in the measurement of T1 and T1-T2 correlations that addresses some of the challenges encountered when making NMR measurements on shale samples compared to conventional reservoir rocks. Combining these techniques with standard T1 and T2 measurements provides a more complete assessment of the hydrogen-bearing constituents (e.g., bitumen, kerogen, clay-bound water) in shale samples. These methods are applied to immature and pyrolyzed oil shale samples to examine the solid and highly viscous organic phases present during the petroleum generation process. The solid echo measurements produce additional signal in the oil shale samples compared to the standard methodologies, indicating the presence of components undergoing homonuclear dipolar coupling. The results presented here include the first low-field NMR measurements performed on kerogen as well as detailed NMR analysis of highly viscous thermally generated bitumen present in pyrolyzed oil shale.

Updated methodology for nuclear magnetic resonance characterization of shales

USGS Publications Warehouse

Washburn, Kathryn E.; Birdwell, Justin E.

2013-01-01

Unconventional petroleum resources, particularly in shales, are expected to play an increasingly important role in the world’s energy portfolio in the coming years. Nuclear magnetic resonance (NMR), particularly at low-field, provides important information in the evaluation of shale resources. Most of the low-field NMR analyses performed on shale samples rely heavily on standard T1 and T2 measurements. We present a new approach using solid echoes in the measurement of T1 and T1–T2 correlations that addresses some of the challenges encountered when making NMR measurements on shale samples compared to conventional reservoir rocks. Combining these techniques with standard T1 and T2 measurements provides a more complete assessment of the hydrogen-bearing constituents (e.g., bitumen, kerogen, clay-bound water) in shale samples. These methods are applied to immature and pyrolyzed oil shale samples to examine the solid and highly viscous organic phases present during the petroleum generation process. The solid echo measurements produce additional signal in the oil shale samples compared to the standard methodologies, indicating the presence of components undergoing homonuclear dipolar coupling. The results presented here include the first low-field NMR measurements performed on kerogen as well as detailed NMR analysis of highly viscous thermally generated bitumen present in pyrolyzed oil shale.

Micromorphologic evidence for paleosol development in the Endicott group, Siksikpuk formation, Kingak(?) shale, and Ipewik formation, western Brooks range, Alaska

USGS Publications Warehouse

Dumoulin, Julie A.; White, Tim

2005-01-01

Micromorphologic evidence indicates the presence of paleosols in drill-core samples from four sedimentary units in the Red Dog area, western Brooks Range. Well-developed sepic-plasmic fabrics and siderite spherules occur in claystones of the Upper Devonian through Lower Mississippian(?) Kanayut Conglomerate (Endicott Group), the Pennsylvanian through Permian Siksikpuk Formation (Etivluk Group), the Jurassic through Lower Cretaceous Kingak(?) Shale, and the Lower Cretaceous Ipewik Formation. Although exposure surfaces have been previously recognized in the Endicott Group and Kingak Shale on the basis of outcrop features, our study is the first microscopic analysis of paleosols from these units, and it provides the first evidence of subaerial exposure in the Siksikpuk and Ipewik Formations. Regional stratigraphic relations and geochemical data support our interpretations. Paleosols in the Siksikpuk, Kingak, and Ipewik Formations likely formed in nearshore coastal-plain environments, with pore waters subjected to inundation by the updip migration of slightly brackish ground water, whereas paleosols in the Kanayut Conglomerate probably formed in a more distal setting relative to a marine basin.

Estimating Hydraulic Conductivities in a Fractured Shale Formation from Pressure Pulse Testing and 3d Modeling

NASA Astrophysics Data System (ADS)

Courbet, C.; DICK, P.; Lefevre, M.; Wittebroodt, C.; Matray, J.; Barnichon, J.

2013-12-01

In the framework of its research on the deep disposal of radioactive waste in shale formations, the French Institute for Radiological Protection and Nuclear Safety (IRSN) has developed a large array of in situ programs concerning the confining properties of shales in their underground research laboratory at Tournemire (SW France). One of its aims is to evaluate the occurrence and processes controlling radionuclide migration through the host rock, from the disposal system to the biosphere. Past research programs carried out at Tournemire covered mechanical, hydro-mechanical and physico-chemical properties of the Tournemire shale as well as water chemistry and long-term behaviour of the host rock. Studies show that fluid circulations in the undisturbed matrix are very slow (hydraulic conductivity of 10-14 to 10-15 m.s-1). However, recent work related to the occurrence of small scale fractures and clay-rich fault gouges indicate that fluid circulations may have been significantly modified in the vicinity of such features. To assess the transport properties associated with such faults, IRSN designed a series of in situ and laboratory experiments to evaluate the contribution of both diffusive and advective process on water and solute flux through a clay-rich fault zone (fault core and damaged zone) and in an undisturbed shale formation. As part of these studies, Modular Mini-Packer System (MMPS) hydraulic testing was conducted in multiple boreholes to characterize hydraulic conductivities within the formation. Pressure data collected during the hydraulic tests were analyzed using the nSIGHTS (n-dimensional Statistical Inverse Graphical Hydraulic Test Simulator) code to estimate hydraulic conductivity and formation pressures of the tested intervals. Preliminary results indicate hydraulic conductivities of 5.10-12 m.s-1 in the fault core and damaged zone and 10-14 m.s-1 in the adjacent undisturbed shale. Furthermore, when compared with neutron porosity data from borehole logging, porosity varies by a factor of 2.5 whilst hydraulic conductivity varies by 2 to 3 orders of magnitude. In addition, a 3D numerical reconstruction of the internal structure of the fault zone inferred from borehole imagery has been built to estimate the permeability tensor variations. First results indicate that hydraulic conductivity values calculated for this structure are 2 to 3 orders of magnitude above those measured in situ. Such high values are due to the imaging method that only takes in to account open fractures of simple geometry (sine waves). Even though improvements are needed to handle more complex geometry, outcomes are promising as the fault damaged zone clearly appears as the highest permeability zone, where stress analysis show that the actual stress state may favor tensile reopening of fractures. Using shale samples cored from the different internal structures of the fault zone, we aim now to characterize the advection and diffusion using laboratory petrophysical tests combined with radial and through-diffusion experiments.

Artificial maturation of oil shale: The Irati Formation from the Parana Basin, Brazil

NASA Astrophysics Data System (ADS)

Gayer, James L.

Oil shale samples from the Irati Formation in Brazil were evaluated from an outcrop block, denoted Block 003. The goals of this thesis include: 1) Characterizing the Irati Formation, 2) Comparing the effects of two different types of pyrolysis, anhydrous and hydrous, and 3) Utilizing a variety of geophysical experiments to determine the changes associated with each type of pyrolysis. Primary work included determining total organic carbon, source rock analysis, mineralogy, computer tomography x-ray scans, and scanning electron microscope images before and after pyrolysis, as well as acoustic properties of the samples during pyrolysis. Two types of pyrolysis (hydrous and anhydrous) were performed on samples cored at three different orientations (0°, 45°, and 90°) with respect to the axis of symmetry, requiring six total experiments. During pyrolysis, the overall effective pressure was maintained at 800 psi, and the holding temperature was 365°C. The changes and deformation in the hydrous pyrolysis samples were greater compared to the anhydrous pyrolysis. The velocities gave the best indication of changes occurring during pyrolysis, but it was difficult to maintain the same amplitude and quality of waveforms at higher temperatures. The velocity changes were due to a combination of factors, including thermal deformation of the samples, fracture porosity development, and the release of adsorbed water and bitumen from the sample. Anhydrous pyrolysis in this study did not reduce TOC, while TOC was reduced due to hydrous pyrolysis by 5%, and velocities in the hydrous pyrolysis decreased by up to 30% at 365°C compared to room temperature. Data from this study and future data that can be acquired with the improved high-temperature, high-pressure experiment will assist in future economic production from oil shale at lower temperatures under hydrous pyrolysis conditions.

Experimental study of CO2 effect on shale mechanical properties in the processes of complete strain-stress and post-failure tests

NASA Astrophysics Data System (ADS)

Wang, Y.; Ji, J.; Li, M.

2017-12-01

CO2 enhanced shale gas recovery has proved to be one of the most efficient methods to extract shale gas, and represent a mutually beneficial approach to mitigate greenhouse gas emission into the atmosphere. During the processes of most CO2 enhanced shale gas recovery, liquid CO2 is injected into reservoirs, fracturing the shale, making competitive adsorption with shale gas and displacing the shale gas at multi-scale to the production well. Hydraulic and mechanical coupling actions between the shale and fluid media are expected to play important roles in affecting fracture propagation, CO2 adsorption and shale gas desorption, multi-scale fluid flow, plume development, and CO2 storage. In this study, four reservoir shale samples were selected to carry out triaxial compression experiments of complete strain-stress and post failure tests. Two fluid media, CO2 and N2, were used to flow through the samples and produce the pore pressure. All of the above four compression experiments were conducted under the same confining and pore pressures, and loaded the axial pressure with the same loading path. Permeability, strain-stress, and pore volumetric change were measured and recorded over time. The results show that, compared to N2, CO2 appeared to lower the peak strength and elastic modulus of shale samples, and increase the permeability up two to six orders of magnitudes after the sample failure. Furthermore, the shale samples were dilated by CO2 much more than N2, and retained the volume of CO2 2.6 times more than N2. Results from this study indicate that the CO2 can embrittle the shale formation so as to form fracture net easily to enhance the shale gas recovery. Meanwhile, part of the remaining CO2 might be adsorbed on the surface of shale matrix and the rest of the CO2 be in the pore and fracture spaces, implying that CO2 can be effectively geo-stored in the shale formation.

Provenance and depositional history of continental slope sediments in the Southwestern Gulf of Mexico unraveled by geochemical analysis

NASA Astrophysics Data System (ADS)

Armstrong-Altrin, John S.; Machain-Castillo, María Luisa; Rosales-Hoz, Leticia; Carranza-Edwards, Arturo; Sanchez-Cabeza, Joan-Albert; Ruíz-Fernández, Ana Carolina

2015-03-01

The aim of this work is to constrain the provenance and depositional history of continental slope sediments in the Southwestern Gulf of Mexico (~1089-1785 m water depth). To achieve this, 10 piston sediment cores (~5-5.5 m long) were studied for mineralogy, major, trace and rare earth element geochemistry. Samples were analyzed at three core sections, i.e. upper (0-1 cm), middle (30-31 cm) and lower (~300-391 cm). The textural study reveals that the core sediments are characterized by silt and clay fractions. Radiocarbon dating of sediments for the cores at different levels indicated a maximum of ~28,000 year BP. Sediments were classified as shale. The chemical index of alteration (CIA) values for the upper, middle, and lower sections revealed moderate weathering in the source region. The index of chemical maturity (ICV) and SiO2/Al2O3 ratio indicated low compositional maturity for the core sediments. A statistically significant correlation observed between total rare earth elements (∑REE) versus Al2O3 and Zr indicated that REE are mainly housed in detrital minerals. The North American Shale Composite (NASC) normalized REE patterns, trace element concentrations such as Cr, Ni and V, and the comparison of REE concentrations in sediments and source rocks indicated that the study area received sediments from rocks intermediate between felsic and mafic composition. The enrichment factor (EF) results indicated that the Cd and Zn contents of the upper section sediments were influenced by an anthropogenic source. The trace element ratios and authigenic U content of the core sediments indicated the existence of an oxic depositional environment.

Experimental study on the influence of slickwater on shale permeability

NASA Astrophysics Data System (ADS)

Liu, Zhonghua; Bai, Baojun; Zhang, Zheyu; Tang, Jing; Zeng, Shunpeng; Li, Xiaogang

2018-02-01

There are two diametrically opposite views of the influence of slickwater on shale permeability among scholars at home and abroad. We used the shale outcrops rock samples from the Lower Silurian Longmaxi Formation in Sichuan Basin. The permeability of these dry samples before and after immersion in different solution systems were tested by pulse attenuation method. The experimental results show that the impregnation of different slickwater components and standard salt solution can promote the increase of the permeability of shale samples. The stress sensitivity of shale samples after liquid immersion is medium weak to weak. The sample stress sensitivity is weak after soaked by the synergist solution and Drag reducing agent solution, and the sensitivity of the sample stress is medium weak after immersed by the standard saline solution, defoamer solution and antiswelling solution; The Ki/K0 of the shale sample after liquid immersion on σi/σ0 is consistent with the exponential stress sensitive evaluation model. With the increase of soaking time, the increase of sample permeability increases first and then decreases.

Results of chemical analyses of soil, shale, and soil/shale extract from the Mancos Shale formation in the Gunnison Gorge National Conservation Area, southwestern Colorado, and at Hanksville, Utah

USGS Publications Warehouse

Tuttle, Michele L.W.; Fahy, Juli; Grauch, Richard I.; Ball, Bridget A.; Chong, Geneva W.; Elliott, John G.; Kosovich, John J.; Livo, Keith E.; Stillings, Lisa L.

2007-01-01

Results of chemical and some isotopic analyses of soil, shale, and water extracts collected from the surface, trenches, and pits in the Mancos Shale are presented in this report. Most data are for sites on the Gunnison Gorge National Conservation Area (GGNCA) in southwestern Colorado. For comparison, data from a few sites from the Mancos landscape near Hanksville, Utah, are included. Twelve trenches were dug on the GGNCA from which 258 samples for whole-rock (total) analyses and 187 samples for saturation paste extracts were collected. Sixteen of the extract samples were duplicated and subjected to a 1:5 water extraction for comparison. A regional soil survey across the Mancos landscape on the GGNCA generated 253 samples for whole-rock analyses and saturation paste extractions. Seventeen gypsum samples were collected on the GGNCA for sulfur and oxygen isotopic analysis. Sixteen samples were collected from shallow pits in the Mancos Shale near Hanksville, Utah.

Using Neutrons to Study Fluid-Rock Interactions in Shales

NASA Astrophysics Data System (ADS)

DiStefano, V. H.; McFarlane, J.; Anovitz, L. M.; Gordon, A.; Hale, R. E.; Hunt, R. D.; Lewis, S. A., Sr.; Littrell, K. C.; Stack, A. G.; Chipera, S.; Perfect, E.; Bilheux, H.; Kolbus, L. M.; Bingham, P. R.

2015-12-01

Recovery of hydrocarbons by hydraulic fracturing depends on complex fluid-rock interactions that we are beginning to understand using neutron imaging and scattering techniques. Organic matter is often thought to comprise the majority of porosity in a shale. In this study, correlations between the type of organic matter embedded in a shale and porosity were investigated experimentally. Selected shale cores from the Eagle Ford and Marcellus formations were subjected to pyrolysis-gas chromatography, Differential Thermal Analysis/Thermogravimetric analysis, and organic solvent extraction with the resulting affluent analyzed by gas chromatography-mass spectrometry. The pore size distribution of the microporosity (~1 nm to 2 µm) in the Eagle Ford shales was measured before and after solvent extraction using small angle neutron scattering. Organics representing mass fractions of between 0.1 to 1 wt.% were removed from the shales and porosity generally increased across the examined microporosity range, particularly at larger pore sizes, approximately 50 nm to 2 μm. This range reflects extraction of accessible organic material, including remaining gas molecules, bitumen, and kerogen derivatives, indicating where the larger amount of organic matter in shale is stored. An increase in porosity at smaller pore sizes, ~1-3 nm, was also present and could be indicative of extraction of organic material stored in the inter-particle spaces of clays. Additionally, a decrease in porosity after extraction for a sample was attributed to swelling of pores with solvent uptake. This occurred in a shale with high clay content and low thermal maturity. The extracted hydrocarbons were primarily paraffinic, although some breakdown of larger aromatic compounds was observed in toluene extractions. The amount of hydrocarbon extracted and an overall increase in porosity appeared to be primarily correlated with the clay percentage in the shale. This study complements fluid transport neutron imaging studies, to explain the physics and chemistry of fluid-rock behavior. Research supported by the U.S. Department of Energy, Office of Science, Basic Energy Sciences, Chemical Sciences, Geosciences, and Biosciences Division and the Bredesen Center at the University of Tennessee.

Early diagenetic partial oxidation of organic matter and sulfides in the Middle Pennsylvanian (Desmoinesian) Excello Shale Member of the Fort Scott Limestone and equivalents, northern Midcontinent region, USA

USGS Publications Warehouse

Hatch, J.R.; Leventhal, M.S.

1997-01-01

A process of early diagenetic partial oxidation of organic matter and sulfides has altered the chemical composition of the Middle Pennsylvanian Excello Shale Member of the Fort Scott Limestone and equivalents in the northern Midcontinent region. This process was identified by comparison of organic carbon contents, Rock-Eval hydrogen indices, organic carbon ??13C and element compositions of core and surface mine samples of the Excello Shale Member with analyses of three other underlying and overlying organic-matter-rich marine shales (offshore shale lithofacies) from southern Iowa, northern Missouri, eastern Kansas and northeastern Oklahoma. The end product of the partial oxidation process is shale with relatively low contents of hydrogen-poor, C13-enriched organic matter, lower contents of sulfur and sulfide-forming elements, and relatively unchanged contents of phosphorus and many trace elements (e.g. Cr, Ni, and V). However, because of lower organic carbon contents, element/organic carbon ratios are greatly increased. The partial oxidation process apparently took place during subaerial exposure of the overlying marine carbonate member (Blackjack Creek Member of the Fort Scott Limestone) following a marine regression when meteoric waters percolated down to the level of the Excello muds allowing oxidation of organic matter and sulfides. This hypothesis is supported by earlier workers, who have identified meteoric carbonate cements within, and soil horizons at the top of the Blackjack Creek Member. The period of oxidation is constrained in that organic matter and sulfides in the Little Osage Shale Member of the Fort Scott Limestone and equivalents (immediately overlying the Blackjack Creek Member) appear unaltered. Similar alteration of other shales in the Middle and Upper Pennsylvanian sections may be local to regional in extent and would depend on the extent and duration of the marine regression and be influenced by local variations in permeability and topography. The partial oxidation process has likely led to a redistribution of sulfur and sulfide-forming elements into other organic-rich lithologies in the section. The altered/oxidized shales are nongenerative with respect to hydrocarbon generation.

Indirect and direct tensile behavior of Devonian oil shales

DOE Office of Scientific and Technical Information (OSTI.GOV)

Chong, K.P.; Chen, J.L.; Dana, G.F.

1984-03-01

Ultimate indirect tensile strengths of Devonian oil shales across the bedding planes is a mechanical property parameter important to predicting how oil shale will break. This is particularly important to in-situ fragmentation. The Split Cylinder Test was used to determine the indirect tensile strengths between the bedding planes. Test specimens, cored perpendicular to the bedding planes, representing oil shales of different oil yields taken from Silver Point Quad in DeKalb County, Tennessee and Friendship in Scioto County, Ohio, were subjected to the Split Cylinder Test. Linear regression equations relating ultimate tensile strength across the bedding planes to volume percent ofmore » organic matter in the rock were developed from the test data. In addition, direct tensile strengths were obtained between the bedding planes for the Tennessee oil shales. This property is important for the design of horizontal fractures in oil shales. Typical results were presented.« less

Linear infrastructure drives habitat conversion and forest fragmentation associated with Marcellus shale gas development in a forested landscape.

PubMed

Langlois, Lillie A; Drohan, Patrick J; Brittingham, Margaret C

2017-07-15

Large, continuous forest provides critical habitat for some species of forest dependent wildlife. The rapid expansion of shale gas development within the northern Appalachians results in direct loss of such habitat at well sites, pipelines, and access roads; however the resulting habitat fragmentation surrounding such areas may be of greater importance. Previous research has suggested that infrastructure supporting gas development is the driver for habitat loss, but knowledge of what specific infrastructure affects habitat is limited by a lack of spatial tracking of infrastructure development in different land uses. We used high-resolution aerial imagery, land cover data, and well point data to quantify shale gas development across four time periods (2010, 2012, 2014, 2016), including: the number of wells permitted, drilled, and producing gas (a measure of pipeline development); land use change; and forest fragmentation on both private and public land. As of April 2016, the majority of shale gas development was located on private land (74% of constructed well pads); however, the number of wells drilled per pad was lower on private compared to public land (3.5 and 5.4, respectively). Loss of core forest was more than double on private than public land (4.3 and 2.0%, respectively), which likely results from better management practices implemented on public land. Pipelines were by far the largest contributor to the fragmentation of core forest due to shale gas development. Forecasting future land use change resulting from gas development suggests that the greatest loss of core forest will occur with pads constructed farthest from pre-existing pipelines (new pipelines must be built to connect pads) and in areas with greater amounts of core forest. To reduce future fragmentation, our results suggest new pads should be placed near pre-existing pipelines and methods to consolidate pipelines with other infrastructure should be used. Without these mitigation practices, we will continue to lose core forest as a result of new pipelines and infrastructure particularly on private land. Copyright © 2017 Elsevier Ltd. All rights reserved.

The geological and microbiological controls on the enrichment of Se and Te in sedimentary rocks

NASA Astrophysics Data System (ADS)

Bullock, Liam; Parnell, John; Armstrong, Joseph; Boyce, Adrian; Perez, Magali

2017-04-01

Selenium (Se) and tellurium (Te) have become elements of high interest, mainly due to their photovoltaic and photoconductive properties, and can contaminate local soils and groundwater systems during mobilisation. Due to their economic and environmental significance, it is important to understand the processes that lead to Se- and Te-enrichment in sediments. The distribution of Se and Te in sedimentary environments is primarily a function of redox conditions, and may be transported and concentrated by the movement of reduced fluids through oxidised strata. Se and Te concentrations have been measured in a suite of late Neoproterozoic Gwna Group black shales (UK) and uranium red bed (roll-front) samples (USA). Due to the chemical affinity of Se and sulphur (S), variations in the S isotopic composition of pyrite have also been measured in order to provide insights into their origin. Scanning electron microscopy of pyrite in the black shales shows abundant inclusions of the lead selenide mineral clausthalite. The data for the black shale samples show marked enrichment in Te and Se relative to crustal mean and several hundreds of other samples processed through our laboratory. While Se levels in sulphidic black shales are typically below 5 ppm, the measured values of up to 116 ppm are remarkable. The Se enrichment in roll-fronts (up to 168 ppm) is restricted to a narrow band of alteration at the interface between the barren oxidised core, and the highly mineralised reduced nose of the front. Te is depleted in roll-fronts with respect to the continental crust and other geological settings and deposits. S isotope compositions for pyrite in both the black shales and roll-fronts are very light and indicate precipitation by microbial sulphate reduction, suggesting that Se was microbially sequestered. Results show that Gwna Group black shales and U.S roll-front deposits contain marked elemental enrichments (particularly Se content). In Gwna Group black shales, Se and Te were sequestered out of seawater into pyritic shales at a higher rate than into crusts. Se enrichment in roll-fronts relates to the initial mobilisation of trace elements in oxidised conditions, and later precipitation downgradient in reduced conditions. Results highlight the potential for sedimentary types of Se- and Te-bearing deposits. The enrichment of elements of high value for future technologies in sedimentary rocks deserve careful assessment for potential future resources, and should be monitored during exploration and mobilisation due to the potential contamination effects. This work forms part of the NERC-funded 'Security of Supply of Mineral Resources' project, which aims to detail the science needed to sustain the security of supply of strategic minerals in a changing environment.

Effects of rock mineralogy and pore structure on stress-dependent permeability of shale samples

PubMed Central

Al Ismail, Maytham I.; Zoback, Mark D.

2016-01-01

We conducted pulse-decay permeability experiments on Utica and Permian shale samples to investigate the effect of rock mineralogy and pore structure on the transport mechanisms using a non-adsorbing gas (argon). The mineralogy of the shale samples varied from clay rich to calcite rich (i.e. clay poor). Our permeability measurements and scanning electron microscopy images revealed that the permeability of the shale samples whose pores resided in the kerogen positively correlated with organic content. Our results showed that the absolute value of permeability was not affected by the mineral composition of the shale samples. Additionally, our results indicated that clay content played a significant role in the stress-dependent permeability. For clay-rich samples, we observed higher pore throat compressibility, which led to higher permeability reduction at increasing effective stress than with calcite-rich samples. Our findings highlight the importance of considering permeability to be stress dependent to achieve more accurate reservoir simulations especially for clay-rich shale reservoirs. This article is part of the themed issue ‘Energy and the subsurface’. PMID:27597792

Comparison of formation mechanism of fresh-water and salt-water lacustrine organic-rich shale

NASA Astrophysics Data System (ADS)

Lin, Senhu

2017-04-01

Based on the core and thin section observation, major, trace and rare earth elements test, carbon and oxygen isotopes content analysis and other geochemical methods, a detailed study was performed on formation mechanism of lacustrine organic-rich shale by taking the middle Permian salt-water shale in Zhungaer Basin and upper Triassic fresh-water shale in Ordos Basin as the research target. The results show that, the middle Permian salt-water shale was overall deposited in hot and dry climate. Long-term reductive environment and high biological abundance due to elevated temperature provides favorable conditions for formation and preservation of organic-rich shale. Within certain limits, the hotter climate, the organic-richer shale formed. These organic-rich shale was typically distributed in the area where palaeosalinity is relatively high. However, during the upper Triassic at Ordos Basin, organic-rich shale was formed in warm and moist environment. What's more, if the temperature, salinity or water depth rises, the TOC in shale decreases. In other words, relatively low temperature and salinity, stable lake level and strong reducing conditions benefits organic-rich shale deposits in fresh water. In this sense, looking for high-TOC shale in lacustrine basin needs to follow different rules depends on the palaeoclimate and palaeoenvironment during sedimentary period. There is reason to believe that the some other factors can also have significant impact on formation mechanism of organic-rich shale, which increases the complexity of shale oil and gas prediction.

IMPACT OF PHYSICAL AND CHEMICAL MUD CONTAMINATION ON WELLBORE CEMENT- FORMATION SHEAR BOND STRENGTH Authors: Arome Oyibo1 and Mileva Radonjic1 * 1. Craft and Hawkins Department of Petroleum Engineering, 2131 Patrick F. Taylor Hall, Louisiana State University, Baton Rouge, LA 70803, aoyibo1@tigers.lsu.edu, mileva@lsu.edu

NASA Astrophysics Data System (ADS)

Oyibo, A. E.

2013-12-01

Wellbore cement has been used to provide well integrity through zonal isolation in oil & gas wells and geothermal wells. Cementing is also used to provide mechanical support for the casing and protect the casing from corrosive fluids. Failure of cement could be caused by several factors ranging from poor cementing, failure to completely displace the drilling fluids to failure on the path of the casing. A failed cement job could result in creation of cracks and micro annulus through which produced fluids could migrate to the surface which could lead to sustained casing pressure, contamination of fresh water aquifer and blow out in some cases. In addition, cement failures could risk the release of chemicals substances from hydraulic fracturing into fresh water aquifer during the injection process. To achieve proper cementing, the drilling fluid should be completely displaced by the cement slurry. However, this is hard to achieve in practice, some mud is usually left on the wellbore which ends up contaminating the cement afterwards. The purpose of this experimental study is to investigate the impact of both physical and chemical mud contaminations on cement-formation bond strength for different types of formations. Physical contamination occurs when drilling fluids (mud) dries on the surface of the formation forming a mud cake. Chemical contamination on the other hand occurs when the drilling fluids which is still in the liquid form interacts chemically with the cement during a cementing job. We investigated the impact of the contamination on the shear bond strength and the changes in the mineralogy of the cement at the cement-formation interface to ascertain the impact of the contamination on the cement-formation bond strength. Berea sandstone and clay rich shale cores were bonded with cement cores with the cement-formation contaminated either physically or chemically. For the physically contaminated composite cores, we have 3 different sample designs: clean/not contaminated, scrapped and washed composite cores. Similarly, for the chemically contaminated samples we had 3 different sample designs: 0%, 5% and 10% mud contaminated composite cores. Shear test were performed on the composite cores to determine the shear bond strength and the results suggested that the detrimental impact of the contamination is higher when the cores are physically contaminated i.e. when we have mud cake present at the surface of the wellbore before a cement job is performed. Also, the results showed that shear bond strength is higher for sandstone formations as compared to shale formations. Material characterization analysis was carried out to determine the micro structural changes at the cement-formation interface. The results obtained from the SEM and micro CT images taken at the bond interface confirmed that chemical contamination caused substantial changes in the spatial distribution of minerals that impacted bond strength. Keywords: Cement-Formation bond strength, mud contamination, shale, sandstone and material characterization *Corresponding author

Parameters controlling mechanical stratification of gas-bearing shale complexes: integration of wellbore logging and core profiling (Peri-Baltic Basin, Poland).

NASA Astrophysics Data System (ADS)

Pachytel, Radomir; Jarosiński, Marek; Bobek, Kinga; Roszkowska-Remin, Joanna; Roman, Michał

2016-04-01

In our study of mechanical properties of gas-bearing shale complexes from exploration wells in Pomerania, we take advantage from having access to continuous, several hundred meters long core profiles which are supplemented with complete sets of geophysical logging from the same shale intervals. We are focused on different approaches to discriminate the Consistent Mechanical Units (CMUs). Such units are essential for mechanical modeling of stress and strain in shales and their scale is highly dependent on the purpose of analyses. We have done a precise lithological and structural core profiling, which results in distinguishing Consistent Lithological Units (CLUs) at a centimeter scale. The geophysical logs, essential for mechanical studies, exhibit resolution from tens of centimeters to a meter. The meter resolution we have found appropriate for consideration of mechanics of hydraulic fracture propagation and therefore we have used it in CMUs analysis. The first challenge we have faced is to switch between scales of analyses without significant losses of information coming from the lower level of observation. The next challenge, is to find the mechanical parameter which is able to discriminate CMUs most efficiently. Brittleness Indexes (BIs) are commonly used parameters in order to characterize mechanical shale units, but at the same time these indexes are arbitrary defined to match individual requirements of the users. In our study, we have determined the BIs in several ways, based either on mineral composition or on elastic modules, both supplemented with pore volume. The gamma ray (GR), Young modulus (YM), Poisson Ratio (ν) interpretation from acoustic logging, bulk density (RHOB), porosity interpretation (ø) and mineralogical profile (ULTRA, GEM) from spectral logging were computed. Detailed comparison of lithological profile and discriminated CLUs with above logs led us to conclusions about geophysical representation of dolomite and silica lithified shale, organic matter enrichment tuffite layers or disturbances in lamination, which are important for mechanical differentiation of shale complexes. Finally, we have checked which of the calculated BIs matches best the lithological differentiation and the natural fracture density profile that allowed us for selection of the BI which, in our opinion, represents the potential for hydraulic fracture propagation. Our study in the frame of ShaleMech Project (Blue Gas Program) is in progress and the results are preliminary.

New insights on the Karoo shale gas potential from borehole KZF-1 (Western Cape, South Africa)

NASA Astrophysics Data System (ADS)

Campbell, Stuart A.; Götz, Annette E.; Montenari, Michael

2016-04-01

A study on world shale reserves conducted by the Energy Information Agency (EIA) in 2013 concluded that there could be as much as 390 Tcf recoverable reserves of shale gas in the southern and south-western parts of the Karoo Basin. This would make it the 8th-largest shale gas resource in the world. However, the true extent and commercial viability is still unknown, due to the lack of exploration drilling and modern 3D seismic. Within the framework of the Karoo Research Initiative (KARIN), two deep boreholes were drilled in the Eastern and Western Cape provinces of South Africa. Here we report on new core material from borehole KZF-1 (Western Cape) which intersected the Permian black shales of the Ecca Group, the Whitehill Formation being the main target formation for future shale gas production. To determine the original source potential for shale gas we investigated the sedimentary environments in which the potential source rocks formed, addressing the research question of how much sedimentary organic matter the shales contained when they originally formed. Palynofacies indicates marginal marine conditions of a stratified basin setting with low marine phytoplankton percentages (acritarchs, prasinophytes), good AOM preservation, high terrestrial input, and a high spores:bisaccates ratio (kerogen type III). Stratigraphically, a deepening-upward trend is observed. Laterally, the basin configuration seems to be much more complex than previously assumed. Furthermore, palynological data confirms the correlation of marine black shales of the Prince Albert and Whitehill formations in the southern and south-western parts of the Karoo Basin with the terrestrial coals of the Vryheid Formation in the north-eastern part of the basin. TOC values (1-6%) classify the Karoo black shales as promising shale gas resources, especially with regard to the high thermal maturity (Ro >3). The recently drilled deep boreholes in the southern and south-western Karoo Basin, the first since the SOEKOR exploration programmes of the 1960's and 1970's, provide new core material to determine the likely current potential for retention of shale gas with regard to the structural and thermal history of the basin. Thus, the KARIN research program will produce a valuable data set for future unconventional gas exploration and production in South Africa.

Clean and Secure Energy from Domestic Oil Shale and Oil Sands Resources

DOE Office of Scientific and Technical Information (OSTI.GOV)

Spinti, Jennifer; Birgenheier, Lauren; Deo, Milind

This report summarizes the significant findings from the Clean and Secure Energy from Domestic Oil Shale and Oil Sands Resources program sponsored by the Department of Energy through the National Energy Technology Laboratory. There were four principle areas of research; Environmental, legal, and policy issues related to development of oil shale and oil sands resources; Economic and environmental assessment of domestic unconventional fuels industry; Basin-scale assessment of conventional and unconventional fuel development impacts; and Liquid fuel production by in situ thermal processing of oil shale Multiple research projects were conducted in each area and the results have been communicated viamore » sponsored conferences, conference presentations, invited talks, interviews with the media, numerous topical reports, journal publications, and a book that summarizes much of the oil shale research relating to Utah’s Uinta Basin. In addition, a repository of materials related to oil shale and oil sands has been created within the University of Utah’s Institutional Repository, including the materials generated during this research program. Below is a listing of all topical and progress reports generated by this project and submitted to the Office of Science and Technical Information (OSTI). A listing of all peer-reviewed publications generated as a result of this project is included at the end of this report; Geomechanical and Fluid Transport Properties 1 (December, 2015); Validation Results for Core-Scale Oil Shale Pyrolysis (February, 2015); and Rates and Mechanisms of Oil Shale Pyrolysis: A Chemical Structure Approach (November, 2014); Policy Issues Associated With Using Simulation to Assess Environmental Impacts (November, 2014); Policy Analysis of the Canadian Oil Sands Experience (September, 2013); V-UQ of Generation 1 Simulator with AMSO Experimental Data (August, 2013); Lands with Wilderness Characteristics, Resource Management Plan Constraints, and Land Exchanges (March, 2012); Conjunctive Surface and Groundwater Management in Utah: Implications for Oil Shale and Oil Sands Development (May, 2012); Development of CFD-Based Simulation Tools for In Situ Thermal Processing of Oil Shale/Sands (February, 2012); Core-Based Integrated Sedimentologic, Stratigraphic, and Geochemical Analysis of the Oil Shale Bearing Green River Formation, Uinta Basin, Utah (April, 2011); Atomistic Modeling of Oil Shale Kerogens and Asphaltenes Along with their Interactions with the Inorganic Mineral Matrix (April, 2011); Pore Scale Analysis of Oil Shale/Sands Pyrolysis (March, 2011); Land and Resource Management Issues Relevant to Deploying In-Situ Thermal Technologies (January, 2011); Policy Analysis of Produced Water Issues Associated with In-Situ Thermal Technologies (January, 2011); and Policy Analysis of Water Availability and Use Issues for Domestic Oil Shale and Oil Sands Development (March, 2010)« less

The Mid-Cretaceous Frontier Formation near the Moxa Arch, southwestern Wyoming

USGS Publications Warehouse

Mereweather, E.A.; Blackmon, P.D.; Webb, J.C.

1984-01-01

The Frontier Formation in the Green River Basin of Wyoming, Utah, and Colorado, consists of sandstone, siltstone, and shale, and minor conglomerate, coal, and bentonite. These strata were deposited in several marine and nonmarine environments during early Late Cretaceous time. At north-trending outcrops along the eastern edge of the overthrust belt, the Frontier is of Cenomanian, Turonian, and early Coniacian age, and commonly is about 610 m (2,000 ft) thick. The formation in that area conformably overlies the Lower Cretaceous Aspen Shale and is divided into the following members, in ascending order: Chalk Creek, Coalville, Allen Hollow, Oyster Ridge Sandstone, and Dry Hollow. In west-trending outcrops on the northern flank of the Uinta Mountains in Utah, the Frontier is middle and late Turonian, and is about 60 m (200 ft) thick. These strata disconformably overlie the Lower Cretaceous Mowry Shale. In boreholes on the Moxa arch, the upper part of the Frontier is of middle Turonian to early Coniacian age and unconformably overlies the lower part of the formation, which is early Cenomanian at the south end and probably Cenomanian to early Turonian at the north end. The Frontier on the arch thickens northward from less than 100 m (328 ft) to more than 300 m (984 ft) and conformably overlies the Mowry. The marine and nonmarine Frontier near the Uinta Mountains, marine and mnmarine beds in the upper part of the formation on the Moxa arch and the largely nonmarine Dry Hollow Member at the top of the Frontier in the overthrust belt are similar in age. Older strata in the formation, which are represented by the disconformable basal contact of the Frontier near the Uinta Mountains, thicken northward along the Moxa arch and westward between the arch and the overthrust belt. The large changes in thickness of the Frontier in the Green River Basin were caused mainly by differential uplift and truncation of the lower part of the formation during the early to middle Turonian and by the shoreward addition of progressively younger sandstone units at the top of the formation during the late Turonian and early Coniacian. The sandstone in cores of the Frontier, from boreholes on the Moxa arch and the northern plunge of the Rock Springs uplift, consists of very fine grained and fine-grained litharenites and sublitharenites that were deposited in deltaic and shallow-water marine environments. These rocks consist mainly of quartz, chert, rock fragments, mixed-layer illite-smectite, mica-illite, and chlorite. Samples of the sandstone have porosities of 4.7 to 23.0 percent and permeabilities of 0.14 to 6.80 millidarcies, and seem to represent poor to fair reservoir beds for oil and gas. The shale in cores of the Frontier Formation and the overlying basal Hilliard Shale, from the Moxa arch, Rock Springs uplift, and overthrust belt, was deposited in deltaic and offshore-marine environments. Samples of the shale are composed largely of quartz, micaillite, mixed-layer illite-smectite, kaolin, and chlorite. They also contain from 0.27 to 4.42 percent organic carbon, in humic and sapropelic organic matter. Most of the sampled shale units are thermally mature, in terms of oil generation, and a few probably are source rocks for oil and gas.

Cracking mechanism of shale cracks during fracturing

NASA Astrophysics Data System (ADS)

Zhao, X. J.; Zhan, Q.; Fan, H.; Zhao, H. B.; An, F. J.

2018-06-01

In this paper, we set up a model for calculating the shale fracture pressure on the basis of Huang’s model by the theory of elastic-plastic mechanics, rock mechanics and the application of the maximum tensile stress criterion, which takes into account such factors as the crustal stress field, chemical field, temperature field, tectonic stress field, the porosity of shale and seepage of drilling fluid and so on. Combined with the experimental data of field fracturing and the experimental results of three axis compression of shale core with different water contents, the results show that the error between the present study and the measured value is 3.85%, so the present study can provide technical support for drilling engineering.

Experimental investigation of the role of rock fabric in gas generation and expulsion during thermal maturation: Anhydrous closed-system pyrolysis of a bitumen-rich Eagle Ford Shale

USGS Publications Warehouse

Shao, Deyong; Ellis, Geoffrey S.; Li, Yanfang; Zhang, Tongwei

2018-01-01

Gold-tube pyrolysis experiments were conducted on miniature core plugs and powdered rock from a bitumen-rich sample of Eagle Ford Shale to investigate the role of rock fabric in gas generation and expulsion during thermal maturation. The samples were isothermally heated at 130, 300, 310, 333, 367, 400, and 425 °C for 72 h under a confining pressure of 68.0 MPa, corresponding to six levels of induced thermal maturity: pre-oil generation (130 °C/72 h), incipient oil/bitumen generation (300 and 310 °C/72 h), early oil generation (333 °C/72 h), peak oil generation (367 °C/72 h), early oil cracking (400 °C/72 h), and late oil cracking (425 °C/72 h). Experimental results show that gas retention coupled with compositional fractionation occurs in the core plug experiments and varies as a function of thermal maturity. During the incipient oil/bitumen generation stage, yields of methane through pentane (C1–C5) from core plugs are significantly lower than those from rock powder, and gases from core plugs are enriched in methane. However, the differences in C1–C5 gas yield and composition decrease throughout the oil generation stage, and by the oil cracking stage no obvious compositional difference in C1–C5 gases exists. The decrease in the effect of rock fabric on gas yield and composition with increasing maturity is the result of an increase in gas expulsion efficiency. Pyrolysis of rock powder yields 4–16 times more CO2 compared to miniature core plugs, with δ13CCO2 values ranging from −2.9‰ to −0.6‰, likely due to carbonate decomposition accelerated by reactions with organic acids. Furthermore, lower yields of gaseous alkenes and H2 from core plug experiments sugge

Characterization of oil shale, isolated kerogen, and post-pyrolysis residues using advanced 13 solid-state nuclear magnetic resonance spectroscopy

USGS Publications Warehouse

Cao, Xiaoyan; Birdwell, Justin E.; Chappell, Mark A.; Li, Yuan; Pignatello, Joseph J.; Mao, Jingdong

2013-01-01

Characterization of oil shale kerogen and organic residues remaining in postpyrolysis spent shale is critical to the understanding of the oil generation process and approaches to dealing with issues related to spent shale. The chemical structure of organic matter in raw oil shale and spent shale samples was examined in this study using advanced solid-state 13C nuclear magnetic resonance (NMR) spectroscopy. Oil shale was collected from Mahogany zone outcrops in the Piceance Basin. Five samples were analyzed: (1) raw oil shale, (2) isolated kerogen, (3) oil shale extracted with chloroform, (4) oil shale retorted in an open system at 500°C to mimic surface retorting, and (5) oil shale retorted in a closed system at 360°C to simulate in-situ retorting. The NMR methods applied included quantitative direct polarization with magic-angle spinning at 13 kHz, cross polarization with total sideband suppression, dipolar dephasing, CHn selection, 13C chemical shift anisotropy filtering, and 1H-13C long-range recoupled dipolar dephasing. The NMR results showed that, relative to the raw oil shale, (1) bitumen extraction and kerogen isolation by demineralization removed some oxygen-containing and alkyl moieties; (2) unpyrolyzed samples had low aromatic condensation; (3) oil shale pyrolysis removed aliphatic moieties, leaving behind residues enriched in aromatic carbon; and (4) oil shale retorted in an open system at 500°C contained larger aromatic clusters and more protonated aromatic moieties than oil shale retorted in a closed system at 360°C, which contained more total aromatic carbon with a wide range of cluster sizes.

Identifying water-quality trends in the Trinity River, Texas, USA, 1969-1992, using sediment cores from Lake Livingston

USGS Publications Warehouse

Van Metre, P.C.; Callender, E.

1996-01-01

Chemical analyses were done on cores of bottom sediment from three locations in Lake Livingston, a reservoir on the Trinity River in east Texas to identify trends in water quality in the Trinity River using the chemical record preserved in bottom sediments trapped by the reservoir. Sediment cores spanned the period from 1969, when the reservoir was impounded, to 1992, when the cores were collected. Chemical concentrations in reservoir sediment samples were compared to concentrations for 14 streambed sediment samples from the Trinity River Basin and to reported concentrations for soils in the eastern United States and shale. These comparisons indicate that sediments deposited in Lake Livingston are representative of the environmental setting of Lake Livingston within the Trinity River Basin. Vertical changes in concentrations within sediment cores indicate temporal trends of decreasing concentrations of lead, sodium, barium, and total DDT (DDT plus its metabolites DDD and DDE) in the Trinity River. Possible increasing temporal trends are indicated for chlordane and dieldrin. Each sediment-derived trend is related to trends in water quality in the Trinity River or known changes in environmental factors in its drainage basin or both.

The variation of molybdenum isotopes within the weathering system of the black shales

NASA Astrophysics Data System (ADS)

Jianming, Z.

2016-12-01

Jian-Ming Zhu 1,2, De-Can Tan 2, Liang Liang 2, Wang Jing21 State Key Laboratory of Geological Processes and Mineral Resources, China University of Geosciences, Beijing, 100083, China 2 State Key Laboratory of Environmental Geochemistry, Institute of Geochemistry, Chinese Academy of Sciences, Guiyang, 550002, China Molybdenum (Mo) stable isotopes have been developed as a tracer to indicate the evolution of the atmospheric and oceanic oxygenation related with continent weathering, and to reveal the extent of ancient oceanic euxinia. Molybdenum isotopic variation within the weathering system of basalts has been studied, and was presented the whole trend with heavier isotopes preferentially removed during weathering processes. However, there are few researches to study the variation of Mo isotopes during black shale weathering, especiall on the behavoir of Mo isotopes within the perfect shales' profiles. Here, the weathering profiles of Mo and selenium(Se)-rich carbonaceous rocks in Enshi southwest Hubei Province were selected. The Mo isotopes was measured on Nu Plasma II's MC-ICP-MS using 97Mo-100Mo double spike, and δ98/95Mo was reported relative to NIST 3134. A comprehensive set of Mo isotopic composition and concentration data from the unweathered, weakly and intensely weathered rocks were collected. The δ98/95Mo in fresh shales (220±248 mg/kg Mo, 1SD, n=41) from Shadi and Yutangba drill cores varies from 0.41‰ to 0.99‰ with an average of 0.67±0.16‰, while the strongly weathered shales (19.9±5.8 mg/kg Mo, 1SD, n=5) from Shadi profiles are isotopically heavier with average δ98/95Mo values of 1.03±0.10‰ (1SD, n=5). The Locally altered shales exposed in a quarry at Yutangba are highly enriched in Mo, varing from 31 to 2377 mg/kg with an average of 428 ±605mg/kg (1SD, n=24), approximately 2 times greater than that in fresh shales samples. These rocks are presented a significant variation in δ98/95Mo values varing from -0.24 ‰ to -3.99 ‰ with average -1.67±1.57‰, showing the extremely negative δ98/95Mo values existed in natural samples. This suggested that Mo isotopes can be fractionated during shales weathering processes, with lighter isotopes preferentially removed. This finding is in contrast to the previous knowledge from basalt weathering, and requires further study.

Geology of the Devonian Marcellus Shale--Valley and Ridge province, Virginia and West Virginia--a field trip guidebook for the American Association of Petroleum Geologists Eastern Section Meeting, September 28-29, 2011

USGS Publications Warehouse

Enomoto, Catherine B.; Coleman, James L.; Haynes, John T.; Whitmeyer, Steven J.; McDowell, Ronald R.; Lewis, J. Eric; Spear, Tyler P.; Swezey, Christopher S.

2012-01-01

Detailed and reconnaissance field mapping and the results of geochemical and mineralogical analyses of outcrop samples indicate that the Devonian shales of the Broadtop Synclinorium from central Virginia to southern Pennsylvania have an organic content sufficiently high and a thermal maturity sufficiently moderate to be considered for a shale gas play. The organically rich Middle Devonian Marcellus Shale is present throughout most of the synclinorium, being absent only where it has been eroded from the crests of anticlines. Geochemical analyses of outcrop and well samples indicate that hydrocarbons have been generated and expelled from the kerogen originally in place in the shale. The mineralogical characteristics of the Marcellus Shale samples from the Broadtop Synclinorium are slightly different from the averages of samples from New York, Pennsylvania, northeast Ohio, and northern West Virginia. The Middle Devonian shale interval is moderately to heavily fractured in all areas, but in some areas substantial fault shearing has removed a regular "cleat" system of fractures. Conventional anticlinal gas fields in the study area that are productive from the Lower Devonian Oriskany Sandstone suggest that a continuous shale gas system may be in place within the Marcellus Shale interval at least in a portion of the synclinorium. Third-order intraformational deformation is evident within the Marcellus shale exposures. Correlations between outcrops and geophysical logs from exploration wells nearby will be examined by field trip attendees.

Organic-rich shale lithofacies geophysical prediction: A case study in the fifth organic-matter-rich interval of Paleogene Hetaoyuan Formation, Biyang Depression

NASA Astrophysics Data System (ADS)

Fei, S.; Xinong, X.

2017-12-01

The fifth organic-matter-rich interval (ORI 5) in the He-third Member of the Paleogene Hetaoyuan Formation is believed to be the main exploration target for shale oil in Biyang Depression, eastern China. An important part of successful explorating and producing shale oil is to identify and predict organic-rich shale lithofacies with different reservoir capacities and rock geomechanical properties, which are related to organic matter content and mineral components. In this study, shale lithofacies are defined by core analysis data, well-logging and seismic data, and the spatial-temporal distribution of various lithologies are predicted qualitatively by seismic attribute technology and quantitatively by geostatistical inversion analysis, and the prediction results are confirmed by the logging data and geological background. ORI 5 is present in lacustrine expanding system tract and can be further divided into four parasequence sets based on the analysis of conventional logs, TOC content and wavelet transform. Calcareous shale, dolomitic shale, argillaceous shale, silty shale and muddy siltstone are defined within ORI 5, and can be separated and predicted in regional-scale by root mean square amplitude (RMS) analysis and wave impedance. The results indicate that in the early expansion system tract, dolomitic shale and calcareous shale widely developed in the study area, and argillaceous shale, silty shale, and muddy siltstone only developed in periphery of deep depression. With the lake level rising, argillaceous shale and calcareous shale are well developed, and argillaceous shale interbeded with silty shale or muddy siltstone developed in deep or semi-deep lake. In the late expansion system tract, argillaceous shale is widely deposited in the deepest depression, calcareous shale presented band distribution in the east of the depression. Actual test results indicate that these methods are feasible to predict the spatial distribution of shale lithofacies.

Enrichment Of Volcanogenic Trace Elements, Co, Cr, Cu, Ni, Mo And Zr In A Continuous Subsurface Eagle Ford Core In South Texas And Origin Of The Oceanic Anoxic Event II At The Cenomanian-Turonian (C/T) Boundary

NASA Astrophysics Data System (ADS)

Valencia, D.; Basu, A. R.; Loocke, M. P.

2017-12-01

The Eagle Ford Formation containing the Cenomanian-Turonian (C/T) boundary continues to be studied globally not only for its economic potential and analog for `frack-able' unconventional organic-rich formations, but it is of particular interest to researchers because it was deposited across the C/T boundary recording an Oceanic Anoxic Event (OAE2). OAEs are short lived episodes (< 1Ma) of widespread marine anoxia during which large amounts of organic carbon were buried on the ocean floor under oxygen-deficient bottom waters. The exact trigger for the increased deposition of organic matter into the sedimentary record remains enigmatic. Geochemical and geochronological analysis of a subsurface 300ft long continuous core of the Eagle Ford Formation of South Texas shows evidence for volcanism throughout. This is confirmed by multiple thin intermittent bentonite beds. The whole rock black shale (marl) shows elevated concentrations of volcanogenic trace elements (Co, Cr, Cu, Ni, Mo and Zn) throughout the core. By sampling bentonite bed zircons near the inferred C/T boundary, U-Pb age of 93.2 ±1.7 Ma for the Eagle Ford is established. Using this horizon, the onset of OAE2 is constrained and well-correlated with the positive δ13C excursion. For the trace element analysis, the core was sampled at 10ft intervals for ICP-MS. The analytical results show significantly increased volcanogenic trace metal input correlating with increased Total Organic Carbon and positive δ13C values at the C/T dated zircon horizon. OAE2, defined by the positive δ13C excursion, was found to span over an interval of 85ft. With a definitive constraint for OAE2 established, this well-defined interval was analyzed at a much higher resolution using ED-XRF. The core was then sampled at 6' intervals throughout the C/T boundary at OAE2. The high-resolution sampling of the core shows 80-99% increase in abundance of Co, Cr, Cu, Ni, Mo, Zn over the average Post Australian Archean Shale(PAAS), representative of average continental crust. These volcanogenic-rich intervals reach peak values before the onset of OAE2 and at the maximum values for the positive δ13C isotope excursion directly after the 93.2 ±1.7 Ma bentonite bed. This continuous vertical extent of data set supports volcanic origin resulted in organic matter deposition and subsequent anoxia.

A comparative study of removal of fluoride from contaminated water using shale collected from different coal mines in India.

PubMed

Biswas, Gargi; Dutta, Manjari; Dutta, Susmita; Adhikari, Kalyan

2016-05-01

Low-cost water defluoridation technique is one of the most important issues throughout the world. In the present study, shale, a coal mine waste, is employed as novel and low-cost adsorbent to abate fluoride from simulated solution. Shale samples were collected from Mahabir colliery (MBS) and Sonepur Bazari colliery (SBS) of Raniganj coalfield in West Bengal, India, and used to remove fluoride. To increase the adsorption efficiency, shale samples were heat activated at a higher temperature and samples obtained at 550 °C are denoted as heat-activated Mahabir colliery shale (HAMBS550) and heat-activated Sonepur Bazari colliery shale (HASBS550), respectively. To prove the fluoride adsorption onto different shale samples and ascertain its mechanism, natural shale samples, heat-activated shale samples, and their fluoride-loaded forms were characterized using scanning electron microscopy, energy dispersive X-ray analysis, X-ray diffraction study, and Fourier transform infrared spectroscopy. The effect of different parameters such as pH, adsorbent dose, size of particles, and initial concentration of fluoride was investigated during fluoride removal in a batch contactor. Lower pH shows better adsorption in batch study, but it is acidic in nature and not suitable for direct consumption. However, increase of pH of the solution from 3.2 to 6.8 and 7.2 during fluoride removal process with HAMBS550 and HASBS550, respectively, confirms the applicability of the treated water for domestic purposes. HAMBS550 and HASBS550 show maximum removal of 88.3 and 88.5 %, respectively, at initial fluoride concentration of 10 mg/L, pH 3, and adsorbent dose of 70 g/L.

Element mobilization from Bakken shales as a function of water chemistry.

PubMed

Wang, Lin; Burns, Scott; Giammar, Daniel E; Fortner, John D

2016-04-01

Waters that return to the surface after injection of a hydraulic fracturing fluid for gas and oil production contain elements, including regulated metals and metalloids, which are mobilized through interactions between the fracturing fluid and the shale formation. The rate and extent of mobilization depends on the geochemistry of the formation and the chemical characteristics of the fracturing fluid. In this work, laboratory scale experiments investigated the influence of water chemistry on element mobilization from core samples taken from the Bakken formation, one of the most productive shale oil plays in the US. Fluid properties were systematically varied and evaluated with regard to pH, oxidant level, solid:water ratio, temperature, and chemical additives. Element mobilization strongly depended on solution pH and redox conditions and to a lesser extent on the temperature and solid:water ratio. The presence of oxygen and addition of hydrogen peroxide or ammonium persulfate led to pyrite oxidation, resulting in elevated sulfate concentrations. Further, depending on the mineral carbonates available to buffer the system pH, pyrite oxidation could lower the system pH and enhance the mobility of several metals and metalloids. Copyright © 2016 Elsevier Ltd. All rights reserved.

Variations in petrophysical properties of shales along a stratigraphic section in the Whitby mudstone (UK)

NASA Astrophysics Data System (ADS)

Barnhoorn, Auke; Houben, Maartje; Lie-A-Fat, Joella; Ravestein, Thomas; Drury, Martyn

2015-04-01

In unconventional tough gas reservoirs (e.g. tight sandstones or shales) the presence of fractures, either naturally formed or hydraulically induced, is almost always a prerequisite for hydrocarbon productivity to be economically viable. One of the formations classified so far as a potential interesting formation for shale gas exploration in the Netherlands is the Lower Jurassic Posidonia Shale Formation (PSF). However data of the Posidonia Shale Formation is scarce so far and samples are hard to come by, especially on the variability and heterogeneity of the petrophysical parameters of this shale little is known. Therefore research and sample collection is conducted on a time and depositional analogue of the PSF: the Whitby Mudstone Formation (WMF) in the United Kingdom. A large number of samples along a ~7m stratigraphic section of the Whitby Mudstone Formation have been collected and analysed. Standard petrophysical properties such as porosity and matrix densities are quantified for a number of samples throughout the section, as well as mineral composition analysis based on XRD/XRF and SEM analyses. Seismic velocity measurements are also conducted at multiple heights in the section and in multiple directions to elaborate on anisotropy of the material. Attenuation anisotropy is incorporated as well as Thomsen's parameters combined with elastic parameters, e.g. Young's modulus and Poisson's ratio, to quantify the elastic anisotropy. Furthermore rock mechanical experiments are conducted to determine the elastic constants, rock strength, fracture characteristics, brittleness index, fraccability and rock mechanical anisotropy across the stratigraphic section of the Whitby mudstone formation. Results show that the WMF is highly anisotropic and it exhibits an anisotropy on the large limit of anisotropy reported for US gas shales. The high anisotropy of the Whitby shales has an even larger control on the formation of the fracture network. Furthermore, most petrophysical properties are highly variable. They vary per sample, but even within a sample on a mm-scale, large variations in e.g. the porosity occur. These relatively large variations influence the potential for future shale gas exploration for these Lower Jurassic shales in northern Europe and need to be quantified in detail beforehand. Compositional analyses and rock deformation experiments on the first samples indicate relatively low brittleness indices for the Whitby shale, but variation of these parameters within the stratigraphy are present. All petrophysical analyses combined will provide a complete assessment of the potential for shale gas exploration of these Lower Jurassic shales.

Borehole petrophysical chemostratigraphy of Pennsylvanian black shales in the Kansas subsurface

USGS Publications Warehouse

Doveton, J.H.; Merriam, D.F.

2004-01-01

Pennsylvanian black shales in Kansas have been studied on outcrop for decades as the core unit of the classic Midcontinent cyclothem. These shales appear to be highstand condensed sections in the sequence stratigraphic paradigm. Nuclear log suites provide several petrophysical measurements of rock chemistry that are a useful data source for chemostratigraphic studies of Pennsylvanian black shales in the subsurface. Spectral gamma-ray logs partition natural radioactivity between contributions by U, Th, and K sources. Elevated U contents in black shales can be related to reducing depositional environments, whereas the K and Th contents are indicators of clay-mineral abundance and composition. The photoelectric factor log measurement is a direct function of aggregate atomic number and so is affected by clay-mineral volume, clay-mineral iron content, and other black shale compositional elements. Neutron porosity curves are primarily a response to hydrogen content. Although good quality logs are available for many black shales, borehole washout features invalidate readings from the nuclear contact devices, whereas black shales thinner than tool resolution will be averaged with adjacent beds. Statistical analysis of nuclear log data between black shales in successive cyclothems allows systematic patterns of their chemical and petrophysical properties to be discriminated in both space and time. ?? 2004 Elsevier B.V. All rights reserved.

Permeability evolution of shale during spontaneous imbibition

DOE Office of Scientific and Technical Information (OSTI.GOV)

Chakraborty, N.; Karpyn, Z. T.; Liu, S.

Shales have small pore and throat sizes ranging from nano to micron scales, low porosity and limited permeability. The poor permeability and complex pore connectivity of shales pose technical challenges to (a) understanding flow and transport mechanisms in such systems and, (b) in predicting permeability changes under dynamic saturation conditions. This paper presents quantitative experimental evidence of the migration of water through a generic shale core plug using micro CT imaging. In addition, in-situ measurements of gas permeability were performed during counter-current spontaneous imbibition of water in nano-darcy permeability Marcellus and Haynesville core plugs. It was seen that water blocksmore » severely reduced the effective permeability of the core plugs, leading to losses of up to 99.5% of the initial permeability in experiments lasting 30 days. There was also evidence of clay swelling which further hindered gas flow. When results from this study were compared with similar counter-current gas permeability experiments reported in the literature, the initial (base) permeability of the rock was found to be a key factor in determining the time evolution of effective gas permeability during spontaneous imbibition. With time, a recovery of effective permeability was seen in the higher permeability rocks, while becoming progressively detrimental and irreversible in tighter rocks. Finally, these results suggest that matrix permeability of ultra-tight rocks is susceptible to water damage following hydraulic fracturing stimulation and, while shut-in/soaking time helps clearing-up fractures from resident fluid, its effect on the adjacent matrix permeability could be detrimental.« less

Permeability evolution of shale during spontaneous imbibition

DOE PAGES

Chakraborty, N.; Karpyn, Z. T.; Liu, S.; ...

2017-01-05

Shales have small pore and throat sizes ranging from nano to micron scales, low porosity and limited permeability. The poor permeability and complex pore connectivity of shales pose technical challenges to (a) understanding flow and transport mechanisms in such systems and, (b) in predicting permeability changes under dynamic saturation conditions. This paper presents quantitative experimental evidence of the migration of water through a generic shale core plug using micro CT imaging. In addition, in-situ measurements of gas permeability were performed during counter-current spontaneous imbibition of water in nano-darcy permeability Marcellus and Haynesville core plugs. It was seen that water blocksmore » severely reduced the effective permeability of the core plugs, leading to losses of up to 99.5% of the initial permeability in experiments lasting 30 days. There was also evidence of clay swelling which further hindered gas flow. When results from this study were compared with similar counter-current gas permeability experiments reported in the literature, the initial (base) permeability of the rock was found to be a key factor in determining the time evolution of effective gas permeability during spontaneous imbibition. With time, a recovery of effective permeability was seen in the higher permeability rocks, while becoming progressively detrimental and irreversible in tighter rocks. Finally, these results suggest that matrix permeability of ultra-tight rocks is susceptible to water damage following hydraulic fracturing stimulation and, while shut-in/soaking time helps clearing-up fractures from resident fluid, its effect on the adjacent matrix permeability could be detrimental.« less

Talaromyces sayulitensis, Acidiella bohemica and Penicillium citrinum in Brazilian oil shale by-products.

PubMed

de Goes, Kelly C G P; da Silva, Josué J; Lovato, Gisele M; Iamanaka, Beatriz T; Massi, Fernanda P; Andrade, Diva S

2017-12-01

Fine shale particles and retorted shale are waste products generated during the oil shale retorting process. These by-products are small fragments of mined shale rock, are high in silicon and also contain organic matter, micronutrients, hydrocarbons and other elements. The aims of this study were to isolate and to evaluate fungal diversity present in fine shale particles and retorted shale samples collected at the Schist Industrialization Business Unit (Six)-Petrobras in São Mateus do Sul, State of Paraná, Brazil. Combining morphology and internal transcribed spacer (ITS) sequence, a total of seven fungal genera were identified, including Acidiella, Aspergillus, Cladosporium, Ochroconis, Penicillium, Talaromyces and Trichoderma. Acidiella was the most predominant genus found in the samples of fine shale particles, which are a highly acidic substrate (pH 2.4-3.6), while Talaromyces was the main genus in retorted shale (pH 5.20-6.20). Talaromyces sayulitensis was the species most frequently found in retorted shale, and Acidiella bohemica in fine shale particles. The presence of T. sayulitensis, T. diversus and T. stolli in oil shale is described herein for the first time. In conclusion, we have described for the first time a snapshot of the diversity of filamentous fungi colonizing solid oil shale by-products from the Irati Formation in Brazil.

Experimental investigation on the fracture behaviour of black shale by acoustic emission monitoring and CT image analysis during uniaxial compression

NASA Astrophysics Data System (ADS)

Wang, Y.; Li, C. H.; Hu, Y. Z.

2018-04-01

Plenty of mechanical experiments have been done to investigate the deformation and failure characteristics of shale; however, the anisotropic failure mechanism has not been well studied. Here, laboratory Uniaxial Compressive Strength tests on cylindrical shale samples obtained by drilling at different inclinations to bedding plane were performed. The failure behaviours of the shale samples were studied by real-time acoustic emission (AE) monitoring and post-test X-ray computer tomography (CT) analysis. The experimental results suggest that the pronounced bedding planes of shale have a great influence on the mechanical properties and AE patterns. The AE counts and AE cumulative energy release curves clearly demonstrate different morphology, and the `U'-shaped curve relationship between the AE counts, AE cumulative energy release and bedding inclination was first documented. The post-test CT image analysis shows the crack patterns via 2-D image reconstructions, an index of stimulated fracture density is defined to represent the anisotropic failure mode of shale. What is more, the most striking finding is that the AE monitoring results are in good agreement with the CT analysis. The structural difference in the shale sample is the controlling factor resulting in the anisotropy of AE patterns. The pronounced bedding structure in the shale formation results in an anisotropy of elasticity, strength and AE information from which the changes in strength dominate the entire failure pattern of the shale samples.

Sea Level and Paleoenvironment Control on Late Ordovician Source Rocks, Hudson Bay Basin, Canada

NASA Astrophysics Data System (ADS)

Zhang, S.; Hefter, J.

2009-05-01

Hudson Bay Basin is one of the largest Paleozoic sedimentary basins in North America, with Southampton Island on its north margin. The lower part of the basin succession comprises approximately 180 to 300 m of Upper Ordovician strata including Bad Cache Rapids and Churchill River groups and Red Head Rapids Formation. These units mainly comprise carbonate rocks consisting of alternating fossiliferous limestone, evaporitic and reefal dolostone, and minor shale. Shale units containing extremely high TOC, and interpreted to have potential as petroleum source rocks, were found at three levels in the lower Red Head Rapids Formation on Southampton Island, and were also recognized in exploration wells from the Hudson Bay offshore area. A study of conodonts from 390 conodont-bearing samples from continuous cores and well cuttings from six exploration wells in the Hudson Bay Lowlands and offshore area (Comeault Province No. 1, Kaskattama Province No. 1, Pen Island No. 1, Walrus A-71, Polar Bear C-11 and Narwhal South O-58), and about 250 conodont-bearing samples collected from outcrops on Southampton Island allows recognition of three conodont zones in the Upper Ordovician sequence, namely (in ascendant sequence) Belodina confluens, Amorphognathus ordovicicus, and Rhipidognathus symmetricus zones. The three conodont zones suggest a cycle of sea level changes of rising, reaching the highest level, and then falling during the Late Ordovician. Three intervals of petroleum potential source rock are within the Rhipidognathus symmetricus Zone in Red Head Rapids Formation, and formed in a restricted anoxic and hypersaline condition during a period of sea level falling. This is supported by the following data: 1) The conodont Rhipidognathus symmetricus represents the shallowest Late Ordovician conodont biofacies and very shallow subtidal to intertidal and hypersaline condition. This species has the greatest richness within the three oil shale intervals to compare other parts of Red Head Rapids Formation. 2) Type I kerogen is normally formed in quiet, oxygen-deficient, shallow water environment. Rock-Eval6 data from 40 samples of the three oil shale intervals, collected from outcrops on Southampton Island, demonstrate that the proportion of Type I kerogen gradually increases in the mixed Type I-Type II kerogen from the lower to upper oil shale intervals. 3) Pristane/phytane ratio can be used as a paleoenvironment indicator. The low ratios in the three oil shale intervals range from 0.5 to 0.9 and indicate anoxic and hypersaline conditions. In addition, the presence of isorenieratene derivatives from green phototrophic sulfur bacteria (Chlorobiaceae), with highest relative concentrations in the lower oil shale intervals, points to anoxia reaching into the photic zone of the water column.

Research on the equivalence between digital core and rock physics models

NASA Astrophysics Data System (ADS)

Yin, Xingyao; Zheng, Ying; Zong, Zhaoyun

2017-06-01

In this paper, we calculate the elastic modulus of 3D digital cores using the finite element method, systematically study the equivalence between the digital core model and various rock physics models, and carefully analyze the conditions of the equivalence relationships. The influences of the pore aspect ratio and consolidation coefficient on the equivalence relationships are also further refined. Theoretical analysis indicates that the finite element simulation based on the digital core is equivalent to the boundary theory and Gassmann model. For pure sandstones, effective medium theory models (SCA and DEM) and the digital core models are equivalent in cases when the pore aspect ratio is within a certain range, and dry frame models (Nur and Pride model) and the digital core model are equivalent in cases when the consolidation coefficient is a specific value. According to the equivalence relationships, the comparison of the elastic modulus results of the effective medium theory and digital rock physics is an effective approach for predicting the pore aspect ratio. Furthermore, the traditional digital core models with two components (pores and matrix) are extended to multiple minerals to more precisely characterize the features and mineral compositions of rocks in underground reservoirs. This paper studies the effects of shale content on the elastic modulus in shaly sandstones. When structural shale is present in the sandstone, the elastic modulus of the digital cores are in a reasonable agreement with the DEM model. However, when dispersed shale is present in the sandstone, the Hill model cannot describe the changes in the stiffness of the pore space precisely. Digital rock physics describes the rock features such as pore aspect ratio, consolidation coefficient and rock stiffness. Therefore, digital core technology can, to some extent, replace the theoretical rock physics models because the results are more accurate than those of the theoretical models.

The organic geochemical characterization: An indication of type of kerogen and maturity of early - Mid Jurassic shale in the Blue Nile formation

NASA Astrophysics Data System (ADS)

Shoieba, Monera Adam; Sum, Chow Weng; Abidin, Nor Syazwani Zainal; Bhattachary, Swapan Kumar

2018-06-01

The heterogeneity and complexity of shale gas has become clear as the development of unconventional resources have improved. The Blue Nile Basin, is one of the many Mesozoic rift basins in Sudan associated with the Central African Rift System (CARS). It is located in the eastern part of the Republic of Sudan and has been the major focus for shale gas exploration due to the hydrocarbon found in the basin. But so far no success of discovery has been achieved because the shale gas potentiality of the study area is still unknown. The objective of this study is to assess the type of kerogen and maturity of the shale samples from the Blue Nile Formation within the Blue Nile Basin. This was done by employing organic geochemical methods such as pyrolysis gas chromatography (Py-GC) and petrographic analysis such as vitrinite reflectance (Ro%). Ten representative shale samples from TW-1 well in the Blue Nile Formation have been used to assess the quality of the source rock. Pyrolysis GC analysis indicate that all the selected shale samples contain Type II kerogen that produces oil and gas. The Blue Nile Formation possesses vitrinite reflectance (Ro%) of 0.60-0.65%, indicating that the shale samples are mature in the oil window.

Improved Characterization and Modeling of Tight Oil Formations for CO 2 Enhanced Oil Recovery Potential and Storage Capacity Estimation

DOE Office of Scientific and Technical Information (OSTI.GOV)

Sorensen, James; Smith, Steven; Kurz, Bethany

Tight oil formations such as those in the Bakken petroleum system are known to hold hundreds of billions of barrels of oil in place; however, the primary recovery factor for these plays is typically less than 10%. Tight oil formations, including the Bakken Formation, therefore, may be attractive candidates for enhanced oil recovery (EOR) using CO 2. Multiphase fluid behavior and flow in fluid-rich shales can vary substantially depending on the size of pore throats, and properties such as fluid viscosity and density are much different in nanoscale pores than in macroscale pores. Thus it is critical to understand themore » nature and distribution of nano-, micro-, and macroscale pores and fracture networks. To address these issues, the Energy & Environmental Research Center (EERC) has been conducting a research program entitled “Improved Characterization and Modeling of Tight Oil Formations for CO 2 Enhanced Oil Recovery Potential and Storage Capacity Estimation.” The objectives of the project are 1) the use of advanced characterization methods to better understand and quantify the petrophysical and geomechanical factors that control CO 2 and oil mobility within tight oil formation samples, 2) the determination of CO 2 permeation and oil extraction rates in tight reservoir rocks and organic-rich shales of the Bakken, and 3) the integration of the laboratory-based CO 2 permeation and oil extraction data and the characterization data into geologic models and dynamic simulations to develop predictions of CO 2 storage resource and EOR in the Bakken tight oil formation. A combination of standard and advanced petrophysical characterization techniques were applied to characterize samples of Bakken Formation tight reservoir rock and shales from multiple wells. Techniques included advanced computer tomography (CT) imaging, scanning electron microscopy (SEM) techniques, whole-core and micro x-ray CT imaging, field emission (FE) SEM, and focused ion beam (FIB) SEM. Selected samples were also analyzed for geomechanical properties. X-ray CT imaging yielded information on the occurrence of fractures, bedding planes, fossils, and bioturbation in core, as well as data on bulk density and photoelectric factor logs, which were used to interpret porosity, organic content, and mineralogy. FESEM was used for characterization of nano- and microscale features, including nanoscale pore visualization and micropore and pore throat mineralogy. FIBSEM yielded micro- to nanoscale visualization of fracture networks, porosity and pore-size distribution, connected versus isolated porosity, and distribution of organics. Results from the characterization activities provide insight on nanoscale fracture properties, pore throat mineralogy and connectivity, rock matrix characteristics, mineralogy, and organic content. Laboratory experiments demonstrated that CO 2 can permeate the tight matrix of Bakken shale and nonshale reservoir samples and mobilize oil from those samples. Geologic models were created at scales ranging from the core plug to the reservoir, and dynamic simulations were conducted. The data from the characterization and laboratory-based activities were integrated into modeling research activities to determine the fundamental mechanisms controlling fluid transport in the Bakken, which support EOR scheme design and estimation of CO 2 storage potential in tight oil formations. Simulation results suggest a CO 2 storage resource estimate range of 169 million to 1.5 billion tonnes for the Bakken in North Dakota, possibly resulting in 1.8 billion to 16 billion barrels of incremental oil.« less

An integrated profile of natural fractures in gas-bearing shale complex (Pomerania, Poland): based on structural profiling of oriented core and borehole logging data.

NASA Astrophysics Data System (ADS)

Bobek, Kinga; Jarosiński, Marek; Stadtmuller, Marek; Pachytel, Radomir; Lis-Śledziona, Anita

2016-04-01

Natural fractures in gas-bearing shales has significant impact on reservoir stimulation and increase of exploitation. Density of natural fractures and their orientation in respect to the maximum horizontal stress are crucial for propagation of technological hydraulic fractures. Having access to continuous borehole core profile and modern geophysical logging from several wells in the Pomeranian part of the Early Paleozoic Baltic Basin (Poland) we were able to compare the consistency of structural interpretation of several data sets. Although, final aim of our research is to optimize the method of fracture network reconstruction on a reservoir scale, at a recent stage we were focused on quantitative characterization of tectonic structures in a direct vicinity of boreholes. The data we have, cover several hundred meters long profiles of boreholes from the Ordovician and Silurian shale complexes. Combining different sets of data we broaden the scale of observation from borehole core (5 cm radius), through XRMI scan of a borehole wall (10 cm radius), up to penetration of a signal of an acoustic dipole logging (several tens of cm range). At the borehole core we examined the natural tectonic structures and mechanically significant features, like: mineral veins, fractured veins, bare fractures, slickensides, fault zones, stylolites, bedding plane and mechanically contrasting layers. We have also noticed drilling-induced features like centerline fractures and core disking, controlled by a recent tectonic stress. We have measured the orientation of fractures, their size, aperture and spacing and also describe the character of veins and tried to determine the stress regime responsible for fault slippage and fracture propagation. Wide range of analyzed features allowed us to discriminate fracture sets and reconstruct tectonic evolution of the complex. The most typical for analyzed shale complexes are steep and vertical strata-bound fractures that create an orthogonal joint system, which is locally disturbed by small-scale faults and fractures, associated with them. For regular joints, observed on borehole core, we have calculated variation of mean height and area and volume of mineralization for veins. Fracture density variation reveals good correlation with lithological shale formations which are comparable with Consistent Mechanical Units differentiated based on detailed lithological profiling and geophysical data (see Pachytel et al., this issue).We have also proposed a new method of a rose diagram construction presenting strike of fractures taking into account their size and angular error bar in strike determination. Each fracture was weighted with its length or aperture and an angular error was included by blurring the less credible records. This allowed for more precise adjustment of fracture sets direction in comparison to conventional diagrams without weighting procedure. Recently, we are processing acoustic dipole logs for anisotropy analyses aiming in comparison with density of fracture sets. Our study, which is conducted in the frame of ShaleMech Project (within Blue Gas Program) is in progress, thus the presented results should be considered as preliminary.

Effects of processed oil shale on the element content of Atriplex cancescens

USGS Publications Warehouse

Anderson, B.M.

1982-01-01

Samples of four-wing saltbush were collected from the Colorado State University Intensive Oil Shale Revegetation Study Site test plots in the Piceance basin, Colorado. The test plots were constructed to evaluate the effects of processed oil shale geochemistry on plant growth using various thicknesses of soil cover over the processed shale and/or over a gravel barrier between the shale and soil. Generally, the thicker the soil cover, the less the influence of the shale geochemistry on the element concentrations in the plants. Concentrations of 20 elements were larger in the ash of four-wing saltbush growing on the plot with the gravel barrier (between the soil and processed shale) when compared to the sample from the control plot. A greater water content in the soil in this plot has been reported, and the interaction between the increased, percolating water and shale may have increased the availability of these elements for plant uptake. Concentrations of boron, copper, fluorine, lithium, molybdenum, selenium, silicon, and zinc were larger in the samples grown over processed shale, compared to those from the control plot, and concentrations for barium, calcium, lanthanum, niobium, phosphorus, and strontium were smaller. Concentrations for arsenic, boron, fluorine, molybdenum, and selenium-- considered to be potential toxic contaminants--were similar to results reported in the literature for vegetation from the test plots. The copper-to-molybdenum ratios in three of the four samples of four-wing saltbush growing over the processed shale were below the ratio of 2:1, which is judged detrimental to ruminants, particularly cattle. Boron concentrations averaged 140 ppm, well above the phytotoxicity level for most plant species. Arsenic, fluorine, and selenium concentrations were below toxic levels, and thus should not present any problem for revegetation or forage use at this time.

Understanding gas shales using inorganic, ternary geochemical systematics.

NASA Astrophysics Data System (ADS)

Basu, Sudeshna; Jones, Adrian; Verchovsky, Alexander

2016-04-01

We have developed a new approach of simultaneous analyses of carbon, nitrogen and noble gases, for isotopic and elemental compositions in bulk shales from different depths (11785 to 11909 feet) of a core from the Haynesville Bossier formation to decouple the different trapped components. This is preceded by major, minor and trace elemental analyses to understand their paleo productivity, tectonic and redox conditions of deposition as well as constraining their alteration and weathering. 5 to 10 mg of samples have been combusted from 200-1200°C in incremental steps of 100°C. Based on δ13C, we identify both marine+lacustrine (δ13C ~ -25 ‰, C/N ~ 5) and minor continental organic matter (δ13C ~ -27 ‰, C/N ~ 60) in the samples, in agreement with observations from elemental compositions. Extremely depleted δ13C of ≤ -34 ‰ in some temperature steps, can be attributed to methanogenesis. Two carbonate populations, primary (δ13C ~ 0 to 2 ‰) and diagenetic (δ13C ~ -13 to -11 ‰) can also be identified. We have been able to identify the multiple C components present in the samples, including very minor ones, without resorting to acid treatment. The bulk N δ15N values vary from -1.2to +6.4 ‰, but show a wide range from -15 to 15 ‰ within individual steps. By suitable modelling, we constrain the primary δ15N to be 5 to 8 ‰, identifiable in very high temperature steps of heating. This is possible if there is penetration of hot fluids that eliminates organic N along a reaction front leaving it fractionated, but leaves behind an unreacted core of residual nitrogen unaffected by isotopic fractionation (Boudou et al., 2008). Our study indicates that using bulk N values as primary signatures to constrain the redox conditions of deposition or thermal maturity of shales as is the practice, should be done with caution. Simultaneously obtained noble gases were used to constrain gas retention in the samples. Deviations of measured 4He/40Ar* (where 40Ar* represents radiogenic 40Ar after correcting for contribution from atmospheric Ar) from expected values has been used to monitor gas loss by degassing. Boudou, J., Schimmelmann, A., Ader, M., Mastalerz, M., Sebilo, M., Gengembre, L.,2008. Organic nitrogen chemistry during low grade metamorphism. Geochimica Cosmochimica Acta 72, 1199-1221.

[Effect of near infrared spectrum on the precision of PLS model for oil yield from oil shale].

PubMed

Wang, Zhi-Hong; Liu, Jie; Chen, Xiao-Chao; Sun, Yu-Yang; Yu, Yang; Lin, Jun

2012-10-01

It is impossible to use present measurement methods for the oil yield of oil shale to realize in-situ detection and these methods unable to meet the requirements of the oil shale resources exploration and exploitation. But in-situ oil yield analysis of oil shale can be achieved by the portable near infrared spectroscopy technique. There are different correlativities of NIR spectrum data formats and contents of sample components, and the different absorption specialities of sample components shows in different NIR spectral regions. So with the proportioning samples, the PLS modeling experiments were done by 3 formats (reflectance, absorbance and K-M function) and 4 regions of modeling spectrum, and the effect of NIR spectral format and region to the precision of PLS model for oil yield from oil shale was studied. The results show that the best data format is reflectance and the best modeling region is combination spectral range by PLS model method and proportioning samples. Therefore, the appropriate data format and the proper characteristic spectral region can increase the precision of PLS model for oil yield form oil shale.

Stratigraphy and depositional environments of the Lower Mississippian Joana Limestone in southern White Pine and northern Lincoln Counties, Nevada

DOE Office of Scientific and Technical Information (OSTI.GOV)

Gilmore, T.J.

1990-04-01

The Lower Mississippian Joana Limestone in the southern Schell Creek and Egan ranges of east-central Nevada is composed of three depositional facies: the unbedded wackestone with grainstone/packstone facies or Facies 1; the bedded wackestone with mudstone facies or Facies 2; and the restricted wackestone, mudstone/shale facies, or Facies 3. Facies 1 is characterized by Waulsortian-type carbonate buildups with massive unbedded wackestone cores, grainstone flanking beds and grainstone/packstone capping units. Facies 2 is characterized by an upward progression of sedimentary bedding types from thinly laminated to large scale trough cross-bedding that indicates a shoaling upward of this facies. Facies 3 ismore » characterized by sparse wackestones, mudstones, and shale which show a decrease in both faunal types and diversity and an increase in fine clastics. The restricted wackestone, mudstone/shale facies grades upward into the Mississippian Chainman Shale. The age of the Joana Limestone is confirmed as late Kinderhookian to early Osagean based primarily on conodonts and foraminifera. In the middle beds of the Joana Limestone, the previously unreported upper Siphonodella crenulata conodont zone occurs which helps correlate the Joana Limestone with regional transgressive/regressive sea level events. Color alteration indices of these conodonts are 1.5 to 2, and occur in the oil generation window. Additionally, oil staining was observed in numerous samples located primarily in the lower half of the formation, represented by Facies 3, the unbedded wackestone with grainstone/packstone facies.« less

Extraction of organic compounds from representative shales and the effect on porosity

DOE PAGES

DiStefano, Victoria H.; McFarlane, Joanna; Anovitz, Lawrence M.; ...

2016-09-01

This study is an attempt to understand how native organics are distributed with respect to pore size to determine the relationship between hydrocarbon chemistry and pore structure in shales, as the location and accessibility of hydrocarbons is key to understanding and improving the extractability of hydrocarbons in hydraulic fracturing. Selected shale cores from the Eagle Ford and Marcellus formations were subjected to pyrolysis gas chromatography (GC), thermogravimetric analysis, and organic solvent extraction with the resulting effluent analyzed by GC-mass spectrometry (MS). Organics representing the oil and gas fraction (0.1 to 1 wt. %) were observed by GC-MS. For most ofmore » the samples, the amount of native organic extracted directly related to the percentage of clay in the shale. The porosity and pore size distribution (0.95 nm to 1.35 m) in the Eagle Ford and Marcellus shales was measured before and after solvent extraction using small angle neutron scattering (SANS). An unconventional method was used to quantify the background from incoherent scattering as the Porod transformation obscures the Bragg peak from the clay minerals. Furthermore, the change in porosity from SANS is indicative of the extraction or breakdown of higher molecular weight bitumen with high C/H ratios (asphaltenes and resins). This is mostly likely attributed to complete dissolution or migration of asphaltenes and resins. These longer carbon chain lengths, C30-C40, were observed by pyrolysis GC, but either were too heavy to be analyzed in the extracts by GC-MS or were not effectively leached into the organic solvents. Thus, experimental limitations meant that the amount of extractable material could not be directly correlated to the changes in porosity measured by SANS. But, the observable porosity generally increased with solvent extraction. A decrease in porosity after extraction as observed in a shale with high clay content and low maturity was attributed to swelling of pores with solvent uptake or migration of resins and asphaltenes.« less

Minor-element composition and organic carbon content of marine and nonmarine shales of Late Cretaceous age in the western interior of the United States

USGS Publications Warehouse

Tourtelot, H.A.

1964-01-01

The composition of nonmarine shales of Cretaceous age that contain less than 1 per cent organic carbon is assumed to represent the inherited minor-element composition of clayey sediments delivered to the Cretaceous sea that occupied the western interior region of North America. Differences in minor-element content between these samples and samples of 1. (a) nonmarine carbonaceous shales (1 to 17 per cent organic carbon), 2. (b) nearshore marine shales (less than 1 per cent organic carbon), and 3. (c) offshore marine shales (as much as 8 per cent organic carbon), all of the same age, reveal certain aspects of the role played by clay minerals and organic materials in affecting the minor-element composition of the rocks. The organic carbon in the nonmarine rocks occurs in disseminated coaly plant remains. The organic carbon in the marine rocks occurs predominantly in humic material derived from terrestrial plants. The close similarity in composition between the organic isolates from the marine samples and low-rank coal suggests that the amount of marine organic material in these rocks is small. The minor-element content of the two kinds of nonmarine shales is the same despite the relatively large amount of organic carbon in the carbonaceous shales. The nearshore marine shales, however, contain larger median amounts of arsenic, boron, chromium, vanadium and zinc than do the nonmarine rocks; and the offshore marine shales contain even larger amounts of these elements. Cobalt, molybdenum, lead and zirconium show insignificant differences in median content between the nonmarine and marine rocks, although as much as 25 ppm molybdenum is present in some offshore marine samples. The gallium content is lower in the marine than in the nonmarine samples. Copper and selenium contents of the two kinds of nonmarine rocks and the nearshore marine samples are the same, but those of the offshore samples are larger. In general, arsenic, chromium, copper, molybdenum, selenium, vanadium and zinc are concentrated in those offshore marine samples having the largest amounts of organic carbon, but samples with equal amounts of vanadium, for instance, may differ by a factor of 3 in their amount of organic carbon. Arsenic and molybdenum occur in some samples chiefly in syngenetic pyrite but also are present in relatively large amounts in samples that contain little pyrite. The data on nonmarine carbonaceous shales indicate that organic matter of terrestrial origin in marine shales contributes little to the minor-element content of such rocks. It is possible that marine organic matter, even though seemingly small in amount in marine shales, contributes to the minor-element composition of the shales. In addition to any such contribution, however, the great effectiveness in sorption processes of humic materials in conjunction with clay minerals suggests that such processes must have played an important role as these materials moved from the relatively dilute solutions of the nonmarine environment to the relatively concentrated solution of sea water. The volumes of sea water sufficient to supply for sorption the amounts of most minor elements in the offshore marine samples are insignificant compared to the volumes of water with which the clay and organic matter were in contact during their transportation and sedimentation. Consequently, the chemical characteristics of the environment in which the clay minerals and organic matter accumulated and underwent diagenesis probably were the most important factors in controlling the degree to which sorption processes and the formation of syngenetic minerals affected the final composition of the rocks. ?? 1969.

Fundamentals of gas flow in shale; What the unconventional reservoir industry can learn from the radioactive waste industry

NASA Astrophysics Data System (ADS)

Cuss, Robert; Harrington, Jon; Graham, Caroline

2013-04-01

Tight formations, such as shale, have a wide range of potential usage; this includes shale gas exploitation, hydrocarbon sealing, carbon capture & storage and radioactive waste disposal. Considerable research effort has been conducted over the last 20 years on the fundamental controls on gas flow in a range of clay-rich materials at the British Geological Survey (BGS) mainly focused on radioactive waste disposal; including French Callovo-Oxfordian claystone, Belgian Boom Clay, Swiss Opalinus Clay, British Oxford Clay, as well as engineered barrier material such as bentonite and concrete. Recent work has concentrated on the underlying physics governing fluid flow, with evidence of dilatancy controlled advective flow demonstrated in Callovo-Oxfordian claystone. This has resulted in a review of how advective gas flow is dealt with in Performance Assessment and the applicability of numerical codes. Dilatancy flow has been shown in Boom clay using nano-particles and is seen in bentonite by the strong hydro-mechanical coupling displayed at the onset of gas flow. As well as observations made at BGS, dilatancy flow has been shown by other workers on shale (Cuss et al., 2012; Angeli et al. 2009). As well as experimental studies using cores of intact material, fractured material has been investigated in bespoke shear apparatus. Experimental results have shown that the transmission of gas by fractures is highly localised, dependent on normal stress, varies with shear, is strongly linked with stress history, is highly temporal in nature, and shows a clear correlation with fracture angle. Several orders of magnitude variation in fracture transmissivity is seen during individual tests. Flow experiments have been conducted using gas and water, showing remarkably different behaviour. The radioactive waste industry has also noted a number of important features related to sample preservation. Differences in gas entry pressure have been shown across many laboratories and these may be attributed to different core preparation techniques. Careful re-stressing of core barrels and sealing techniques also ensure that experiments are conducted on near in situ condition. The construction of tunnels within shale clearly aids our understanding of the interaction of engineered operations (borehole drilling or tunnelling) on the behaviour of the rock. References: Angeli, M., Soldal, M., Skurtveit, E. and Aker, E., (2009) Experimental percolation of supercritical CO2 through a caprock. Energy Procedia 1, 3351-3358 Cuss, R.J., Harrington, J.F., Giot, R., and Auvray, C. (2012) Experimental observations of mechanical dilation at the onset of gas flow in Callovo-Oxfordian Claystone. Poster Presentation 5th International Meeting Clays in Natural and Engineered Barriers for Radioactive Waste Confinement, Montpellier, France October 22nd - 25th 2012.

Detailed description of oil shale organic and mineralogical heterogeneity via fourier transform infrared mircoscopy

USGS Publications Warehouse

Washburn, Kathryn E.; Birdwell, Justin E.; Foster, Michael; Gutierrez, Fernando

2015-01-01

Mineralogical and geochemical information on reservoir and source rocks is necessary to assess and produce from petroleum systems. The standard methods in the petroleum industry for obtaining these properties are bulk measurements on homogenized, generally crushed, and pulverized rock samples and can take from hours to days to perform. New methods using Fourier transform infrared (FTIR) spectroscopy have been developed to more rapidly obtain information on mineralogy and geochemistry. However, these methods are also typically performed on bulk, homogenized samples. We present a new approach to rock sample characterization incorporating multivariate analysis and FTIR microscopy to provide non-destructive, spatially resolved mineralogy and geochemistry on whole rock samples. We are able to predict bulk mineralogy and organic carbon content within the same margin of error as standard characterization techniques, including X-ray diffraction (XRD) and total organic carbon (TOC) analysis. Validation of the method was performed using two oil shale samples from the Green River Formation in the Piceance Basin with differing sedimentary structures. One sample represents laminated Green River oil shales, and the other is representative of oil shale breccia. The FTIR microscopy results on the oil shales agree with XRD and LECO TOC data from the homogenized samples but also give additional detail regarding sample heterogeneity by providing information on the distribution of mineral phases and organic content. While measurements for this study were performed on oil shales, the method could also be applied to other geological samples, such as other mudrocks, complex carbonates, and soils.

Graphite Black shale of Vendas de Ceira, Coimbra, Portugal

NASA Astrophysics Data System (ADS)

Quinta-Ferreira, Mário; Silva, Daniela; Coelho, Nuno; Gomes, Ruben; Santos, Ana; Piedade, Aldina

2017-04-01

The graphite black shale of Vendas de Ceira located in south of Coimbra (Portugal), caused serious instability problems in recent road excavation slopes. The problems increased with the rain, transforming shales into a dark mud that acquires a metallic hue when dried. The black shales are attributed to the Devonian or eventually, to the Silurian. At the base of the slope is observed graphite black shale and on the topbrown schist. Samples were collected during the slope excavation works. Undisturbed and less altered materials were selected. Further, sampling was made difficult as the graphite shale was covered by a thick layer of reinforced concrete, which was used to stabilize the excavated surfaces. The mineralogy is mainly constituted by quartz, muscovite, ilite, ilmenite and feldspar without the presence of expansive minerals. The organic matter content is 0.3 to 0.4%. The durability evaluated by the Slake Durability Test varies from very low (Id2 of 6% for sample A) to high (98% for sample C). The grain size distribution of the shale particles, was determined after disaggregation with water, which allowed verifying that sample A has 37% of fines (5% of clay and 32% of silt) and 63% of sand, while sample C has only 14% of fines (2% clay and 12% silt) and 86% sand, showing that the decrease in particle size contributes to reduce durability. The unconfined linear expansion confirms the higher expandability (13.4%) for sample A, reducing to 12.1% for sample B and 10.5% for sample C. Due the shale material degradated with water, mercury porosimetry was used. While the dry weight of the three samples does not change significantly, around 26 kN/m3, the porosity is much higher in sample A with 7.9% of pores, reducing to 1.4% in sample C. The pores size vary between 0.06 to 0.26 microns, does not seem to have any significant influence in the shale behaviour. In order to have a comparison term, a porosity test was carried out on the low weatherable brown shale, which is quite abundant at the site. The main difference to the graphite shale is the high porosity of the brown shale with 14.7% and the low volume weight of 23 kN/m3, evidencing the distinct characteristics of the graphite schists. The maximum strength was evaluated by the Schmidt hammer, as the point load test could not be performed as the rock was very soft. The maximum estimated values on dry samples were 32 MPa for sample A and 85 MPa for sample C. The results show a singular material characterized by significant heterogeneity. It can be concluded that for the graphite schists the smaller particle size and higher porosity make the soft rock extremely weatherable when decompressed and exposed to water, as a result of high capillary tension and reduced cohesion. They also exhibit high expansion and an enormous degradation of the rock presenting a behaviour close to a soil. The graphite black schist is a highly weatherable soft rock, without expansive minerals, with small pores, in which the porosity, low strength and low cohesion allow their rapid degradation when decompressed and exposed to the action of Water.

Near-Infrared Imaging for Spatial Mapping of Organic Content in Petroleum Source Rocks

NASA Astrophysics Data System (ADS)

Mehmani, Y.; Burnham, A. K.; Vanden Berg, M. D.; Tchelepi, H.

2017-12-01

Natural gas from unconventional petroleum source rocks (shales) plays a key role in our transition towards sustainable low-carbon energy production. The potential for carbon storage (in adsorbed state) in these formations further aligns with efforts to mitigate climate change. Optimizing production and development from these resources requires knowledge of the hydro-thermo-mechanical properties of the rock, which are often strong functions of organic content. This work demonstrates the potential of near-infrared (NIR) spectral imaging in mapping the spatial distribution of organic content with O(100µm) resolution on cores that can span several hundred feet in depth (Mehmani et al., 2017). We validate our approach for the immature oil shale of the Green River Formation (GRF), USA, and show its applicability potential in other formations. The method is a generalization of a previously developed optical approach specialized to the GRF (Mehmani et al., 2016a). The implications of this work for spatial mapping of hydro-thermo-mechanical properties of excavated cores, in particular thermal conductivity, are discussed (Mehmani et al., 2016b). References:Mehmani, Y., A.K. Burnham, M.D. Vanden Berg, H. Tchelepi, "Quantification of organic content in shales via near-infrared imaging: Green River Formation." Fuel, (2017). Mehmani, Y., A.K. Burnham, M.D. Vanden Berg, F. Gelin, and H. Tchelepi. "Quantification of kerogen content in organic-rich shales from optical photographs." Fuel, (2016a). Mehmani, Y., A.K. Burnham, H. Tchelepi, "From optics to upscaled thermal conductivity: Green River oil shale." Fuel, (2016b).

Noble Gas Signatures in Antrim Shale Gas in the Michigan Basin - Assessing Compositional Variability and Transport Processes

NASA Astrophysics Data System (ADS)

Wen, T.; Castro, M. C.; Ellis, B. R.; Hall, C. M.; Lohmann, K. C.; Bouvier, L.

2014-12-01

Recent studies in the Michigan Basin looked at the atmospheric and terrigenic noble gas signatures of deep brines to place constraints on the past thermal history of the basin and to assess the extent of vertical transport processes within this sedimentary system. In this contribution, we present noble gas data of shale gas samples from the Antrim shale formation in the Michigan Basin. The Antrim shale was one of the first economic shale-gas plays in the U.S. and has been actively developed since the 1980's. This study pioneers the use of noble gases in subsurface shale gas in the Michigan Basin to clarify the nature of vertical transport processes within the sedimentary sequence and to assess potential variability of noble gas signatures in shales. Antrim Shale gas samples were analyzed for all stable noble gases (He, Ne, Ar, Kr, Xe) from samples collected at depths between 300 and 500m. Preliminary results show R/Ra values (where R and Ra are the measured and atmospheric 3He/4He ratios, respectively) varying from 0.022 to 0.21. Although most samples fall within typical crustal R/Ra range values (~0.02-0.05), a few samples point to the presence of a mantle He component with higher R/Ra ratios. Samples with higher R/Ra values also display higher 20Ne/22Ne ratios, up to 10.4, and further point to the presence of mantle 20Ne. The presence of crustally produced nucleogenic 21Ne and radiogenic 40Ar is also apparent with 21Ne/22Ne ratios up to 0.033 and 40Ar/36Ar ratios up to 312. The presence of crustally produced 4He, 21Ne and 40Ar is not spatially homogeneous within the Antrim shale. Areas of higher crustal 4He production appear distinct to those of crustally produced 21Ne and 40Ar and are possibly related the presence of different production levels within the shale with varying concentrations of parent elements.

Surface water geochemical and isotopic variations in an area of accelerating Marcellus Shale gas development.

PubMed

Pelak, Adam J; Sharma, Shikha

2014-12-01

Water samples were collected from 50 streams in an area of accelerating shale gas development in the eastern U.S.A. The geochemical/isotopic characteristics show no correlation with the five categories of Marcellus Shale production. The sub-watersheds with the greatest density of Marcellus Shale development have also undergone extensive coal mining. Hence, geochemical/isotopic compositions were used to understand sources of salinity and effects of coal mining and shale gas development in the area. The data indicates that while some streams appear to be impacted by mine drainage; none appear to have received sustained contribution from deep brines or produced waters associated with shale gas production. However, it is important to note that our interpretations are based on one time synoptic base flow sampling of a few sampling stations and hence do account potential intermittent changes in chemistry that may result from major/minor spills or specific mine discharges on the surface water chemistry. Copyright © 2014 Elsevier Ltd. All rights reserved.

Micropillar Compression Technique Applied to Micron-Scale Mudstone Elasto-Plastic Deformation

NASA Astrophysics Data System (ADS)

Dewers, T. A.; Boyce, B.; Buchheit, T.; Heath, J. E.; Chidsey, T.; Michael, J.

2010-12-01

Mudstone mechanical testing is often limited by poor core recovery and sample size, preservation and preparation issues, which can lead to sampling bias, damage, and time-dependent effects. A micropillar compression technique, originally developed by Uchic et al. 2004, here is applied to elasto-plastic deformation of small volumes of mudstone, in the range of cubic microns. This study examines behavior of the Gothic shale, the basal unit of the Ismay zone of the Pennsylvanian Paradox Formation and potential shale gas play in southeastern Utah, USA. Precision manufacture of micropillars 5 microns in diameter and 10 microns in length are prepared using an ion-milling method. Characterization of samples is carried out using: dual focused ion - scanning electron beam imaging of nano-scaled pores and distribution of matrix clay and quartz, as well as pore-filling organics; laser scanning confocal (LSCM) 3D imaging of natural fractures; and gas permeability, among other techniques. Compression testing of micropillars under load control is performed using two different nanoindenter techniques. Deformation of 0.5 cm in diameter by 1 cm in length cores is carried out and visualized by a microscope loading stage and laser scanning confocal microscopy. Axisymmetric multistage compression testing and multi-stress path testing is carried out using 2.54 cm plugs. Discussion of results addresses size of representative elementary volumes applicable to continuum-scale mudstone deformation, anisotropy, and size-scale plasticity effects. Other issues include fabrication-induced damage, alignment, and influence of substrate. This work is funded by the US Department of Energy, Office of Basic Energy Sciences. Sandia is a multiprogram laboratory operated by Sandia Corporation, a Lockheed Martin Company, for the United States Department of Energy’s National Nuclear Security Administration under contract DE-AC04-94AL85000.

Evaluation of stratigraphic relations of sandstone-producing reservoirs in upper Council Grove and Chase groups (Permian) in north-central Oklahoma

DOE Office of Scientific and Technical Information (OSTI.GOV)

Chaplin, J.R.

1989-08-01

Poor well control and the absence of surface stratigraphic control made previous interpretations of the stratigraphic relations of sandstone-producing reservoirs tenuous. Recent extensive analyses of surface outcrops and well and core data support the contention that the major sandstone-producing reservoirs can be physically correlated with formations in the outcrop section. Sandstone bodies within the upper Council Grove Group include Neva sand and Blackwell sand (Neva Limestone), Hotson-Kisner sand (Eskridge Shale), and the Whitney-Hodges sand. The Whitney-Hodges sand correlates, in part, with the Speiser Shale (Garrison Formation) of the outcrop section. However, previous usage suggested tentative correlations with sandstone bodies stratigraphicallymore » lower in the section. These sands were probably deposited in channels that were, in part, fluvial, tidal, or estuarine. Production from the Chase Group occurs locally within channelform sandstone bodies referred to as the Hoy-Matfield sand. These sands appear to be equivalent, occupying essentially the position of the Kinney Limestone Member (Matfield Shale) of the outcrop section. Detailed core-hole data at and in the vicinity of Kaw Dam, southeastern Kay County, and outcrops along the shoreline of Kaw Lake at Kaw City, Kay County, clearly demonstrate the facies distribution of the Hoy sand. Core-hole data has also delineated additional potential sandstone reservoirs within and near or at the top of the Fort Riley Limestone Member (Barneston Limestone). The Wolfe sand, a producing sandstone locally, occupies a stratigraphic position within the Doyle Shale.« less

Comparative study of microfacies variation in two samples from the Chittenango member, Marcellus shale subgroup, western New York state, USA

DOE Office of Scientific and Technical Information (OSTI.GOV)

Balulla, Shama, E-mail: shamamohammed77@outlook.com; Padmanabhan, E., E-mail: eswaran-padmanabhan@petronas.com.my; Over, Jeffrey, E-mail: over@geneseo.edu

This study demonstrates the significant lithologic variations that occur within the two shale samples from the Chittenango member of the Marcellus shale formation from western New York State in terms of mineralogical composition, type of lamination, pyrite occurrences and fossil content using thin section detailed description and field emission Scanning electron microscope (FESEM) with energy dispersive X-Ray Spectrum (EDX). This study is classified samples as laminated clayshale and fossiliferous carbonaceous shale. The most important detrital constituents of these shales are the clay mineral illite and chlorite, quartz, organic matter, carbonate mineral, and pyrite. The laminated clayshale has a lower amountmore » of quartz and carbonate minerals than fossiliferous carbonaceous shale while it has a higher amount of clay minerals (chlorite and illite) and organic matter. FESEM analysis confirms the presence of chlorite and illite. The fossil content in the laminated clayshale is much lower than the fossiliferous carbonaceous shale. This can provide greater insights about variations in the depositional and environmental factors that influenced its deposition. This result can be compiled with the sufficient data to be helpful for designing the horizontal wells and placement of hydraulic fracturing in shale gas exploration and production.« less

Sedimentology of SPICE (Steptoean positive carbon isotope excursion): A high-resolution trace fossil and microfabric analysis of the middle to late Cambrian Alum Shale Formation, southern Sweden

USGS Publications Warehouse

Egenhoff, Sven; Fishman, Neil; Ahlberg, Per; Maletz, Jorg; Jackson, Allison; Kolte, Ketki; Lowers, Heather; Mackie, James; Newby, Warren; Petrowsky, Matthew

2015-01-01

The Cambrian Alum Shale Formation in the Andrarum-3 core from Scania, southern Sweden, consists of black siliciclastic mudstone with minor carbonate intercalations. Four facies comprise three siliciclastic mudstones and one fine-grained carbonate. The facies reflect deposition along a transect from deep ramp to basin on a Cambrian shelf. The three mudstone facies contain abundant clay clasts and laterally variable siltstone laminae. Bed-load transport processes seem to have dominated deposition on this deep shelf. These sedimentary rocks record mainly event deposition, and only relatively few, thin laminae probably resulted from suspension settling. The Alum Shale Formation deep shelf did not show a bioturbation gradient, but fecal strings are common and Planolites burrows are rare in all mudstone facies. Evidence for biotic colonization indicates that this mudstone environment was not persistently anoxic, but rather was most likely intermittently dysoxic. The Alum Shale Formation in the Andrarum-3 core shows an overall decrease of grain size, preserved energy indicators, and carbonate content upsection interpreted to reflect a deepening upward. The succession can also be divided into four small-scale fining-upward cycles that represent deepening, and four overlying coarsening-upward cycles that represent upward shallowing.

Rates and Mechanisms of Oil Shale Pyrolysis: A Chemical Structure Approach

DOE Office of Scientific and Technical Information (OSTI.GOV)

Fletcher, Thomas; Pugmire, Ronald

2015-01-01

Three pristine Utah Green River oil shale samples were obtained and used for analysis by the combined research groups at the University of Utah and Brigham Young University. Oil shale samples were first demineralized and the separated kerogen and extracted bitumen samples were then studied by a host of techniques including high resolution liquid-state carbon-13 NMR, solid-state magic angle sample spinning 13C NMR, GC/MS, FTIR, and pyrolysis. Bitumen was extracted from the shale using methanol/dichloromethane and analyzed using high resolution 13C NMR liquid state spectroscopy, showing carbon aromaticities of 7 to 11%. The three parent shales and the demineralized kerogensmore » were each analyzed with solid-state 13C NMR spectroscopy. Carbon aromaticity of the kerogen was 23-24%, with 10-12 aromatic carbons per cluster. Crushed samples of Green River oil shale and its kerogen extract were pyrolyzed at heating rates from 1 to 10 K/min at pressures of 1 and 40 bar and temperatures up to 1000°C. The transient pyrolysis data were fit with a first-order model and a Distributed Activation Energy Model (DAEM). The demineralized kerogen was pyrolyzed at 10 K/min in nitrogen at atmospheric pressure at temperatures up to 525°C, and the pyrolysis products (light gas, tar, and char) were analyzed using 13C NMR, GC/MS, and FTIR. Details of the kerogen pyrolysis have been modeled by a modified version of the chemical percolation devolatilization (CPD) model that has been widely used to model coal combustion/pyrolysis. This refined CPD model has been successful in predicting the char, tar, and gas yields of the three shale samples during pyrolysis. This set of experiments and associated modeling represents the most sophisticated and complete analysis available for a given set of oil shale samples.« less

Cr(VI)/Cr(III) and As(V)/As(III) ratio assessments in Jordanian spent oil shale produced by aerobic combustion and Anaerobic Pyrolysis.

PubMed

El-Hasan, Tayel; Szczerba, Wojciech; Buzanich, Günter; Radtke, Martin; Riesemeier, Heinrich; Kersten, Michael

2011-11-15

With the increase in the awareness of the public in the environmental impact of oil shale utilization, it is of interest to reveal the mobility of potentially toxic trace elements in spent oil shale. Therefore, the Cr and As oxidation state in a representative Jordanian oil shale sample from the El-Lajjoun area were investigated upon different lab-scale furnace treatments. The anaerobic pyrolysis was performed in a retort flushed by nitrogen gas at temperatures in between 600 and 800 °C (pyrolytic oil shale, POS). The aerobic combustion was simply performed in porcelain cups heated in a muffle furnace for 4 h at temperatures in between 700 and 1000 °C (burned oil shale, BOS). The high loss-on-ignition in the BOS samples of up to 370 g kg(-1) results from both calcium carbonate and organic carbon degradation. The LOI leads to enrichment in the Cr concentrations from 480 mg kg(-1) in the original oil shale up to 675 mg kg(-1) in the ≥ 850 °C BOS samples. Arsenic concentrations were not much elevated beyond that in the average shale standard (13 mg kg(-1)). Synchrotron-based X-ray absorption near-edge structure (XANES) analysis revealed that within the original oil shale the oxidation states of Cr and As were lower than after its aerobic combustion. Cr(VI) increased from 0% in the untreated or pyrolyzed oil shale up to 60% in the BOS ash combusted at 850 °C, while As(V) increased from 64% in the original oil shale up to 100% in the BOS ash at 700 °C. No Cr was released from original oil shale and POS products by the European compliance leaching test CEN/TC 292 EN 12457-1 (1:2 solid/water ratio, 24 h shaking), whereas leachates from BOS samples showed Cr release in the order of one mmol L(-1). The leachable Cr content is dominated by chromate as revealed by catalytic adsorptive stripping voltammetry (CAdSV) which could cause harmful contamination of surface and groundwater in the semiarid environment of Jordan.

Geologic and hydraulic characteristics of selected shaly geologic units in Oklahoma

USGS Publications Warehouse

Becker, C.J.; Overton, M.D.; Johnson, K.S.; Luza, K.V.

1997-01-01

Information was collected on the geologic and hydraulic characteristics of three shale-dominated units in Oklahoma-the Dog Creek Shale and Chickasha Formation in Canadian County, Hennessey Group in Oklahoma County, and the Boggy Formation in Pittsburg County. The purpose of this project was to gain insight into the characteristics controlling fluid flow in shaly units that could be targeted for confinement of hazardous waste in the State and to evaluate methods of measuring hydraulic characteristics of shales. Permeameter results may not indicate in-place small-scale hydraulic characteristics, due to pretest disturbance and deterioration of core samples. The Dog Creek Shale and Chickasha Formation hydraulic conductivities measured by permeameter methods ranged from 2.8 times 10 to the negative 11 to 3.0 times 10 to the negative 7 meter per second in nine samples and specific storage from 3.3 times 10 to the negative 4 to 1.6 times 10 to the negative 3 per meter in four samples. Hennessey Group hydraulic conductivities ranged from 4.0 times 10 to the negative 12 to 4.0 times 10 to the negative 10 meter per second in eight samples. Hydraulic conductivity in the Boggy Formation ranged from 1.7 times 10 to the negative 12 to 1.0 times 10 to the negative 8 meter per second in 17 samples. The hydraulic properties of isolated borehole intervals of average length of 4.5 meters in the Hennessey Group and the Boggy Formation were evaluated by a pressurized slug-test method. Hydraulic conductivities obtained with this method tend to be low because intervals with features that transmitted large volumes of water were not tested. Hennessey Group hydraulic conductivities measured by this method ranged from 3.0 times 10 to the negative 13 to 1.1 times 10 to the negative 9 meter per second; the specific storage values are small and may be unreliable. Boggy Formation hydraulic conductivities ranged from 2.0 times 10 to the negative 13 to 2.7 times 10 to the negative 10 meter per second and specific storage values in these tests also are small and may be unreliable. A substantially higher hydraulic conductivity of 3.0 times 10 to the negative 8 meter per second was measured in one borehole 30 meters deep in the Boggy Formation using an open hole slug-test method.

Real-time detection of dielectric anisotropy or isotropy in unconventional oil-gas reservoir rocks supported by the oblique-incidence reflectivity difference technique

NASA Astrophysics Data System (ADS)

Zhan, Honglei; Wang, Jin; Zhao, Kun; Lű, Huibin; Jin, Kuijuan; He, Liping; Yang, Guozhen; Xiao, Lizhi

2016-12-01

Current geological extraction theory and techniques are very limited to adequately characterize the unconventional oil-gas reservoirs because of the considerable complexity of the geological structures. Optical measurement has the advantages of non-interference with the earth magnetic fields, and is often useful in detecting various physical properties. One key parameter that can be detected using optical methods is the dielectric permittivity, which reflects the mineral and organic properties. Here we reported an oblique-incidence reflectivity difference (OIRD) technique that is sensitive to the dielectric and surface properties and can be applied to characterization of reservoir rocks, such as shale and sandstone core samples extracted from subsurface. The layered distribution of the dielectric properties in shales and the uniform distribution in sandstones are clearly identified using the OIRD signals. In shales, the micro-cracks and particle orientation result in directional changes of the dielectric and surface properties, and thus, the isotropy and anisotropy of the rock can be characterized by OIRD. As the dielectric and surface properties are closely related to the hydrocarbon-bearing features in oil-gas reservoirs, we believe that the precise measurement carried with OIRD can help in improving the recovery efficiency in well-drilling process.

Real-time detection of dielectric anisotropy or isotropy in unconventional oil-gas reservoir rocks supported by the oblique-incidence reflectivity difference technique

PubMed Central

Zhan, Honglei; Wang, Jin; Zhao, Kun; Lű, Huibin; Jin, Kuijuan; He, Liping; Yang, Guozhen; Xiao, Lizhi

2016-01-01

Current geological extraction theory and techniques are very limited to adequately characterize the unconventional oil-gas reservoirs because of the considerable complexity of the geological structures. Optical measurement has the advantages of non-interference with the earth magnetic fields, and is often useful in detecting various physical properties. One key parameter that can be detected using optical methods is the dielectric permittivity, which reflects the mineral and organic properties. Here we reported an oblique-incidence reflectivity difference (OIRD) technique that is sensitive to the dielectric and surface properties and can be applied to characterization of reservoir rocks, such as shale and sandstone core samples extracted from subsurface. The layered distribution of the dielectric properties in shales and the uniform distribution in sandstones are clearly identified using the OIRD signals. In shales, the micro-cracks and particle orientation result in directional changes of the dielectric and surface properties, and thus, the isotropy and anisotropy of the rock can be characterized by OIRD. As the dielectric and surface properties are closely related to the hydrocarbon-bearing features in oil-gas reservoirs, we believe that the precise measurement carried with OIRD can help in improving the recovery efficiency in well-drilling process. PMID:27976746

Assessment of continuous (unconventional) oil and gas resources in the Late Cretaceous Mancos Shale of the Piceance Basin, Uinta-Piceance Province, Colorado and Utah, 2016

USGS Publications Warehouse

Hawkins, Sarah J.; Charpentier, Ronald R.; Schenk, Christopher J.; Leathers-Miller, Heidi M.; Klett, Timothy R.; Brownfield, Michael E.; Finn, Tom M.; Gaswirth, Stephanie B.; Marra, Kristen R.; Le, Phoung A.; Mercier, Tracey J.; Pitman, Janet K.; Tennyson, Marilyn E.

2016-06-08

The U.S. Geological Survey (USGS) completed a geology-based assessment of the continuous (unconventional) oil and gas resources in the Late Cretaceous Mancos Shale within the Piceance Basin of the Uinta-Piceance Province (fig. 1). The previous USGS assessment of the Mancos Shale in the Piceance Basin was completed in 2003 as part of a comprehensive assessment of the greater UintaPiceance Province (U.S. Geological Survey Uinta-Piceance Assessment Team, 2003). Since the last assessment, more than 2,000 wells have been drilled and completed in one or more intervals within the Mancos Shale of the Piceance Basin (IHS Energy Group, 2015). In addition, the USGS Energy Resources Program drilled a research core in the southern Piceance Basin that provided significant new geologic and geochemical data that were used to refine the 2003 assessment of undiscovered, technically recoverable oil and gas in the Mancos Shale.

Geochemical and mineralogical sampling of the Devonian shales in the Broadtop synclinorium, Appalachian basin, in Virginia, West Virginia, Maryland, and Pennsylvania

USGS Publications Warehouse

Enomoto, Catherine B.; Coleman, James L.; Swezey, Christopher S.; Niemeyer, Patrick W.; Dulong, Frank T.

2015-01-01

The presence of conventional anticlinal gas fields in the study area that are productive from the underlying Lower Devonian Oriskany Sandstone suggests that an unconventional (or continuous) shale gas system may be in place within the Marcellus Shale in the study area. Results of this study indicate that the Marcellus Shale in the Broadtop synclinorium generally is similar in organic geochemical nature throughout its extent, and based on the sample analyses, there are no clearly identifiable high potential areas (or “sweet spots”) in the study area. This report contains analyses of 132 outcrop and well drill-cuttings samples.

IN SITU AND LABORATORY GEOTECHNICAL TESTS OF THE PIERRE SHALE NEAR HAYES, SOUTH DAKOTA - A CHARACTERIZATION OF ENGINEERING BEHAVIOR.

USGS Publications Warehouse

Nichols, Thomas C.; Collins, Donley S.; Davidson, Richard R.

1986-01-01

A geotechnical investigation of the Pierre Shale near Hayes, South Dakota, was conducted by the U. S. Geological Survey as a basis for evaluating problems in deep excavations into that formation. The physical and mechanical properties of the shale were determined through use of core holes drilled to a maximum depth of 184 m. In situ borehole determinations included a gravimeter survey, pressuremeter testing, thermal profile measurements, and borehole velocity measurements. Onsite and offsite laboratory measurements included rebound measurements, sonic velocity measurements of shear and primary waves, X-ray mineralogy and major element determinations, size analyses, fracture analyses, fabric analyses, and determination of thermal properties. The properties of the clay shale indicate problems that may be encountered in excavation and use of deep underground facilities.

The effect of maturation on the configuration of pristane in sediments and petroleum

NASA Technical Reports Server (NTRS)

Patience, R. L.; Rowland, S. J.; Maxwell, J. R.

1978-01-01

The absolute stereochemistry of pristane in a sample of contemporary marine zooplankton, Messel shale (Germany) and Djatibarang (Java) crude has been determined by gas chromatographic methods. The relative stereochemistry in Irati shale (Brazil), Green River (U.S.) crude, Halibut (Australia) crude has also been determined, and confirmed for a sample of the Green River shale. The stereoisomer distributions indicate a loss of stereospecificity of the phytol-derived 6(R), 10(S) pristane with increasing geological maturation. For example, the least mature geological sample, the Eocene Messel shale, contains solely the 6(R), 10(S) isomer, whereas a mature sample, Djatibarange crude, contains 50% of the 6(R), 10(S) isomer and 25% of each of the 6(R), 10(R) and 6(S), 10(S) isomers.

Effects of processed oil shale on the element content of Atriplex cancescens

DOE Office of Scientific and Technical Information (OSTI.GOV)

Anderson, B.M.

1982-01-01

Samples of four-wing saltbush were collected from the Colorado State University Intensive Oil Shale Revegetation Study Site test plots in the Piceance basin, Colorado. The test plots were constructed to evaluate the effects of processed oil shale geochemistry on plant growth using various thicknesses of soil cover over the processed shale and/or over a gravel barrier between the shale and soil. Generally, the thicker the soil cover, the less the influence of the shale geochemistry on the element concentrations in the plants. Concentrations of 20 elements were larger in the ash of four-wing saltbush growing on the plot with themore » gravel barrier (between the soil and processed shale) when compared to the sample from the control plot. A greater water content in the soil in this plot has been reported, and the interaction between the increased, percolating water and shale may have increased the availability of these elements for plant uptake. Concentrations of boron, copper, fluorine, lithium, molybdenum, selenium, silicon, and zinc were larger in the samples grown over processed shale, compared to those from the control plot, and concentrations for barium, calcium, lanthanum, niobium, phosphorus, and strontium were smaller. Concentrations for arsenic, boron, fluorine, molybdenum, and selenium - considered to be potential toxic contaminants - were similar to results reported in the literature for vegetation from the test plots. The copper-to-molybdenum ratios in three of the four samples of four-wing saltbush growing over the processed shale were below the ratio of 2:1, which is judged detrimental to ruminants, particularly cattle. Boron concentrations averaged 140 ppM, well above the phytotoxicity level for most plant species. Arsenic, fluorine, and selenium concentrations were below toxic levels, and thus should not present any problem for revegetation or forage use at this time.« less

High-resolution stratigraphic analyses of Permian-Triassic core material recovered in central Spitsbergen

NASA Astrophysics Data System (ADS)

Sleveland, Arve; Planke, Sverre; Zuchuat, Valentin; Franeck, Franziska; Svensen, Henrik; Midtkandal, Ivar; Hammer, Øyvind; Twitchett, Richard; Deltadalen Study Group

2017-04-01

The Siberian Traps voluminous igneous activity is considered a likely trigger for the Permian-Triassic global extinction event. However, documented evidence of the Siberian Traps environmental effects decreases away from the centre of volcanic activity in north-central Russia. Previous research on the Permian-Triassic boundary (PTB) mostly relies on field observations, and resolution has thus depended on outcrop quality. This study reports on two 90 m cored sedimentary successions intersecting the PTB in Deltadalen, Svalbard, providing high-quality material to a comprehensive documentation of the stratigraphic interval. Sequence stratigraphic concepts are utilised to help constrain the Permian-Triassic basin development models in Svalbard and the high-Arctic region. The cored sections are calibrated with outcrop data from near the drill site. One core has been systematically described and scanned using 500-μm and 200-μm resolution XRF, hyperspectral imagery and microfocus CT (latter only on selected core sections). The base of both cores represents the upper 15 m of the Permian Kapp Starostin Formation, which is dominated by green glauconitic sandstones with spiculitic cherts, and exhibit various degrees of bioturbation. The Kapp Starostin Formation is in turn sharply overlain by 2 m of heavily reworked sand- and mudstones, extensively bioturbated, representing the base of the lower Triassic Vikinghøgda Formation. These bioturbated units are conformably overlain by 9 m of ash-bearing laminated black shale where signs of biological activity both on micro- and macro-scale are limited, and is thus interpreted to have recorded the Permian-Triassic extinction interval. Descriptive sedimentology and sequence stratigraphic concepts reveal the onset of relative sea level rise at the Vikinghøgda Formation base. The disappearance of bioturbation and extensive presence of pyrite in the overlying laminated black shale of the Vikinghøgda Formation suggest near anoxic conditions. The maximum flooding surface is recorded 6 m above the base of the Vikinghøgda Formation, in the middle of the laminated black shale and indicates that the lower ash-layers are tied to igneous activity at a time of relatively high sea level. The remaining succession above the laminated black shale is an overall aggradational interval of interbedded clay- and siltstones of the Vikinghøgda Formation, marking the return of biological activity at its base. The Vikinghøgda Formation includes 18 preserved zircon-bearing ash-layers, providing an opportunity for accurate U/Pb dating. Detailed cyclostratigraphic analyses of the laminated black shale suggest a sedimentation rate of approximately 0.5 cm/kyr, and provides thus, together with the U/Pb zircon ages, a great tool for high-resolution documentation of the PTB interval.

Micro-fracture Behavior of Organic Matters in Kerogen-Rich Shale (KRS) Composites from Micro- to Milli-meter Scales

NASA Astrophysics Data System (ADS)

Haque, M. H.; Han, Y.; Hull, K. L.; Abousleiman, Y. N.

2017-12-01

Understanding the failure behavior of kerogen-rich shale (KRS) at multiscale is critical to efficient hydraulic fracture stimulations in unconventional source shale reservoirs. As a composite material consisting of compacted clay particles, silt-sized grains, and organic matter (OM), KRS is highly complex both structurally and mechanically. The OM, which is intertwined within the shale matrix, presents a particular challenge as it can be much more compliant than its surrounding minerals while at the same time have a significantly higher tensile strength. The mode-I fracture toughness and tensile failure behavior of KRS has been studied at the core scale by traditional rock mechanics methods i.e., Brazilian tests and more recently with non-traditional approaches at the micro-scale using nanoindentation techniques. However, core scale testing fails in precisely capturing the effects of OM due to its coarse resolution, while nanoindention may capture the behavior of isolated component but in some cases miss the collective properties of the composite system. To bridge this gap, while still complying with ASTM/ISRM standards in principle, we investigate fracture initiation and propagation in KRS using the single-edge notched beam (SENB) miniature samples with span length in the millimeter scale. The size scale attempts to isolate the contributions from individual components, especially the OM, to the emergent and systematic fracturing behavior of KRS. Crack propagation along and across the bedding planes have left noticeable signatures on fractured OM while travelling through and around an OM body depending upon its size and spatial position along the crack path illustrating what looks like crack arrest and/or crack bridging in a composite porous matrix. The fractured surface of OM, even being polymeric in nature, exhibits smooth and even surface profile when ripped apart but not in all observed surfaces. Unique microscale features such as- ridges, twists, and inclusions have also been observed for the OM indicating a mix of complex modes of failures. This study helps further the understanding of fracture morphologies in source rock reservoirs.

Thermal Maturity of Pennsylvanian Coals and Coaly Shales, Eastern Shelf and Fort Worth Basin, Texas

USGS Publications Warehouse

Hackley, Paul C.; Guevara, Edgar H.; Hentz, Tucker F.; Hook, Robert W.

2007-01-01

The U.S. Geological Survey and the Texas Bureau of Economic Geology are engaged in an ongoing collaborative study to characterize the organic composition and thermal maturity of Upper Paleozoic coal-bearing strata from the Eastern Shelf of the Midland basin and from the Fort Worth basin, north-central Texas. Data derived from this study will have application to a better understanding of the potential for coalbed gas resources in the region. This is an important effort in that unconventional resources such as coalbed gas are expected to satisfy an increasingly greater component of United States and world natural gas demand in coming decades. In addition, successful coalbed gas production from equivalent strata in the Kerr basin of southern Texas and from equivalent strata elsewhere in the United States suggests that a closer examination of the potential for coalbed gas resources in north-central Texas is warranted. This report presents thermal maturity data for shallow (<2,000 ft; <610 m) coal and coaly shale cuttings, core, and outcrop samples from the Middle-Upper Pennsylvanian Strawn, Canyon, and Cisco Groups from the Eastern Shelf of the Midland basin. Data for Lower Pennsylvanian Atoka Group strata from deeper wells (5,400 ft; 1,645 m) in the western part of the Fort Worth basin also are included herein. The data indicate that the maturity of some Pennsylvanian coal and coaly shale samples is sufficient to support thermogenic coalbed gas generation on the Eastern Shelf and in the western Fort Worth basin.

Early trends in landcover change and forest fragmentation due to shale-gas development in Pennsylvania: a potential outcome for the Northcentral Appalachians.

PubMed

Drohan, P J; Brittingham, M; Bishop, J; Yoder, K

2012-05-01

Worldwide shale-gas development has the potential to cause substantial landscape disturbance. The northeastern U.S., specifically the Allegheny Plateau in Pennsylvania, West Virginia, Ohio, and Kentucky, is experiencing rapid exploration. Using Pennsylvania as a proxy for regional development across the Plateau, we examine land cover change due to shale-gas exploration, with emphasis on forest fragmentation. Pennsylvania's shale-gas development is greatest on private land, and is dominated by pads with 1-2 wells; less than 10 % of pads have five wells or more. Approximately 45-62 % of pads occur on agricultural land and 38-54 % in forest land (many in core forest on private land). Development of permits granted as of June 3, 2011, would convert at least 644-1072 ha of agricultural land and 536-894 ha of forest land. Agricultural land conversion suggests that drilling is somewhat competing with food production. Accounting for existing pads and development of all permits would result in at least 649 km of new road, which, along with pipelines, would fragment forest cover. The Susquehanna River basin (feeding the Chesapeake Bay), is most developed, with 885 pads (26 % in core forest); permit data suggests the basin will experience continued heavy development. The intensity of core forest disturbance, where many headwater streams occur, suggests that such streams should become a focus of aquatic monitoring. Given the intense development on private lands, we believe a regional strategy is needed to help guide infrastructure development, so that habitat loss, farmland conversion, and the risk to waterways are better managed.

Experimental Investigation of Mechanical Properties of Black Shales after CO₂-Water-Rock Interaction.

PubMed

Lyu, Qiao; Ranjith, Pathegama Gamage; Long, Xinping; Ji, Bin

2016-08-06

The effects of CO₂-water-rock interactions on the mechanical properties of shale are essential for estimating the possibility of sequestrating CO₂ in shale reservoirs. In this study, uniaxial compressive strength (UCS) tests together with an acoustic emission (AE) system and SEM and EDS analysis were performed to investigate the mechanical properties and microstructural changes of black shales with different saturation times (10 days, 20 days and 30 days) in water dissoluted with gaseous/super-critical CO₂. According to the experimental results, the values of UCS, Young's modulus and brittleness index decrease gradually with increasing saturation time in water with gaseous/super-critical CO₂. Compared to samples without saturation, 30-day saturation causes reductions of 56.43% in UCS and 54.21% in Young's modulus for gaseous saturated samples, and 66.05% in UCS and 56.32% in Young's modulus for super-critical saturated samples, respectively. The brittleness index also decreases drastically from 84.3% for samples without saturation to 50.9% for samples saturated in water with gaseous CO₂, to 47.9% for samples saturated in water with super-critical carbon dioxide (SC-CO₂). SC-CO₂ causes a greater reduction of shale's mechanical properties. The crack propagation results obtained from the AE system show that longer saturation time produces higher peak cumulative AE energy. SEM images show that many pores occur when shale samples are saturated in water with gaseous/super-critical CO₂. The EDS results show that CO₂-water-rock interactions increase the percentages of C and Fe and decrease the percentages of Al and K on the surface of saturated samples when compared to samples without saturation.

An exploratory study of air emissions associated with shale gas development and production in the Barnett Shale.

PubMed

Rich, Alisa; Grover, James P; Sattler, Melanie L

2014-01-01

Information regarding air emissions from shale gas extraction and production is critically important given production is occurring in highly urbanized areas across the United States. Objectives of this exploratory study were to collect ambient air samples in residential areas within 61 m (200 feet) of shale gas extraction/production and determine whether a "fingerprint" of chemicals can be associated with shale gas activity. Statistical analyses correlating fingerprint chemicals with methane, equipment, and processes of extraction/production were performed. Ambient air sampling in residential areas of shale gas extraction and production was conducted at six counties in the Dallas/Fort Worth (DFW) Metroplex from 2008 to 2010. The 39 locations tested were identified by clients that requested monitoring. Seven sites were sampled on 2 days (typically months later in another season), and two sites were sampled on 3 days, resulting in 50 sets of monitoring data. Twenty-four-hour passive samples were collected using summa canisters. Gas chromatography/mass spectrometer analysis was used to identify organic compounds present. Methane was present in concentrations above laboratory detection limits in 49 out of 50 sampling data sets. Most of the areas investigated had atmospheric methane concentrations considerably higher than reported urban background concentrations (1.8-2.0 ppm(v)). Other chemical constituents were found to be correlated with presence of methane. A principal components analysis (PCA) identified multivariate patterns of concentrations that potentially constitute signatures of emissions from different phases of operation at natural gas sites. The first factor identified through the PCA proved most informative. Extreme negative values were strongly and statistically associated with the presence of compressors at sample sites. The seven chemicals strongly associated with this factor (o-xylene, ethylbenzene, 1,2,4-trimethylbenzene, m- and p-xylene, 1,3,5-trimethylbenzene, toluene, and benzene) thus constitute a potential fingerprint of emissions associated with compression. Information regarding air emissions from shale gas development and production is critically important given production is now occurring in highly urbanized areas across the United States. Methane, the primary shale gas constituent, contributes substantially to climate change; other natural gas constituents are known to have adverse health effects. This study goes beyond previous Barnett Shale field studies by encompassing a wider variety of production equipment (wells, tanks, compressors, and separators) and a wider geographical region. The principal components analysis, unique to this study, provides valuable information regarding the ability to anticipate associated shale gas chemical constituents.

Fracture-permeability behavior of shale

DOE Office of Scientific and Technical Information (OSTI.GOV)

Carey, J. William; Lei, Zhou; Rougier, Esteban

The fracture-permeability behavior of Utica shale, an important play for shale gas and oil, was investigated using a triaxial coreflood device and X-ray tomography in combination with finite-discrete element modeling (FDEM). Fractures generated in both compression and in a direct-shear configuration allowed permeability to be measured across the faces of cylindrical core. Shale with bedding planes perpendicular to direct-shear loading developed complex fracture networks and peak permeability of 30 mD that fell to 5 mD under hydrostatic conditions. Shale with bedding planes parallel to shear loading developed simple fractures with peak permeability as high as 900 mD. In addition tomore » the large anisotropy in fracture permeability, the amount of deformation required to initiate fractures was greater for perpendicular layering (about 1% versus 0.4%), and in both cases activation of existing fractures are more likely sources of permeability in shale gas plays or damaged caprock in CO₂ sequestration because of the significant deformation required to form new fracture networks. FDEM numerical simulations were able to replicate the main features of the fracturing processes while showing the importance of fluid penetration into fractures as well as layering in determining fracture patterns.« less

Fracture-permeability behavior of shale

DOE PAGES

Carey, J. William; Lei, Zhou; Rougier, Esteban; ...

2015-05-08

The fracture-permeability behavior of Utica shale, an important play for shale gas and oil, was investigated using a triaxial coreflood device and X-ray tomography in combination with finite-discrete element modeling (FDEM). Fractures generated in both compression and in a direct-shear configuration allowed permeability to be measured across the faces of cylindrical core. Shale with bedding planes perpendicular to direct-shear loading developed complex fracture networks and peak permeability of 30 mD that fell to 5 mD under hydrostatic conditions. Shale with bedding planes parallel to shear loading developed simple fractures with peak permeability as high as 900 mD. In addition tomore » the large anisotropy in fracture permeability, the amount of deformation required to initiate fractures was greater for perpendicular layering (about 1% versus 0.4%), and in both cases activation of existing fractures are more likely sources of permeability in shale gas plays or damaged caprock in CO₂ sequestration because of the significant deformation required to form new fracture networks. FDEM numerical simulations were able to replicate the main features of the fracturing processes while showing the importance of fluid penetration into fractures as well as layering in determining fracture patterns.« less

Mineralogical characterization of selected shales in support of nuclear waste repository studies: Progress report, October 1987--September 1988

DOE Office of Scientific and Technical Information (OSTI.GOV)

Lee, S. Y.; Hyder, L. K.; Baxter, P. M.

1989-07-01

One objective of the Sedimentary Rock Program at the Oak Ridge National Laboratory has been to examine end-member shales to develop a data base that will aid in evaluations if shales are ever considered as a repository host rock. Five end-member shales were selected for comprehensive characterization: the Chattanooga Shale from Fentress County, Tennessee; the Pierre Shale from Gregory County, South Dakota; the Green River Formation from Garfield County, Colorado; and the Nolichucky Shale and Pumpkin Valley Shale from Roane County, Tennessee. Detailed micromorphological and mineralogical characterizations of the shales were completed by Lee et al. (1987) in ORNL/TM-10567. Thismore » report is a supplemental characterization study that was necessary because second batches of the shale samples were needed for additional studies. Selected physical, chemical, and mineralogical properties were determined for the second batches; and their properties were compared with the results from the first batches. Physical characterization indicated that the second-batch and first-batch samples had a noticeable difference in apparent-size distributions but had similar primary-particle-size distributions. There were some differences in chemical composition between the batches, but these differences were not considered important in comparison with the differences among the end-member shales. The results of x-ray diffraction analyses showed that the second batches had mineralogical compositions very similar to the first batches. 9 refs., 9 figs., 4 tabs.« less

Lower Cretaceous dinoflagellate cyst and acritarch stratigraphy of the Cismon APTICORE (Southern Alps, Italy).

PubMed

Torricelli

2000-02-01

A pelagic sedimentary succession, virtually complete from the Upper Hauterivian to the Upper Aptian and unconformably overlain by the Middle-Upper Albian p.p., was continuously cored in the Belluno Basin (southern Alps, NE Italy) as part of the APTICORE Program. APTICORE at Cismon Valley penetrated 131.8m of limestones, marls and black shales, with 100% recovery of good quality cored material.One hundred and forty-six samples recovered from the marl and shale beds of the Cismon core were processed and analyzed for palynomorphs. Most of them yielded relatively rich and fairly well preserved assemblages of marine and terrestrially-derived palynomorphs.The results of a qualitative study of dinoflagellate cysts and acritarchs are presented and discussed. The distributions of 150 taxa are tabulated against the chronostratigraphy independently established on the basis of original litho-, bio-, chemo-, magnetostratigraphic investigations and of correlations with extensively studied sections outcropping in the vicinity of the Cismon drill site.The acritarch Pinocchiodinium erbae gen. et sp. nov. is described. Due to its distinctive morphology and extremely constant occurrence also in the black shales of the Selli Level, it is proposed as a marker species for the Aptian sediments of the Tethys.The dinoflagellate cysts Kallosphaeridium dolomiticum sp. nov. and Nexosispinum hesperus brevispinosum subsp. nov. are described from the Upper Hauterivian. Additional taxonomic remarks are made about other dinoflagellate cyst species, including the emendations of Tanyosphaeridium magneticum Davies 1983 and Bourkidinium granulatum Morgan 1975.The biostratigraphic value of selected taxa is discussed and compared with data known both from the Tethyan and Boreal realms. In particular, the extinction of Bourkidinium granulatum emend. is proposed as the best dinoflagellate cyst event for the delimitation of the Hauterivian-Barremian boundary in the Northern Hemisphere. The first appearance datums of Prolixosphaeridium parvispinum and Odontochitina operculata, and the slightly younger last appearance datum of Nexosispinum vetusculum are confirmed as useful biohorizons for recognition of the lower part of the Upper Barremian and hence for the approximation of the Lower-Upper Barremian boundary. The last occurrences of Rhynchodiniopsis aptiana and Phoberocysta neocomica are calibrated in the basal Aptian.

Diagenetic variation at the lamina scale in lacustrine organic-rich shales: Implications for hydrocarbon migration and accumulation

NASA Astrophysics Data System (ADS)

Liang, Chao; Cao, Yingchang; Liu, Keyu; Jiang, Zaixing; Wu, Jing; Hao, Fang

2018-05-01

Lacustrine carbonate-rich shales are well developed within the Mesozoic-Cenozoic strata of the Bohai Bay Basin (BBB) of eastern China and across southeast Asia. Developing an understanding of the diagenesis of these shales is essential to research on mass balance, diagenetic fluid transport and exchange, and organic-inorganic interactions in black shales. This study investigates the origin and distribution of authigenic minerals and their diagenetic characteristics, processes, and pathways at the scale of lacustrine laminae within the Es4s-Es3x shale sequence of the BBB. The research presented in this study is based on thin sections, field emission scanning electron microscope (FESEM) and SEM-catholuminescence (CL) observations of well core samples combined with the use of X-ray diffraction (XRD), energy dispersive spectroscopy, electron microprobe analysis, and carbon and oxygen isotope analyses performed using a laser microprobe mass spectrometer. The dominant lithofacies within the Es4s-Es3x sequence are a laminated calcareous shale (LCS-1) and a laminated clay shale (LCS-2). The results of this study show that calcite recrystallization1 is the overarching diagenetic process affecting the LCS-1, related to acid generation from organic matter (OM) thermal evolution. This evolutionary transition is the key factor driving the diagenesis of this lithofacies, while the transformation of clay minerals is the main diagenetic attribute of the LCS-2. Diagenetic differences occur within different laminae and at variable locations within the same lamina level, controlled by variations in mineral composition and the properties of laminae interfaces. The diagenetic fluid migration scale is vertical and responses (dissolution and replacement) are limited to individual laminae, between zero and 100 μm in width. In contrast, the dominant migration pathway for diagenetic fluid is lateral, along the abrupt interfaces between laminae boundaries, which leads to the vertical transmission of diagenetic responses. The recrystallization boundaries between calcite laminae act as the main migration pathways for the expulsion of hydrocarbons from these carbonate-rich lacustrine shales. However, because the interaction between diagenetic fluids and the shales themselves is limited to the scale of individual lamina, this system is normally closed. The occurrence of abnormal pressure fractures can open the diagenetic system, however, and cause interactions to occur throughout laminae; in particular, the closed-open (C-O) diagenetic process at this scale is critical to this shale interval. Multi-scale C-O systems are ubiquitous and episodic ranging from the scale of laminae to the whole basin. Observations show that such small-scale systems are often superimposed onto larger ones to constitute the complex diagenetic system seen within the BBB combining fluid transport, material and energy exchange, and solid-liquid and organic-inorganic interactions.

Lithofacies classification of the Barnett Shale gas reservoir using neural network

NASA Astrophysics Data System (ADS)

Aliouane, Leila; Ouadfeul, Sid-Ali

2017-04-01

Here, we show the contribution of the artificial intelligence such as neural network to predict the lithofacies in the lower Barnett shale gas reservoir. The Multilayer Perceptron (MLP) neural network with Hidden Weight Optimization Algorithm is used. The input is raw well-logs data recorded in a horizontal well drilled in the Lower Barnett shale formation, however the output is the concentration of the Clay and the Quartz calculated using the ELAN model and confirmed with the core rock measurement. After training of the MLP machine weights of connection are calculated, the raw well-logs data of two other horizontal wells drilled in the same reservoir are propagated though the neural machine and an output is calculated. Comparison between the predicted and measured clay and Quartz concentrations in these two horizontal wells shows the ability of neural network to improve shale gas reservoirs characterization.

Research core drilling in the Manson impact structure, Iowa

NASA Technical Reports Server (NTRS)

Anderson, R. R.; Hartung, J. B.; Roddy, D. J.; Shoemaker, E. M.

1992-01-01

The Manson impact structure (MIS) has a diameter of 35 km and is the largest confirmed impact structure in the United States. The MIS has yielded a Ar-40/Ar-39 age of 65.7 Ma on microcline from its central peak, an age that is indistinguishable from the age of the Cretaceous-Tertiary boundary. In the summer of 1991 the Iowa Geological Survey Bureau and U.S. Geological Survey initiated a research core drilling project on the MIS. The first core was beneath 55 m of glacial drift. The core penetrated a 6-m layered sequence of shale and siltstone and 42 m of Cretaceous shale-dominated sedimentary clast breccia. Below this breccia, the core encountered two crystalline rock clast breccia units. The upper unit is 53 m thick, with a glassy matrix displaying various degrees of devitrification. The upper half of this unit is dominated by the glassy matrix, with shock-deformed mineral grains (especially quartz) the most common clast. The glassy-matrix unit grades downward into the basal unit in the core, a crystalline rock breccia with a sandy matrix, the matrix dominated by igneous and metamorphic rock fragments or disaggregated grains from those rocks. The unit is about 45 m thick, and grains display abundant shock deformation features. Preliminary interpretations suggest that the crystalline rock breccias are the transient crater floor, lifted up with the central peak. The sedimentary clast breccia probably represents a postimpact debris flow from the crater rim, and the uppermost layered unit probably represents a large block associated with the flow. The second core (M-2) was drilled near the center of the crater moat in an area where an early crater model suggested the presence of postimpact lake sediments. The core encountered 39 m of sedimentary clast breccia, similar to that in the M-1 core. Beneath the breccia, 120 m of poorly consolidated, mildly deformed, and sheared siltstone, shale, and sandstone was encountered. The basal unit in the core was another sequence of sedimentary clast breccia. The two sedimentary clast units, like the lithologically similar unit in the M-1 core, probably formed as debris flows from the crater rim. The middle, nonbrecciated interval is probably a large, intact block of Upper Cretaceous strata transported from the crater rim with the debris flow. Alternatively, the sequence may represent the elusive postimpact lake sequence.

The Architecture and Frictional Properties of Faults in Shale

NASA Astrophysics Data System (ADS)

De Paola, N.; Imber, J.; Murray, R.; Holdsworth, R.

2015-12-01

The geometry of brittle fault zones in shale rocks, as well as their frictional properties at reservoir conditions, are still poorly understood. Nevertheless, these factors may control the very low recovery factors (25% for gas and 5% for oil) obtained during fracking operations. Extensional brittle fault zones (maximum displacement < 3 m) cut exhumed oil mature black shales in the Cleveland Basin (UK). Fault cores up to 50 cm wide accommodated most of the displacement, and are defined by a stair-step geometry. Their internal architecture is characterised by four distinct fault rock domains: foliated gouges; breccias; hydraulic breccias; and a slip zone up to 20 mm thick, composed of a fine-grained black gouge. Hydraulic breccias are located within dilational jogs with aperture of up to 20 cm. Brittle fracturing and cataclastic flow are the dominant deformation mechanisms in the fault core of shale faults. Velocity-step and slide-hold-slide experiments at sub-seismic slip rates (microns/s) were performed in a rotary shear apparatus under dry, water and brine-saturated conditions, for displacements of up to 46 cm. Both the protolith shale and the slip zone black gouge display shear localization, velocity strengthening behaviour and negative healing rates, suggesting that slow, stable sliding faulting should occur within the protolith rocks and slip zone gouges. Experiments at seismic speed (1.3 m/s), performed on the same materials under dry conditions, show that after initial friction values of 0.5-0.55, friction decreases to steady-state values of 0.1-0.15 within the first 10 mm of slip. Contrastingly, water/brine saturated gouge mixtures, exhibit almost instantaneous attainment of very low steady-state sliding friction (0.1), suggesting that seismic ruptures may efficiently propagate in the slip zone of fluid-saturated shale faults. Stable sliding in faults in shale can cause slow fault/fracture propagation, affecting the rate at which new fracture areas are created and, hence, limiting oil and gas production during reservoir stimulation. However, fluid saturated conditions can favour seismic slip propagation, with fast and efficient creation of new fracture areas. These processes are very effective at dilational jogs, where fluid circulation may be enhanced, facilitating oil and gas production.

Leaching of polycyclic aromatic hydrocarbons from oil shale processing waste deposit: a long-term field study.

PubMed

Jefimova, Jekaterina; Irha, Natalya; Reinik, Janek; Kirso, Uuve; Steinnes, Eiliv

2014-05-15

The leaching behavior of selected polycyclic aromatic hydrocarbons (PAHs) from an oil shale processing waste deposit was monitored during 2005-2009. Samples were collected from the deposit using a special device for leachate sampling at field conditions without disturbance of the upper layers. Contents of 16 priority PAHs in leachate samples collected from aged and fresh parts of the deposit were determined by GC-MS. The sum of the detected PAHs in leachates varied significantly throughout the study period: 19-315 μg/l from aged spent shale, and 36-151 μg/l from fresh spent shale. Among the studied PAHs the low-molecular weight compounds phenanthrene, naphthalene, acenaphthylene, and anthracene predominated. Among the high-molecular weight PAHs benzo[a]anthracene and pyrene leached in the highest concentrations. A spent shale deposit is a source of PAHs that could infiltrate into the surrounding environment for a long period of time. Copyright © 2014 Elsevier B.V. All rights reserved.

Investigation of Controlling Factors Impacting Water Quality in Shale Gas Produced Brine

NASA Astrophysics Data System (ADS)

Fan, W.; Hayes, K. F.; Ellis, B. R.

2014-12-01

The recent boom in production of natural gas from unconventional reservoirs has generated a substantial increase in the volume of produced brine that must be properly managed to prevent contamination of fresh water resources. Produced brine, which includes both flowback and formation water, is often highly saline and may contain elevated concentrations of naturally occurring radioactive material and other toxic elements. These characteristics present many challenges with regard to designing effective treatment and disposal strategies for shale gas produced brine. We will present results from a series of batch experiments where crushed samples from two shale formations in the Michigan Basin, the Antrim and Utica-Collingwood shales, were brought into contact with synthetic hydraulic fracturing fluids under in situ temperature and pressure conditions. The Antrim has been an active shale gas play for over three decades, while the Utica-Collingwood formation (a grouped reservoir consisting of the Utica shale and Collingwood limestone) is an emerging shale gas play. The goal of this study is to investigate the influence of water-rock interactions in controlling produced water quality. We evaluate toxic element leaching from shale samples in contact with model hydraulic fracturing fluids under system conditions corresponding to reservoir depths up to 1.5 km. Experimental results have begun to elucidate the relative importance of shale mineralogy, system conditions, and chemical additives in driving changes in produced water quality. Initial results indicate that hydraulic fracturing chemical additives have a strong influence on the extent of leaching of toxic elements from the shale. In particular, pH was a key factor in the release of uranium (U) and divalent metals, highlighting the importance of the mineral buffering capacity of the shale. Low pH values persisted in the Antrim and Utica shale experiments and resulted in higher U extraction efficiencies than that observed in the presence of the carbonate-rich Collingwood limestone. In addition to assessing U leaching, we also measured the activity of 226Ra and 228Ra via high-resolution gamma ray spectroscopy. Laboratory results will be compared to observations from a complimentary field sampling campaign of Antrim produced brine.

Shallow Carbon Sequestration Demonstration Project

DOE Office of Scientific and Technical Information (OSTI.GOV)

Pendergrass, Gary; Fraley, David; Alter, William

The potential for carbon sequestration at relatively shallow depths was investigated at four power plant sites in Missouri. Exploratory boreholes were cored through the Davis Shale confining layer into the St. Francois aquifer (Lamotte Sandstone and Bonneterre Formation). Precambrian basement contact ranged from 654.4 meters at the John Twitty Energy Center in Southwest Missouri to over 1100 meters near the Sioux Power Plant in St. Charles County. Investigations at the John Twitty Energy Center included 3D seismic reflection surveys, downhole geophysical logging and pressure testing, and laboratory analysis of rock core and water samples. Plans to perform injectivity tests atmore » the John Twitty Energy Center, using food grade CO{sub 2}, had to be abandoned when the isolated aquifer was found to have very low dissolved solids content. Investigations at the Sioux Plant and Thomas Hill Energy Center in Randolph County found suitably saline conditions in the St. Francois. A fourth borehole in Platte County was discontinued before reaching the aquifer. Laboratory analyses of rock core and water samples indicate that the St. Charles and Randolph County sites could have storage potentials worthy of further study. The report suggests additional Missouri areas for further investigation as well.« less

DOE Office of Scientific and Technical Information (OSTI.GOV)

DiStefano, Victoria H.; McFarlane, Joanna; Anovitz, Lawrence M.

This study is an attempt to understand how native organics are distributed with respect to pore size to determine the relationship between hydrocarbon chemistry and pore structure in shales, as the location and accessibility of hydrocarbons is key to understanding and improving the extractability of hydrocarbons in hydraulic fracturing. Selected shale cores from the Eagle Ford and Marcellus formations were subjected to pyrolysis gas chromatography (GC), thermogravimetric analysis, and organic solvent extraction with the resulting effluent analyzed by GC-mass spectrometry (MS). Organics representing the oil and gas fraction (0.1 to 1 wt. %) were observed by GC-MS. For most ofmore » the samples, the amount of native organic extracted directly related to the percentage of clay in the shale. The porosity and pore size distribution (0.95 nm to 1.35 m) in the Eagle Ford and Marcellus shales was measured before and after solvent extraction using small angle neutron scattering (SANS). An unconventional method was used to quantify the background from incoherent scattering as the Porod transformation obscures the Bragg peak from the clay minerals. Furthermore, the change in porosity from SANS is indicative of the extraction or breakdown of higher molecular weight bitumen with high C/H ratios (asphaltenes and resins). This is mostly likely attributed to complete dissolution or migration of asphaltenes and resins. These longer carbon chain lengths, C30-C40, were observed by pyrolysis GC, but either were too heavy to be analyzed in the extracts by GC-MS or were not effectively leached into the organic solvents. Thus, experimental limitations meant that the amount of extractable material could not be directly correlated to the changes in porosity measured by SANS. But, the observable porosity generally increased with solvent extraction. A decrease in porosity after extraction as observed in a shale with high clay content and low maturity was attributed to swelling of pores with solvent uptake or migration of resins and asphaltenes.« less

A Late Cambrian Carbon Isotope Excursion Recorded in Passive Margin Dolostones of the Central Appalachian Basin, USA.

NASA Astrophysics Data System (ADS)

Mackey, J. E.; Stewart, B. W.

2016-12-01

A Late Cambrian global positive carbon isotope excursion, known as the SPICE event [1,2] is linked to possible widespread ocean anoxia and enhanced carbon burial [3,4]. We report data from the central Appalachian Conasauga Group from the upper portion of the Middle Cambrian Maryville limestone, through the Late Cambrian Nolichucky shale and Maynardville limestone members. A geochemical, macro-, and micro-scale analyses of core material from southeastern Ohio was carried out to further constrain the timing of oceanic anoxia and trace element geochemistry relative to sediment fluxes occurring at the transition of the Middle to Late Cambrian. The section represents condensed, passive margin shale deposition and carbonate ramp development on the continental shelf of Laurentia. Carbonate sediments (primarily diagenetic dolomite) record a positive δ13C (relative to V-PDB) excursion starting in the upper Nolichucky shale member, reaching its peak (+4.0) in the overlying Maynardville limestone. At this location, there is an offset between the onlap Nolichucky shale deposition and start of the C isotope excursion; this was reported as well in a carbonate section further south of this location [2], on the other side of an extensional feature (Rome Trough) that formed a deep marine basin during Cambrian time. The condensed shale package and relatively low TOC content in our samples is likely due to the combination of a shallow, upslope basin location and isostatic influence on passive margin sedimentation. However, within the Rome Trough, the Nolichucky shale is rich in organic carbon and a recent target of hydrocarbon exploration. The data suggest a possible link between deposition of this shale and the global SPICE event. The robustness of the Late Cambrian δ13C excursion in diagenetically altered sediments and association with hydrocarbon bearing units indicates its utility as a stratigraphic indicator and as a target for exploration. Ongoing geochemical work will focus on trace element and isotopic signatures preserved in the carbonate portion of sediments spanning the C isotope excursion. Refs: [1] Saltzman et al., 1998, Geol. Soc. Am. Bull. 110, 285-297; [2] Glumac and Walker, 1998, J. Sed. Res. 68, 1212-1222; [3] Hurtgen et al., 2009, Earth Planet. Sci. Lett. 281, 288-297; [4] Gill et al., 2011, Nature 469, 80-83.

Quantitative prediction of fractures using the finite element method: A case study of the lower Silurian Longmaxi Formation in northern Guizhou, South China

NASA Astrophysics Data System (ADS)

Liu, Jingshou; Ding, Wenlong; Yang, Haimeng; Jiu, Kai; Wang, Zhe; Li, Ang

2018-04-01

Natural fractures have long been considered important factors in the production of gas from shale reservoirs because they can connect pore spaces and enlarge transport channels, thereby influencing the migration, accumulation and preservation of shale gas. Industrial-level shale gas production has been initiated in the lower Silurian Longmaxi Formation in northern Guizhou, South China. However, it is important to quantitatively predict the distribution of natural fractures in the lower Silurian shale reservoirs to locate additional 'sweet spots' in northern Guizhou. In this study, data obtained from outcrops, cores, thin sections, field-emission scanning electron microscope (FE-SEM) images and X-ray diffraction (XRD) were used to determine the developmental characteristics and controlling factors of these fractures. Correlation analysis indicated that the mechanical parameters of the Longmaxi shale are mainly related to the total organic carbon (TOC), quartz, clay, calcite and dolomite contents. The spatial variations in the mechanical parameters of the Longmaxi shale were determined based on the spatial variations in the TOC and mineral contents. Then, a heterogeneous geomechanical model of the study area was established based on interpretations of the fault systems derived from seismic data and acoustic emission (AE) experiments performed on samples of the relevant rocks. The paleotectonic stress fields during the Yanshanian period were obtained using the finite element method (FEM). Finally, a fracture density calculation model was established to analyze the quantitative development of fractures, and the effects of faults and mechanical parameters on the development of fractures were determined. The results suggest that the main developmental period of tectonic fractures in the Longmaxi Formation was the Early Yanshanian period. During this time, the horizontal principal stress conditions were dominated by a SE-NW-trending (135-315°) compressional stress field, and the Longmaxi Formation experienced a maximum tectonic stress of 110-120 MPa. This simulated paleotectonic stress field was mainly controlled by faults and the contents of TOC, quartz, clay, calcite and dolomite; at different positions along the same fault, the degree of fracture development varies significantly. Overall, the distribution of fractures in the Longmaxi Formation can be used to optimize well deployment and provides a basis for the future exploration of shale gas.

High-resolution seismic reflection to delineate shallow gas in Eastern Kansas

USGS Publications Warehouse

Miller, R.D.; Watney, W.L.; Begay, D.K.; Xia, J.

2000-01-01

Unique amplitude characteristics of shallow gas sands within Pennsylvanian clastic-carbonate dominated sequences are discernible on high-resolution seismic reflection data in eastern Kansas. Upward grading sequences of sand into shale represent a potential gas reservoir with a low-impedence acoustic contrast at the base of the encasing layer. The gas sand and encasing shale, which define the gas reservoir studied here, are part of an erosional incised valley where about 30 m of carbonates and shale have been replaced by sandstone and shale confined to the incised valley. These consolidated geologic settings would normally possess high impedence gas sand reservoirs as defined by abrupt contacts between the gas sand and encasing shale. Based orr core and borehole logs, the gas sand studied here grades from sand into shale in a fashion analogous to that observed in classic low-impedance environments. Amplitude and phase characteristics of high-resolution seismic data across this approximately 400-m wide gas sand are indicative of a low-impedance reservoir. Shot gathers possess classic amplitude with offsett-dependent characteristics which are manifeted on the stacked section as "bright spots." Dominant Frequencies of around 120 Hz allow detection of several reflectors within the 30+ meters of sand/shale that make up this localized gas-rich incised valley fill. The gradational nature of the trapping mechanism observed in this gas reservoir would make detection with conventional seismic reflection methods unlikely.

Organic metamorphism in the Lower Mississippian-Upper Devonian Bakken shales. Part 1: Rock-Eval pyrolysis and vitrinite reflectance.

USGS Publications Warehouse

Price, L.C.; Daws, T.; Pawlewicz, M.

1986-01-01

The Williston basin is an intracratonic basin extending across parts of several states, principally North Dakota, on the US/Canadian frontier. A sequence of up to 16 000 ft of Phanerozoic rocks exists in the basin; the Bakken formation is a relatively thin clastic unit composed of three members, of which the middle one is a black shale. Both core chip and cutting chip samples from a series of widely-distributed well locations were taken for laboratory analysis. Pyrolysis data showed 'wide variations' in maturity indices in samples from equivalent depths at different well locations. This suggests that a number of different palaeoheat-flow regimes have existed in the basin, resulting in the optimization of hydrocarbon formation processes at varying depths at different localities. The vitrinite reflectance profiles presented illustrate the expected trend of linearly-increasing maturity with depth to around 6500 ft. Between 6700 and 10 000 ft, however, this trend is interrupted by two 'reversals'. It is suggested that these reversals are due to suppression of the vitrinite reflectance values in samples with high concentrations of H-rich organic matter, and that they may therefore be associated with transitions from 'terrestrial-derived' to marine-depositional conditions. Consequently, the precise identification of the thresholds of intense hydrocarbon generation within the basin is problematic.-J.M.H.

Assessment of hydrocarbon source rock potential of Polish bituminous coals and carbonaceous shales

USGS Publications Warehouse

Kotarba, M.J.; Clayton, J.L.; Rice, D.D.; Wagner, M.

2002-01-01

We analyzed 40 coal samples and 45 carbonaceous shale samples of varying thermal maturity (vitrinite reflectance 0.59% to 4.28%) from the Upper Carboniferous coal-bearing strata of the Upper Silesian, Lower Silesian, and Lublin basins, Poland, to evaluate their potential for generation and expulsion of gaseous and liquid hydrocarbons. We evaluated source rock potential based on Rock-Eval pyrolysis yield, elemental composition (atomic H/C and O/C), and solvent extraction yields of bitumen. An attempt was made to relate maceral composition to these source rock parameters and to composition of the organic matter and likely biological precursors. A few carbonaceous shale samples contain sufficient generation potential (pyrolysis assay and elemental composition) to be considered potential source rocks, although the extractable hydrocarbon and bitumen yields are lower than those reported in previous studies for effective Type III source rocks. Most samples analysed contain insufficient capacity for generation of hydrocarbons to reach thresholds required for expulsion (primary migration) to occur. In view of these findings, it is improbable that any of the coals or carbonaceous shales at the sites sampled in our study would be capable of expelling commercial amounts of oil. Inasmuch as a few samples contained sufficient generation capacity to be considered potential source rocks, it is possible that some locations or stratigraphic zones within the coals and shales could have favourable potential, but could not be clearly delimited with the number of samples analysed in our study. Because of their high heteroatomic content and high amount of asphaltenes, the bitumens contained in the coals are less capable of generating hydrocarbons even under optimal thermal conditions than their counterpart bitumens in the shales which have a lower heteroatomic content. Published by Elsevier Science B.V.

Rhenium and osmium isotopes in black shales and Ni-Mo-PGE-rich sulfide layers, Yukon Territory, Canada, and Hunan and Guizhou provinces, China

USGS Publications Warehouse

Horan, M.F.; Morgan, J.W.; Grauch, R.I.; Coveney, R.M.; Murowchick, J.B.; Hulbert, L.J.

1994-01-01

Rhenium and osmium abundances and osmium isotopic compositions were determined by negative thermal ionization mass spectrometry for samples of Devonian black shale and an associated Ni-enriched sulfide layer from the Yukon Territory, Canada. The same composition information was also obtained for samples of early Cambrian Ni-Mo-rich sulfide layers hosted in black shale in Guizhou and Hunan provinces, China. This study was undertaken to constrain the origin of the PGE enrichment in the sulfide layers. Samples of the Ni sulfide layer from the Yukon Territory are highly enriched in Re, Os, and other PGE, with distinctly higher Re/192Os but similar Pt/Re, compared to the black shale host. Re-Os isotopic data of the black shale and the sulfide layer are approximately isochronous, and the data plot close to reference isochrons which bracket the depositional age of the enclosing shales. Samples of the Chinese sulfide layers are also highly enriched in Re, Os, and the other PGE. Re/192Os are lower than in the Yukon sulfide layer. Re-Os isotopic data for the sulfide layers lie near a reference isochron with an age of 560 Ma, similar to the depositional age of the black shale host. The osmium isotopic data suggest that Re and PGE enrichment of the brecciated sulfide layers in both the Yukon Territory and in southern China may have occurred near the time of sediment deposition or during early diagenesis, during the middle to late Devonian and early Cambrian, respectively. ?? 1994.

Comparison between results of detailed tectonic studies on borehole core vs microresistivity images of borehole wall from gas-bearing shale complexes, Baltic Basin, Poland.

NASA Astrophysics Data System (ADS)

Bobek, Kinga; Jarosiński, Marek; Pachytel, Radomir

2017-04-01

Structural analysis of borehole core and microresistivity images yield an information about geometry of natural fracture network and their potential importance for reservoir stimulation. Density of natural fractures and their orientation in respect to the maximum horizontal stress has crucial meaning for hydraulic fractures propagation in unconventional reservoirs. We have investigated several hundred meters of continuous borehole core and corresponding microresistivity images (mostly XRMI) from six boreholes in the Pomeranian part of the Early Paleozoic Baltic Basin. In general, our results challenge the question about representatives of statistics based on structural analyses on a small shale volume represented by borehole core or borehole wall images and credibility of different sets of data. Most frequently, fractures observed in both XRMI and cores are steep, small strata-bound fractures and veins with minor mechanical aperture (0,1 mm in average). These veins create an orthogonal joint system, locally disturbed by fractures associated with normal or by gently dipping thrust faults. Mean fractures' height keeps in a range between 30-50 cm. Fracture density differs significantly among boreholes and Consistent Lithological Units (CLUs) but the most frequent means falls in a range 2-4 m-1. We have also payed an attention to bedding planes due to their expected coupling with natural fractures and their role as structural barriers for vertical fracture propagation. We aimed in construction for each CLU the so-called "mean brick", which size is limited by an average distance between two principal joint sets and between bedding fractures. In our study we have found out a discrepancy between structural profiles based on XRMI and core interpretation. For some CLUs joint fractures densities, are higher in cores than in XRMI. In this case, numerous small fractures were not recorded due to the limits of XRMI resolution. However, the most veins with aperture 0,1 mm, cemented with calcite, were clearly visible in scanner image. We have also observed significantly lower density of veins in core than in the XRMI that occurs systematically in one formation enriched with carbonate and dolomite. In this case, veins are not fractured in core and obliterated for bare eye by dolomitization, but are still contrastive in respect of electric resistance. Calculated density of bedding planes per 1 meter reveals systematically higher density of fractures observed on core than in the XRMI (depicted automatically by interpretation program). This difference may come from additional fracking due to relaxation of borehole core while recovery. Comparison of vertical joint fractures density with thickness of mechanical beds shows either lack of significant trends or a negative correlation (greater density of bedding fractures correspond to lower density of joints). This result, obtained for shale complexes contradict that derived for sandstone or limestone. Boundary between CLUs are visible on both: joint and bedding fracture density profiles. Considering small-scale faults and slickensides we have obtained good agreement between results of core and scanner interpretation. This study in the frame of ShaleMech Project funded by Polish Committee for Scientific Research is in progress and the results are preliminary.

Physical and chemical characterization of Devonian gas shale. Quarterly status report, October 1-December 31, 1978

DOE Office of Scientific and Technical Information (OSTI.GOV)

Zielinski, R.E.; Nance, S.W.

On shale samples from the WV-6 (Monongalia County, West Virginia) well, mean total gas yield was 80.4 ft/sup 3//ton. Mean hydrocarbon gas yield was 5.7 ft/sup 3//ton, 7% of total yield. Methane was the major hydrocarbon component and carbon dioxide the major nonhydrocarbon component. Oil yield was negligible. Clay minerals and organic matter were the dominant phases of the shale. Illite averages 76% of the total clay mineral content. This is detrital illite. Permeation of methane, parallel to the bedding direction for select samples from WV-5 (Mason County, West Virginia) well ranges from 10/sup -4/ to 10/sup -12/ darcys. Themore » permeability of these shales is affected by orgaic carbon content, density, particle orientation, depositional facies, etc. Preliminary studies of Devonian shale methane sorption rates suggest that these rates may be affected by shale porosity, as well as absorption and adsorption processes. An experimental system was designed to effectively simulate sorption of methane at natural reservoir conditions. The bulk density and color of select shales from Illinois, Appalachian and Michigan Basins suggest a general trend of decreasing density with increasing organic content. Black and grayish black shales have organic contents which normally exceed 1.0 wt %. Medium dark gray and gray shales generally have organic contents less than 1.0 wt %.« less

Multivariate analysis relating oil shale geochemical properties to NMR relaxometry

USGS Publications Warehouse

Birdwell, Justin E.; Washburn, Kathryn E.

2015-01-01

Low-field nuclear magnetic resonance (NMR) relaxometry has been used to provide insight into shale composition by separating relaxation responses from the various hydrogen-bearing phases present in shales in a noninvasive way. Previous low-field NMR work using solid-echo methods provided qualitative information on organic constituents associated with raw and pyrolyzed oil shale samples, but uncertainty in the interpretation of longitudinal-transverse (T1–T2) relaxometry correlation results indicated further study was required. Qualitative confirmation of peaks attributed to kerogen in oil shale was achieved by comparing T1–T2 correlation measurements made on oil shale samples to measurements made on kerogen isolated from those shales. Quantitative relationships between T1–T2 correlation data and organic geochemical properties of raw and pyrolyzed oil shales were determined using partial least-squares regression (PLSR). Relaxometry results were also compared to infrared spectra, and the results not only provided further confidence in the organic matter peak interpretations but also confirmed attribution of T1–T2 peaks to clay hydroxyls. In addition, PLSR analysis was applied to correlate relaxometry data to trace element concentrations with good success. The results of this work show that NMR relaxometry measurements using the solid-echo approach produce T1–T2 peak distributions that correlate well with geochemical properties of raw and pyrolyzed oil shales.

Seal evaluation and confinement screening criteria for beneficial carbon dioxide storage with enhanced coal bed methane recovery in the Pocahontas Basin, Virginia

USGS Publications Warehouse

Grimm, R.P.; Eriksson, K.A.; Ripepi, N.; Eble, C.; Greb, S.F.

2012-01-01

The geological storage of carbon dioxide in Appalachian basin coal seams is one possible sink for sequestration of greenhouse gases, with the added benefit of enhanced-coal bed methane (ECBM) recovery. The Pocahontas Basin (part of the central Appalachian Basin) of southwestern Virginia is a major coal bed methane (CBM) province with production mostly from coal beds in the Lower Pennsylvanian Pocahontas and New River formations. As part of the Southeast Regional Carbon Sequestration Partnership's Phase II research program, a CO 2-injection demonstration well was installed into Lower Pennsylvanian coal bed-methane producing strata in southwest Virginia. Samples of siliciclastic lithologies above coal beds in this Oakwood Field well, and from several other cores in the Nora Field were taken to establish a baseline of the basic confinement properties of overlying strata to test seal competency at local and regional scales.Strata above CBM-producing coal beds in the Pocahontas and New River formations consist of dark-gray shales; silty gray shales; heterolithic siltstones, sandstones, and shales; lithic sandstones, and quartzose sandstones. Standard measurements of porosity, permeability and petrography were used to evaluate potential leakage hazards and any possible secondary storage potential for typical lithologies. Both lithic- and quartz-rich sandstones exhibit only minor porosity, with generally low permeability (<0.042mD). Interconnected porosity and permeability are strongly impacted by diverse cementation types and compaction. Analyzed siliciclastic lithologies are considered tight, with limited primary matrix permeability risks for leakage, providing an ensemble of redundant CO 2-ECBM traps.One of the most promising confining intervals above the major coal bed-methane producing interval is the Hensley Shale Member. Analyses of 1500 geophysical logs in southwest Virginia indicate that this unit is moderately thick (>50ft, 15m), laterally continuous (>3000km 2), and a homogenous shale, which coarsens upward into siltstone and sandstone, or is truncated by sandstone. Calculations from two mercury injection capillary porosimetry tests of the shale indicate that a displacement entry pressure of 207psi (1427kPa) would generate an estimated seal capacity of 1365ft (416m) of CO 2 before buoyant leakage. Scanning electron microscopy indicates a microfabric of narrow pore throats between quartz grains floating in a clay matrix. Modeled median pore throat size between micro-fabric matrix grains for the shale is estimated at 0.26??m. These characteristics indicate that the shale, where fractures and joints are limited, would be an adequate regional confining interval for deeper CO 2 storage with ECBM. ?? 2011 Elsevier B.V.

Determination of maximal amount of minor gases adsorbed in a shale sample by headspace gas chromatography.

PubMed

Zhang, Chun-Yun; Hu, Hui-Chao; Chai, Xin-Sheng; Pan, Lei; Xiao, Xian-Ming

2014-02-07

In this paper, we present a novel method for determining the maximal amount of ethane, a minor gas species, adsorbed in a shale sample. The method is based on the time-dependent release of ethane from shale samples measured by headspace gas chromatography (HS-GC). The study includes a mathematical model for fitting the experimental data, calculating the maximal amount gas adsorbed, and predicting results at other temperatures. The method is a more efficient alternative to the isothermal adsorption method that is in widespread use today. Copyright © 2013 Elsevier B.V. All rights reserved.

Preliminary source rock evaluation and hydrocarbon generation potential of the early Cretaceous subsurface shales from Shabwah sub-basin in the Sabatayn Basin, Western Yemen

NASA Astrophysics Data System (ADS)

Al-Matary, Adel M.; Hakimi, Mohammed Hail; Al Sofi, Sadam; Al-Nehmi, Yousif A.; Al-haj, Mohammed Ail; Al-Hmdani, Yousif A.; Al-Sarhi, Ahmed A.

2018-06-01

A conventional organic geochemical study has been performed on the shale samples collected from the early Cretaceous Saar Formation from the Shabwah oilfields in the Sabatayn Basin, Western Yemen. The results of this study were used to preliminary evaluate the potential source-rock of the shales in the Saar Formation. Organic matter richness, type, and petroleum generation potential of the analysed shales were assessed. Total organic carbon content and Rock- Eval pyrolysis results indicate that the shale intervals within the early Cretaceous Saar Formation have a wide variation in source rock generative potential and quality. The analysed shale samples have TOC content in the range of 0.50 and 5.12 wt% and generally can be considered as fair to good source rocks. The geochemical results of this study also indicate that the analysed shales in the Saar Formation are both oil- and gas-prone source rocks, containing Type II kerogen and mixed Types II-III gradient to Type III kerogen. This is consistent with Hydrogen Index (HI) values between 66 and 552 mg HC/g TOC. The temperature-sensitive parameters such as vitrinite reflectance (%VRo), Rock-Eval pyrolysis Tmax and PI reveal that the analysed shale samples are generally immature to early-mature for oil-window. Therefore, the organic matter has not been altered by thermal maturity thus petroleum has not yet generated. Therefore, exploration strategies should focus on the known deeper location of the Saar Formation in the Shabwah-sub-basin for predicting the kitchen area.

Water sources and disposal related to hydraulic fracturing in the Barnett Shale: a historical perspective

NASA Astrophysics Data System (ADS)

Nicot, J.; Scanlon, B. R.

2013-12-01

During the past few years, hydraulic fracturing (HF) has become a hotly debated topic particularly related to volume of water used and potential for contamination of shallow aquifers. In this communication, we focused on water use in the oldest shale play in the world as an example for an analysis of historical patterns of water use, consumption, and disposal. The Barnett Shale play in Texas provides an ideal case to assess some of the issues related to shale gas production. It was the first shale play to submit to intense slick-water HF (first horizontal wells in 2003, ~15,000 horizontal wells completed to date). An estimated 200, 000 acre-feet (247 million m3) of water has been used so far in the play (included for vertical wells), mostly in the 4-5 counties making up the core area. More than 90% of the water used is consumed and relatively little recycling occurs in the play. Most of the flowback / produced water is disposed of through injection wells. The median Barnett horizontal well produces back ~100% of the amount of water injected for fracturing in the course of the few years following completion, an amount larger than other well-known shale gas plays. The communication will provide detailed material documenting these findings.

Mineral Reactions in Shale Gas Reservoirs: Barite Scale Formation from Reusing Produced Water As Hydraulic Fracturing Fluid.

PubMed

Paukert Vankeuren, Amelia N; Hakala, J Alexandra; Jarvis, Karl; Moore, Johnathan E

2017-08-15

Hydraulic fracturing for gas production is now ubiquitous in shale plays, but relatively little is known about shale-hydraulic fracturing fluid (HFF) reactions within the reservoir. To investigate reactions during the shut-in period of hydraulic fracturing, experiments were conducted flowing different HFFs through fractured Marcellus shale cores at reservoir temperature and pressure (66 °C, 20 MPa) for one week. Results indicate HFFs with hydrochloric acid cause substantial dissolution of carbonate minerals, as expected, increasing effective fracture volume (fracture volume + near-fracture matrix porosity) by 56-65%. HFFs with reused produced water composition cause precipitation of secondary minerals, particularly barite, decreasing effective fracture volume by 1-3%. Barite precipitation occurs despite the presence of antiscalants in experiments with and without shale contact and is driven in part by addition of dissolved sulfate from the decomposition of persulfate breakers in HFF at reservoir conditions. The overall effect of mineral changes on the reservoir has yet to be quantified, but the significant amount of barite scale formed by HFFs with reused produced water composition could reduce effective fracture volume. Further study is required to extrapolate experimental results to reservoir-scale and to explore the effect that mineral changes from HFF interaction with shale might have on gas production.

Preliminary evaluation of the shale gas prospectivity of the Lower Cretaceous Pearsall Formation in the onshore Gulf Coast region, United States

USGS Publications Warehouse

Enomoto, Catherine B.; Scott, Kristina; Valentine, Brett J.; Hackley, Paul C.; Dennen, Kristin; Lohr, Celeste D.

2012-01-01

Recent work by the U.S. Geological Survey indicated that the Lower Cretaceous Pearsall Formation contains an estimated mean undiscovered, technically recoverable unconventional gas resource of 8.8 trillion cubic ft in the Maverick Basin, South Texas. Cumulative gas production from horizontal wells in the core area of the emerging play has exceeded 5 billion cubic ft since 2008. However, very little information is available to characterize the Pearsall Formation as an unconventional gas resource beyond the Maverick Basin in the greater Gulf Coast region. Therefore, this reconnaissance study examines spatial distribution, thickness, organic richness and thermal maturity of the Pearsall Formation in the onshore U.S. Gulf states using wireline logs and drill cuttings sample analysis. Spontaneous potential and resistivity curves of approximately forty wireline logs from wells in five Gulf Coast states were correlated to ascertain the thickness of the Pearsall Formation and delineate its three members: Pine Island Shale, James Limestone or Cow Creek Limestone, and Bexar Shale, in ascending stratigraphic order. In Florida and Alabama the Pearsall Formation is up to about 300 ft thick; in Mississippi, Louisiana, Arkansas, and East Texas, thickness is up to as much as 800 ft. Drill cuttings sampled from 11 wells at depths ranging from 4600 to 19,600 feet subsurface indicate increasingly oxygenated depositional environments (predominance of red shale) towards the eastern part of the basin. Cuttings vary widely in lithology but indicate interbedded clastics and limestones throughout the Pearsall Formation, consistent with previous regional studies. Organic petrographic and geochemical analyses of 17 cutting samples in the Pearsall Formation indicate a wide range in thermal maturity, from immature (0.43% Ro [vitrinite reflectance]) in paleo-high structural locations to the peak oil window (0.99% Ro) in the eastern portion of the Gulf Coast Basin. This is in contrast to dry gas thermal maturity throughout the Pearsall Formation in the South Texas Maverick Basin. Organic carbon content is low overall, even in immature samples, with a range of 0.17 to 1.08 wt.% by Leco in 22 Pearsall Formation samples. The pyrolysis output range was 0.23 to 2.33 mg hydrocarbon/g rock. The thermal maturity and Rock-Eval pyrolysis data and organic petrologic observations from this study will be used to better focus specific areas of investigation where the Pearsall Formation may be prospective as an unconventional hydrocarbon source and reservoir.

Vertical hydraulic conductivity measurements in the Denver Basin, Colorado

USGS Publications Warehouse

Barkmann, P.E.

2004-01-01

The Denver Basin is a structural basin on the eastern flank of the Rocky Mountain Front Range, Colorado, containing approximately 3000 ft of sediments that hold a critical groundwater resource supplying many thousands of households with water. Managing this groundwater resource requires understanding how water gets into and moves through water-bearing layers in a complex multiple-layered sedimentary sequence. The Denver Basin aquifer system consists of permeable sandstone interbedded with impermeable shale that has been subdivided into four principle aquifers named, in ascending order, the Laramie-Fox Hills, Arapahoe, Denver, and Dawson aquifers. Although shale can dominate the stratigraphic interval containing the aquifers, there is very little empirical data regarding the hydrogeologic properties of the shale layers that control groundwater flow in the basin. The amount of water that flows vertically within the basin is limited by the vertical hydraulic conductivity through the confining shale layers. Low vertical flow volumes translate to low natural recharge rates and can have a profound negative impact on long-term well yields and the economic viability of utilizing the resource. To date, direct measurements of vertical hydraulic conductivity from cores of fine-grained sediments have been published from only five locations; and the data span a wide range from 1??10-3 to 1??10-11 cm/sec. This range may be attributable, in part, to differences in sample handling and analytical methods; however, it may also reflect subtle differences in the lithologic characteristics of the fine-grained sediments such as grain-size, clay mineralogy, and compaction that relate to position in the basin. These limited data certainly call for the collection of additional data.

Multiscale characteristics of mechanical and mineralogical heterogeneity using nanoindentation and Maps Mineralogy in Mancos Shale

NASA Astrophysics Data System (ADS)

Yoon, H.; Mook, W. M.; Dewers, T. A.

2017-12-01

Multiscale characteristics of textural and compositional (e.g., clay, cement, organics, etc.) heterogeneity profoundly influence the mechanical properties of shale. In particular, strongly anisotropic (i.e., laminated) heterogeneities are often observed to have a significant influence on hydrological and mechanical properties. In this work, we investigate a sample of the Cretaceous Mancos Shale to explore the importance of lamination, cements, organic content, and the spatial distribution of these characteristics. For compositional and structural characterization, the mineralogical distribution of thin core sample polished by ion-milling is analyzed using QEMSCAN® with MAPS MineralogyTM (developed by FEI Corporoation). Based on mineralogy and organic matter distribution, multi-scale nanoindentation testing was performed to directly link compositional heterogeneity to mechanical properties. With FIB-SEM (3D) and high-magnitude SEM (2D) images, key nanoindentation patterns are analyzed to evaluate elastic and plastic responses. Combined with MAPs Mineralogy data and fine-resolution BSE images, nanoindentation results are explained as a function of compositional and structural heterogeneity. Finite element modeling is used to quantitatively evaluate the link between the heterogeneity and mechanical behavior during nanoindentation. In addition, the spatial distribution of compositional heterogeneity, anisotropic bedding patterns, and mechanical anisotropy are employed as inputs for multiscale brittle fracture simulations using a phase field model. Comparison of experimental and numerical simulations reveal that proper incorporation of additional material information, such as bedding layer thickness and other geometrical attributes of the microstructures, may yield improvements on the numerical predictions of the mesoscale fracture patterns and hence the macroscopic effective toughness. Sandia National Laboratories is a multimission laboratory managed and operated by National Technology & Engineering Solutions of Sandia, LLC., a wholly owned subsidiary of Honeywell International, Inc., for the U.S. Department of Energy's National Nuclear Security Administration under contract DE-NA0003525.

A USANS/SANS study of the accessibility of pores in the Barnett Shale to methane and water

USGS Publications Warehouse

Ruppert, Leslie F.; Sakurovs, Richard; Blach, Tomasz P.; He, Lilin; Melnichenko, Yuri B.; Mildner, David F.; Alcantar-Lopez, Leo

2013-01-01

Shale is an increasingly important source of natural gas in the United States. The gas is held in fine pores that need to be accessed by horizontal drilling and hydrofracturing techniques. Understanding the nature of the pores may provide clues to making gas extraction more efficient. We have investigated two Mississippian Barnett Shale samples, combining small-angle neutron scattering (SANS) and ultrasmall-angle neutron scattering (USANS) to determine the pore size distribution of the shale over the size range 10 nm to 10 μm. By adding deuterated methane (CD4) and, separately, deuterated water (D2O) to the shale, we have identified the fraction of pores that are accessible to these compounds over this size range. The total pore size distribution is essentially identical for the two samples. At pore sizes >250 nm, >85% of the pores in both samples are accessible to both CD4 and D2O. However, differences in accessibility to CD4 are observed in the smaller pore sizes (~25 nm). In one sample, CD4 penetrated the smallest pores as effectively as it did the larger ones. In the other sample, less than 70% of the smallest pores (4, but they were still largely penetrable by water, suggesting that small-scale heterogeneities in methane accessibility occur in the shale samples even though the total porosity does not differ. An additional study investigating the dependence of scattered intensity with pressure of CD4 allows for an accurate estimation of the pressure at which the scattered intensity is at a minimum. This study provides information about the composition of the material immediately surrounding the pores. Most of the accessible (open) pores in the 25 nm size range can be associated with either mineral matter or high reflectance organic material. However, a complementary scanning electron microscopy investigation shows that most of the pores in these shale samples are contained in the organic components. The neutron scattering results indicate that the pores are not equally proportioned in the different constituents within the shale. There is some indication from the SANS results that the composition of the pore-containing material varies with pore size; the pore size distribution associated with mineral matter is different from that associated with organic phases.

Radon-222 content of natural gas samples from Upper and Middle Devonian sandstone and shale reservoirs in Pennsylvania—preliminary data

USGS Publications Warehouse

Rowan, E.L.; Kraemer, T.F.

2012-01-01

Samples of natural gas were collected as part of a study of formation water chemistry in oil and gas reservoirs in the Appalachian Basin. Nineteen samples (plus two duplicates) were collected from 11 wells producing gas from Upper Devonian sandstones and the Middle Devonian Marcellus Shale in Pennsylvania. The samples were collected from valves located between the wellhead and the gas-water separator. Analyses of the radon content of the gas indicated 222Rn (radon-222) activities ranging from 1 to 79 picocuries per liter (pCi/L) with an overall median of 37 pCi/L. The radon activities of the Upper Devonian sandstone samples overlap to a large degree with the activities of the Marcellus Shale samples.

Germanium and uranium in coalified wood bom upper Devonian black shale

USGS Publications Warehouse

Breger, I.A.; Schopf, J.M.

1955-01-01

Microscopic study of black, vitreous, carbonaceous material occurring in the Chattanooga shale in Tennessee and in the Cleveland member of the Ohio shale in Ohio has revealed coalified woody plant tissue. Some samples have shown sufficient detail to be identified with the genus Cauixylon. Similar material has been reported in the literature as "bituminous" or "asphaltic" stringers. Spectrographic analyses of the ash from the coalified wood have shown unusually high percentages of germanium, uranium, vanadium, and nickel. The inverse relationship between uranium and germanium in the ash and the ash content of various samples shows an association of these elements with the organic constituents of the coal. On the basis of geochemical considerations, it seems most probable that the wood or coalified wood was germanium-bearing at the time logs or woody fragmenta were floated into the basins of deposition of the Chattanooga shale and the Cleveland member of the Ohio shale. Once within the marine environment, the material probably absorbed uranium with the formation of organo-uranium compounds such as exist in coals. It is suggested that a more systematic search for germaniferous coals in the vicinity of the Chattanooga shale and the Cleveland member of the Ohio shale might be rewarding. ?? 1955.

Petrophysical approach for S-wave velocity prediction based on brittleness index and total organic carbon of shale gas reservoir: A case study from Horn River Basin, Canada

NASA Astrophysics Data System (ADS)

Kim, Taeyoun; Hwang, Seho; Jang, Seonghyung

2017-01-01

When finding the "sweet spot" of a shale gas reservoir, it is essential to estimate the brittleness index (BI) and total organic carbon (TOC) of the formation. Particularly, the BI is one of the key factors in determining the crack propagation and crushing efficiency for hydraulic fracturing. There are several methods for estimating the BI of a formation, but most of them are empirical equations that are specific to particular rock types. We estimated the mineralogical BI based on elemental capture spectroscopy (ECS) log and elastic BI based on well log data, and we propose a new method for predicting S-wave velocity (VS) using mineralogical BI and elastic BI. The TOC is related to the gas content of shale gas reservoirs. Since it is difficult to perform core analysis for all intervals of shale gas reservoirs, we make empirical equations for the Horn River Basin, Canada, as well as TOC log using a linear relation between core-tested TOC and well log data. In addition, two empirical equations have been suggested for VS prediction based on density and gamma ray log used for TOC analysis. By applying the empirical equations proposed from the perspective of BI and TOC to another well log data and then comparing predicted VS log with real VS log, the validity of empirical equations suggested in this paper has been tested.

Thermal maturity of northern Appalachian Basin Devonian shales: Insights from sterane and terpane biomarkers

USGS Publications Warehouse

Hackley, Paul C.; Ryder, Robert T.; Trippi, Michael H.; Alimi, Hossein

2013-01-01

To better estimate thermal maturity of Devonian shales in the northern Appalachian Basin, eleven samples of Marcellus and Huron Shale were characterized via multiple analytical techniques. Vitrinite reflectance, Rock–Eval pyrolysis, gas chromatography (GC) of whole rock extracts, and GC–mass spectrometry (GCMS) of extract saturate fractions were evaluated on three transects that lie across previously documented regional thermal maturity isolines. Results from vitrinite reflectance suggest that most samples are immature with respect to hydrocarbon generation. However, bulk geochemical data and sterane and terpane biomarker ratios from GCMS suggest that almost all samples are in the oil window. This observation is consistent with the presence of thermogenic gas in the study area and higher vitrinite reflectance values recorded from overlying Pennsylvanian coals. These results suggest that vitrinite reflectance is a poor predictor of thermal maturity in early mature areas of Devonian shale, perhaps because reported measurements often include determinations of solid bitumen reflectance. Vitrinite reflectance interpretations in areas of early mature Devonian shale should be supplanted by evaluation of thermal maturity information from biomarker ratios and bulk geochemical data.

Calorimetric determination of the heat of combustion of spent Green River shale at 978 K

DOE Office of Scientific and Technical Information (OSTI.GOV)

Mraw, S.C.; Keweshan, C.F.

1987-08-01

A Calvet-type calorimeter was used to measure heats of combustion of spent Colorado oil shales. For Green River shale, the samples were members of a sink-float series spanning oil yields from 87 to 340 L . tonne/sup -1/. Shale samples (30-200 mg) are dropped into the calorimeter at high temperature, and a peak in the thermopile signal records the total enthalpy change of the sample between room temperature and the final temperature. Duplicate samples from the above sink-float series were first retorted at 773 K and then dropped separately into nitrogen and oxygen at 978 K. The resulting heats aremore » subtracted to give the heat of combustion, and the results are compared to values from classical bomb calorimetry. The agreement shows that the heats of combustion of the organic component are well understood but that question remain on the reactions of the mineral components.« less

Effect of organic-matter type and thermal maturity on methane adsorption in shale-gas systems

USGS Publications Warehouse

Zhang, Tongwei; Ellis, Geoffrey S.; Ruppel, Stephen C.; Milliken, Kitty; Yang, Rongsheng

2012-01-01

A series of methane (CH4) adsorption experiments on bulk organic rich shales and their isolated kerogens were conducted at 35 °C, 50 °C and 65 °C and CH4 pressure of up to 15 MPa under dry conditions. Samples from the Eocene Green River Formation, Devonian–Mississippian Woodford Shale and Upper Cretaceous Cameo coal were studied to examine how differences in organic matter type affect natural gas adsorption. Vitrinite reflectance values of these samples ranged from 0.56–0.58 %Ro. In addition, thermal maturity effects were determined on three Mississippian Barnett Shale samples with measured vitrinite reflectance values of 0.58, 0.81 and 2.01 %Ro. For all bulk and isolated kerogen samples, the total amount of methane adsorbed was directly proportional to the total organic carbon (TOC) content of the sample and the average maximum amount of gas sorption was 1.36 mmol of methane per gram of TOC. These results indicate that sorption on organic matter plays a critical role in shale-gas storage. Under the experimental conditions, differences in thermal maturity showed no significant effect on the total amount of gas sorbed. Experimental sorption isotherms could be fitted with good accuracy by the Langmuir function by adjusting the Langmuir pressure (PL) and maximum sorption capacity (Γmax). The lowest maturity sample (%Ro = 0.56) displayed a Langmuir pressure (PL) of 5.15 MPa, significantly larger than the 2.33 MPa observed for the highest maturity (%Ro > 2.01) sample at 50 °C. The value of the Langmuir pressure (PL) changes with kerogen type in the following sequence: type I > type II > type III. The thermodynamic parameters of CH4 adsorption on organic rich shales were determined based on the experimental CH4 isotherms. For the adsorption of CH4 on organic rich shales and their isolated kerogen, the heat of adsorption (q) and the standard entropy (Δs0) range from 7.3–28.0 kJ/mol and from −36.2 to −92.2 J/mol/K, respectively.

Study on fracture identification of shale reservoir based on electrical imaging logging

NASA Astrophysics Data System (ADS)

Yu, Zhou; Lai, Fuqiang; Xu, Lei; Liu, Lin; Yu, Tong; Chen, Junyu; Zhu, Yuantong

2017-05-01

In recent years, shale gas exploration has made important development, access to a major breakthrough, in which the study of mud shale fractures is extremely important. The development of fractures has an important role in the development of gas reservoirs. Based on the core observation and the analysis of laboratory flakes and laboratory materials, this paper divides the lithology of the shale reservoirs of the XX well in Zhanhua Depression. Based on the response of the mudstone fractures in the logging curve, the fracture development and logging Response to the relationship between the conventional logging and electrical imaging logging to identify the fractures in the work, the final completion of the type of fractures in the area to determine and quantify the calculation of fractures. It is concluded that the fracture type of the study area is high and the microstructures are developed from the analysis of the XX wells in Zhanhua Depression. The shape of the fractures can be clearly seen by imaging logging technology to determine its type.

The Eastern Gas Shales Project (EGSP) Data System: A case study in data base design, development, and application

USGS Publications Warehouse

Dyman, T.S.; Wilcox, L.A.

1983-01-01

The U.S. Geological Survey and Petroleum Information Corporation in Denver, Colorado, developed the Eastern Gas Shale Project (EGSP)Data System for the U.S. Department of Energy, Morgantown, West Virginia. Geological, geochemical, geophysical, and engineering data from Devonian shale samples from more than 5800 wells and outcrops in the Appalachian basin were edited and converted to a Petroleum Information Corporation data base. Well and sample data may be retrieved from this data system to produce (1)production-test summaries by formation and well location; (2)contoured isopach, structure, and trendsurface maps of Devonian shale units; (3)sample summary reports for samples by location, well, contractor, and sample number; (4)cross sections displaying digitized log traces, geochemical, and lithologic data by depth for wells; and (5)frequency distributions and bivariate plots. Although part of the EGSP Data System is proprietary, and distribution of complete well histories is prohibited by contract, maps and aggregated well-data listings are being made available to the public through published reports. ?? 1983 Plenum Publishing Corporation.

Coal Rank and Stratigraphy of Pennsylvanian Coal and Coaly Shale Samples, Young County, North-Central Texas

USGS Publications Warehouse

Guevara, Edgar H.; Breton, Caroline; Hackley, Paul C.

2007-01-01

Vitrinite reflectance measurements were made to determine the rank of selected subsurface coal and coaly shale samples from Young County, north-central Texas, for the National Coal Resources Database System State Cooperative Program conducted by the Bureau of Economic Geology at The University of Texas at Austin. This research is the continuation of a pilot study that began in adjacent Archer County, and forms part of a larger investigation of the coalbed methane resource potential of Pennsylvanian coals in north-central Texas. A total of 57 samples of coal and coaly shale fragments were hand-picked from drill cuttings from depths of about 2,000 ft in five wells, and Ro determinations were made on an initial 10-sample subset. Electric-log correlation of the sampled wells indicates that the collected samples represent coal and coaly shale layers in the Strawn (Pennsylvanian), Canyon (Pennsylvanian), and Cisco (Pennsylvanian-Permian) Groups. Coal rank in the initial sample subset ranges from lignite (Ro=0.39), in a sample from the Cisco Group at a depth of 310 to 320 ft, to high volatile bituminous A coal (Ro=0.91) in a sample from the lower part of the Canyon Group at a depth of 2,030 to 2,040 ft.

A microstructural study of SAFOD gouge from actively creeping San Andreas Fault zone; Implications for shear localization models

NASA Astrophysics Data System (ADS)

Blackburn, E. D.; Hadizadeh, J.; Babaie, H. A.

2009-12-01

The prevailing models of shear localization in fault gouges are mainly based on experimental aggregates that necessarily neglect the effects of chemical and mechanical maturation with time. The SAFOD cores have provided a chance to test whether cataclasis as a deformation mechanism and factors such as porosity and particle size, critical in some existing shear localization models continue to be critical in mature gouges. We studied a core sample from 3194m MD in the SAFOD phase 3, which consists of intensely foliated shale-siltstone cataclasites in contact with less deformed shale. Microstructures were studied in 3 perpendicular planes with reference to foliation using high resolution scanning electron microscopy, cathodoluminescence imaging, X-ray fluorescence mapping, and energy dispersive X-ray spectroscopy. The cataclastic foliation, recognizable at length scales >100 μm, is primarily defined by bands of clay gouge with distinct microstructure, clay content, and porosity. Variations in elemental composition and porosity of the clay gouge were measured continuously across the foliation. Prominent features within the foliation bands include lens-shaped clusters of highly brecciated and veined siltstone fragments, pyrite smears, and pyrite-cemented cataclasites. The microstructural relations and chemical data provide clear evidence of multiple episodes of veining and deformation with some possibility of relative age determination for the episodes. There is evidence of syn-deformation hydrothermal changes including growth and brittle shear of pyrite, alteration of host shale clays to illite-smectite clays and Fe-rich smectite. Evidence of grain-boundary corrosion of non-clay mineral fragments suggests pressure solution creep. The gouge porosity estimates varied from 0-18% (about 3% in less deformed shale) with the highest value in the bands with abundant siltstone fragments. The banding is mechanically significant since it pervasively segregates the gouge into regions of low clay content, high-porosity and regions of low-porosity, high clay content. It appears from our data that shear localization in the gouge involves pressure solution as well as cataclastic flow assisted by alteration-softening. While the porous bands are potential conduits for fluid flow and could be sites for pressure solution creep, the clay-rich bands could serve as sites of shear localization due to their lower dilatancy rate. A better understanding of interaction between the two deformation mechanisms might shed light on the nature of microearthquake activity in the creeping segment of the SAF.

Feasibility Assessment of CO2 Sequestration and Enhanced Recovery in Gas Shale Reservoirs

NASA Astrophysics Data System (ADS)

Vermylen, J. P.; Hagin, P. N.; Zoback, M. D.

2008-12-01

CO2 sequestration and enhanced methane recovery may be feasible in unconventional, organic-rich, gas shale reservoirs in which the methane is stored as an adsorbed phase. Previous studies have shown that organic-rich, Appalachian Devonian shales adsorb approximately five times more carbon dioxide than methane at reservoir conditions. However, the enhanced recovery and sequestration concept has not yet been tested for gas shale reservoirs under realistic flow and production conditions. Using the lessons learned from previous studies on enhanced coalbed methane (ECBM) as a starting point, we are conducting laboratory experiments, reservoir modeling, and fluid flow simulations to test the feasibility of sequestration and enhanced recovery in gas shales. Our laboratory work investigates both adsorption and mechanical properties of shale samples to use as inputs for fluid flow simulation. Static and dynamic mechanical properties of shale samples are measured using a triaxial press under realistic reservoir conditions with varying gas saturations and compositions. Adsorption is simultaneously measured using standard, static, volumetric techniques. Permeability is measured using pulse decay methods calibrated to standard Darcy flow measurements. Fluid flow simulations are conducted using the reservoir simulator GEM that has successfully modeled enhanced recovery in coal. The results of the flow simulation are combined with the laboratory results to determine if enhanced recovery and CO2 sequestration is feasible in gas shale reservoirs.

Implications of contact metamorphism of Mancos Shale for critical zone processes

NASA Astrophysics Data System (ADS)

Navarre-Sitchler, A.

2016-12-01

Bedrock lithology imparts control on some critical zone processes, for example rates and extent of chemical weathering, solute release though mineral dissolution, and water flow. Bedrock can be very heterogeneous resulting in spatial variability of these processes throughout a catchment. In the East River watershed outside of Crested Butte, Colorado, bedrock is dominantly comprised of the Mancos Shale; a Cretaceous aged, organic carbon rich marine shale. However, in some areas the Mancos Shale appears contact metamorphosed by nearby igneous intrusions resulting in a potential gradient in lithologic change in part of the watershed where impacts of lithology on critical zone processes can be evaluated. Samples were collected in the East River valley along a transect from the contact between the Tertiary Gothic Mountain laccolith of the Mount Carbon igneous system and the underlying Manocs shale. Porosity of these samples was analyzed by small-angle and ultra small-angle neutron scattering. Results indicate contact metamorphism decreases porosity of the shale and changes the pore shape from slightly anisotropic pores aligned with bedding in the unmetamorphosed shale to isotropic pores with no bedding alignment in the metamorphosed shales. The porosity analysis combined with clay mineralogy, surface area, carbon content and oxidation state, and solute release rates determined from column experiments will be used to develop a full understanding of the impact of contact metamorphism on critical zone processes in the East River.

Cyclic injection, storage, and withdrawal of heated water in a sandstone aquifer at St. Paul, Minnesota: Field observations, preliminary model analysis, and aquifer thermal efficiency

USGS Publications Warehouse

Miller, Robert T.

1989-01-01

The Franconia-Ironton-Galesville aquifer is a consolidated sandstone, approximately 60 m thick, the top of which is approximately 180 m below the land surface. It is confined above by the St. Lawrence Formation--a dolomitic sandstone 8-m thick--and below by the Eau Claire Formation--a shale 30-m thick. Initial hydraulic testing with inflatable packers indicated that the aquifer has four hydraulic zones with distinctly different values of relative horizontal hydraulic conductivity. The thickness of each zone was determined by correlating data from geophysical logs, core samples, and the inflatablepacker tests.

Comparison of Pore Fractal Characteristics Between Marine and Continental Shales

NASA Astrophysics Data System (ADS)

Liu, Jun; Yao, Yanbin; Liu, Dameng; Cai, Yidong; Cai, Jianchao

Fractal characterization offers a quantitative evaluation on the heterogeneity of pore structure which greatly affects gas adsorption and transportation in shales. To compare the fractal characteristics between marine and continental shales, nine samples from the Lower Silurian Longmaxi formation in the Sichuan basin and nine from the Middle Jurassic Dameigou formation in the Qaidam basin were collected. Reservoir properties and fractal dimensions were characterized for all the collected samples. In this study, fractal dimensions were originated from the Frenkel-Halsey-Hill (FHH) model with N2 adsorption data. Compared to continental shale, marine shale has greater values of quartz content, porosity, specific surface area and total pore volume but lower level of clay minerals content, permeability, average pore diameter and methane adsorption capacity. The quartz in marine shale is mostly associated with biogenic origin, while that in continental shale is mainly due to terrigenous debris. The N2 adsorption-desorption isotherms exhibit that marine shale has fewer inkbottle-shaped pores but more plate-like and slit-shaped pores than continental shale. Two fractal dimensions (D1 and D2) were obtained at P/Po of 0-0.5 and 0.5-1. The dimension D2 is commonly greater than D1, suggesting that larger pores (diameter >˜ 4nm) have more complex structures than small pores (diameter <˜ 4nm). The fractal dimensions (both D1 and D2) positively correlate to clay minerals content, specific surface area and methane adsorption capacity, but have negative relationships with porosity, permeability and average pore diameter. The fractal dimensions increase proportionally with the increasing quartz content in marine shale but have no obvious correlation with that in continental shale. The dimension D1 is correlative to the TOC content and permeability of marine shale at a similar degree with dimension D2, while the dimension D1 is more sensitive to those of continental shale than dimension D2. Compared with dimension D2, for two shales, dimension D1 is better associated with the content of clay minerals but has worse correlations with the specific surface area and average pore diameter.

The pore structure and fractal characteristics of shales with low thermal maturity from the Yuqia Coalfield, northern Qaidam Basin, northwestern China

NASA Astrophysics Data System (ADS)

Hou, Haihai; Shao, Longyi; Li, Yonghong; Li, Zhen; Zhang, Wenlong; Wen, Huaijun

2018-03-01

The continental shales from the Middle Jurassic Shimengou Formation of the northern Qaidam Basin, northwestern China, have been investigated in recent years because of their shale gas potential. In this study, a total of twenty-two shale samples were collected from the YQ-1 borehole in the Yuqia Coalfield, northern Qaidam Basin. The total organic carbon (TOC) contents, pore structure parameters, and fractal characteristics of the samples were investigated using TOC analysis, low-temperature nitrogen adsorption experiments, and fractal analysis. The results show that the average pore size of the Shimengou shales varied from 8.149 nm to 20.635 nm with a mean value of 10.74 nm, which is considered mesopore-sized. The pores of the shales are mainly inkbottle- and slit-shaped. The sedimentary environment plays an essential role in controlling the TOC contents of the low maturity shales, with the TOC values of shales from deep to semi-deep lake facies (mean: 5.23%) being notably higher than those of the shore-shallow lake facies (mean: 0.65%). The fractal dimensions range from 2.4639 to 2.6857 with a mean of 2.6122, higher than those of marine shales, which indicates that the pore surface was rougher and the pore structure more complex in these continental shales. The fractal dimensions increase with increasing total pore volume and total specific surface area, and with decreasing average pore size. With increasing TOC contents in shales, the fractal dimensions increase first and then decrease, with the highest value occurring at 2% of TOC content, which is in accordance with the trends between the TOC and both total specific surface area and total pore volume. The pore structure complexity and pore surface roughness of these low-maturity shales would be controlled by the combined effects of both sedimentary environments and the TOC contents.

Depositional environments and sand body morphologies of the muddy sandstones at Kitty Field, Powder River Basin, Wyoming

DOE Office of Scientific and Technical Information (OSTI.GOV)

Larberg, G.M.B.

1980-01-01

Lower Cretaceous muddy sandstones form a stratigraphic trap at Kitty Field, Campbell County, Wyoming. Porosity and permeability are generally low, but the best reservoir develop maximum effective porosity of 17% and maximum permeability of 442 md. Reservoirs sandstones average less than 15 ft and rarely exceed 30 ft in thickness. Ultimate recovery from the field is estimated at 23 million bbl. Based on electric log character, 4 easily recognizable zones within the muddy interval at Kitty were numbered one through 4 in slabbed cores and petrographic analyses of selected core samples, suggest that sandstones in the second, third, and fourthmore » muddy zones were deposited as part of a sequence associated with the overall transgression of the lower Cretaceous sea. Fourth zone sandstones are fluvial in origin, and were deposited in lows on the unconformable surface of the underlying skull creek shale. 18 references.« less

An evaluation of water quality in private drinking water wells near natural gas extraction sites in the Barnett Shale formation.

PubMed

Fontenot, Brian E; Hunt, Laura R; Hildenbrand, Zacariah L; Carlton, Doug D; Oka, Hyppolite; Walton, Jayme L; Hopkins, Dan; Osorio, Alexandra; Bjorndal, Bryan; Hu, Qinhong H; Schug, Kevin A

2013-09-03

Natural gas has become a leading source of alternative energy with the advent of techniques to economically extract gas reserves from deep shale formations. Here, we present an assessment of private well water quality in aquifers overlying the Barnett Shale formation of North Texas. We evaluated samples from 100 private drinking water wells using analytical chemistry techniques. Analyses revealed that arsenic, selenium, strontium and total dissolved solids (TDS) exceeded the Environmental Protection Agency's Drinking Water Maximum Contaminant Limit (MCL) in some samples from private water wells located within 3 km of active natural gas wells. Lower levels of arsenic, selenium, strontium, and barium were detected at reference sites outside the Barnett Shale region as well as sites within the Barnett Shale region located more than 3 km from active natural gas wells. Methanol and ethanol were also detected in 29% of samples. Samples exceeding MCL levels were randomly distributed within areas of active natural gas extraction, and the spatial patterns in our data suggest that elevated constituent levels could be due to a variety of factors including mobilization of natural constituents, hydrogeochemical changes from lowering of the water table, or industrial accidents such as faulty gas well casings.

Effects of experimental parameters on the sorption of cesium, strontium, and uranium from saline groundwaters onto shales: Progress report

DOE Office of Scientific and Technical Information (OSTI.GOV)

Meyer, R.E.; Arnold, W.D.; Case, F.I.

1988-11-01

This report concerns an extension of the first series of experiments on the sorption properties of shales and their clay mineral components reported earlier. Studies on the sorption of cesium and strontium were carried out on samples of Chattanooga (Upper Dowelltown), Pierre, Green River Formation, Nolichucky, and Pumpkin Valley Shales that had been heated to 120/degree/C in a 0.1-mol/L NaCl solution for periods up to several months and on samples of the same shales which had been heated to 250/degree/C in air for six months, to simulate limiting scenarios in a HLW repository. To investigate the kinetics of the sorptionmore » process in shale/groundwater systems, strontium sorption experiments were done on unheated Pierre, Green River Formation, Nolichucky, and Pumpkin Valley Shales in a diluted, saline groundwater and in 0.03-mol/L NaHCO/sub 3/, for periods of 0.25 to 28 days. Cesium sorption kinetics tests were performed on the same shales in a concentrated brine for the same time periods. The effect of the water/rock (W/R) ratio on sorption for the same combinations of unheated shales, nuclides, and groundwaters used in the kinetics experiments was investigated for a range of W/R ratios of 3 to 20 mL/g. Because of the complexity of the shale/groundwater interaction, a series of tests was conducted on the effects of contact time and W/R ratio on the pH of a 0.03-mol/L NaHCO/sub 3/ simulated groundwater in contact with shales. 8 refs., 12 figs., 15 tabs.« less

Experimental Investigation of Mechanical Properties of Black Shales after CO2-Water-Rock Interaction

PubMed Central

Lyu, Qiao; Ranjith, Pathegama Gamage; Long, Xinping; Ji, Bin

2016-01-01

The effects of CO2-water-rock interactions on the mechanical properties of shale are essential for estimating the possibility of sequestrating CO2 in shale reservoirs. In this study, uniaxial compressive strength (UCS) tests together with an acoustic emission (AE) system and SEM and EDS analysis were performed to investigate the mechanical properties and microstructural changes of black shales with different saturation times (10 days, 20 days and 30 days) in water dissoluted with gaseous/super-critical CO2. According to the experimental results, the values of UCS, Young’s modulus and brittleness index decrease gradually with increasing saturation time in water with gaseous/super-critical CO2. Compared to samples without saturation, 30-day saturation causes reductions of 56.43% in UCS and 54.21% in Young’s modulus for gaseous saturated samples, and 66.05% in UCS and 56.32% in Young’s modulus for super-critical saturated samples, respectively. The brittleness index also decreases drastically from 84.3% for samples without saturation to 50.9% for samples saturated in water with gaseous CO2, to 47.9% for samples saturated in water with super-critical carbon dioxide (SC-CO2). SC-CO2 causes a greater reduction of shale’s mechanical properties. The crack propagation results obtained from the AE system show that longer saturation time produces higher peak cumulative AE energy. SEM images show that many pores occur when shale samples are saturated in water with gaseous/super-critical CO2. The EDS results show that CO2-water-rock interactions increase the percentages of C and Fe and decrease the percentages of Al and K on the surface of saturated samples when compared to samples without saturation. PMID:28773784

Organoporosity Evaluation of Shale: A Case Study of the Lower Silurian Longmaxi Shale in Southeast Chongqing, China

PubMed Central

Chen, Fangwen; Lu, Shuangfang; Ding, Xue

2014-01-01

The organopores play an important role in determining total volume of hydrocarbons in shale gas reservoir. The Lower Silurian Longmaxi Shale in southeast Chongqing was selected as a case to confirm the contribution of organopores (microscale and nanoscale pores within organic matters in shale) formed by hydrocarbon generation to total volume of hydrocarbons in shale gas reservoir. Using the material balance principle combined with chemical kinetics methods, an evaluation model of organoporosity for shale gas reservoirs was established. The results indicate that there are four important model parameters to consider when evaluating organoporosity in shale: the original organic carbon (w(TOC0)), the original hydrogen index (I H0), the transformation ratio of generated hydrocarbon (F(R o)), and the organopore correction coefficient (C). The organoporosity of the Lower Silurian Longmaxi Shale in the Py1 well is from 0.20 to 2.76%, and the average value is 1.25%. The organoporosity variation trends and the residual organic carbon of Longmaxi Shale are consistent in section. The residual organic carbon is indicative of the relative levels of organoporosity, while the samples are in the same shale reservoirs with similar buried depths. PMID:25184155

Germanium and uranium in coalified wood from Upper Devonian black shale

USGS Publications Warehouse

Breger, Irving A.; Schopf, James M.

1954-01-01

Microscopic study of black, vitreous, carbonaceous material occurring in the Chattanooga shale in Tennessee and in the Cleveland member of the Ohio shale in Ohio has revealed coalified woody plant tissue. Some samples have shown sufficient detail to be identified with the genus Callixylon. Similar material has been reported in the literature as "bituminous" or "asphaltic" stringers. Spectrographic analyses of the ash from the coalified wood have shown unusually high percentages of germanium, uranium, vanadium, and nickel. The inverse relationship between uranium and germanium in the ash and the ash content of various samples shows an association of these elements with the organic constituents of the coal. On the basis of geochemical considerations, it seems most probable that the wood or coalified wood was germanium-bearing at the time logs or woody fragments were floated into the basins of deposition of the Chattanooga shale and the Cleveland member of the Ohio shale. Once within the marine environment, the material probably absorbed uranium with the formation of organo-uranium compounds such as have been found to exist in coals. It is suggested that a more systematic search for germaniferous coals in the vicinity of the Chattanooga shale and the Cleveland member of the Ohio shale might be rewarding.

How microfracture roughness can be used to distinguish between exhumed cracks and in-situ flow paths in shales

NASA Astrophysics Data System (ADS)

Pluymakers, Anne; Kobchenko, Maya; Renard, François

2017-01-01

Flow through fractures in shales is of importance to many geoengineering purposes. Shales are not only caprocks to hydrocarbon reservoirs and nuclear waste or CO2 storage sites, but also potential source and reservoir rocks for hydrocarbons. The presence of microfractures in shales controls their permeability and transport properties. Using X-ray micro-tomography and white light interferometry we scanned borehole samples obtained from 4 km depth in the Pomeranian shales in Poland. These samples contain open exhumation/drying cracks as well as intact vein-rock interfaces plus one striated slip surface. At micron resolution and above tensile drying cracks exhibit a power-law roughness with a scaling exponent, called the Hurst exponent H, of 0.3. At sub-micron resolution we capture the properties of the clay interface only, with H = 0.6. In contrast, the in-situ formed veins and slip surface exhibit H = 0.4-0.5, which is deemed representative for in-situ fractures. These results are discussed in relation to the shale microstructure and linear elastic fracture mechanics theory. The data imply that the Hurst roughness exponent can be used as a microstructural criterion to distinguish between exhumation and in-situ fractures, providing a step forward towards the characterization of potential flow paths at depth in shales.

Geochemistry and shock petrography of the Crow Creek Member, South Dakota, USA: Ejecta from the 74-Ma Manson impact structure

USGS Publications Warehouse

Katongo, C.; Koeberl, C.; Witzke, B.J.; Hammond, R.H.; Anderson, R.R.

2004-01-01

The Crow Creek Member is one of several marl units recognized within the Upper Cretaceous Pierre Shale Formation of eastern South Dakota and northeastern Nebraska, but it is the only unit that contains shock-metamorphosed minerals. The shocked minerals represent impact ejecta from the 74-Ma Manson impact structure (MIS). This study was aimed at determining the bulk chemical compositions and analysis of planar deformation features (PDFs) of shocked quartz; for the basal and marly units of the Crow Creek Member. We studied samples from the Gregory 84-21 core, Iroquois core and Wakonda lime quarry. Contents of siderophile elements are generally high, but due to uncertainties in the determination of Ir and uncertainties in compositional sources for Cr, Co, and Ni, we could not confirm an extraterrestrial component in the Crow Creek Member. We recovered several shocked quartz grains from basal-unit samples, mainly from the Gregory 84-21 core, and results of PDF measurements indicate shock pressures of at least 15 GPa. All the samples are composed chiefly of SiO2, (29-58 wt%), Al2O3 (6-14 wt%), and CaO (7-30 wt%). When compared to the composition of North American Shale Composite, the samples are significantly enriched in CaO, P2O5, Mn, Sr, Y, U, Cr, and Ni. The contents of rare earth elements (REE), high field strength elements (HFSE), Cr, Co, Sc, and their ratios and chemical weathering trends, reflect both felsic and basic sources for the Crow Creek Member, an inference, which is consistent with the lithological compositions in the environs of the MIS. The high chemical indices of alteration and weathering (CIA' and CIW': 75-99), coupled with the Al2O3-(CaO*,+Na2O -K2O (A-CN'-K) ratios, indicate that the Crow Creek Member and source rocks had undergone high degrees of chemical weathering. The expected ejecta thicknesses at the sampled locations (409 to 219 km from Manson) were calculated to range from about 1.9 to 12.2 cm (for the present-day crater radius of Manson), or 0.4 to 2.4 cm (for the estimated transient cavity radius). The trend agrees with the observed thicknesses of the basal unit of the Crow Creek Member, but the actually observed thicknesses are larger than the calculated ones, indicating that not all of the basal unit comprises impact ejecta. ?? Meteoritical Society, 2004.

An Effective Reservoir Parameter for Seismic Characterization of Organic Shale Reservoir

NASA Astrophysics Data System (ADS)

Zhao, Luanxiao; Qin, Xuan; Zhang, Jinqiang; Liu, Xiwu; Han, De-hua; Geng, Jianhua; Xiong, Yineng

2017-12-01

Sweet spots identification for unconventional shale reservoirs involves detection of organic-rich zones with abundant porosity. However, commonly used elastic attributes, such as P- and S-impedances, often show poor correlations with porosity and organic matter content separately and thus make the seismic characterization of sweet spots challenging. Based on an extensive analysis of worldwide laboratory database of core measurements, we find that P- and S-impedances exhibit much improved linear correlations with the sum of volume fraction of organic matter and porosity than the single parameter of organic matter volume fraction or porosity. Importantly, from the geological perspective, porosity in conjunction with organic matter content is also directly indicative of the total hydrocarbon content of shale resources plays. Consequently, we propose an effective reservoir parameter (ERP), the sum of volume fraction of organic matter and porosity, to bridge the gap between hydrocarbon accumulation and seismic measurements in organic shale reservoirs. ERP acts as the first-order factor in controlling the elastic properties as well as characterizing the hydrocarbon storage capacity of organic shale reservoirs. We also use rock physics modeling to demonstrate why there exists an improved linear correlation between elastic impedances and ERP. A case study in a shale gas reservoir illustrates that seismic-derived ERP can be effectively used to characterize the total gas content in place, which is also confirmed by the production well.

Screening for Dissolved Methane in Groundwater Across Texas Shale Plays

NASA Astrophysics Data System (ADS)

Nicot, J. P.; Mickler, P. J.; Hildenbrand, Z.; Larson, T.; Darvari, R.; Uhlman, K.; Smyth, R. C.; Scanlon, B. R.

2014-12-01

There is considerable interest in methane concentrations in groundwater, particularly as they relate to hydraulic fracturing in shale plays. Recent studies of aquifers in the footprint of several gas plays across the US have shown that (1) dissolved thermogenic methane may or may not be present in the shallow groundwater and (2) shallow thermogenic methane may be naturally occurring and emplaced through mostly vertical migration over geologic time and not necessarily a consequence of recent unconventional gas production. We are currently conducting a large sampling campaign across the state of Texas to characterize shallow methane in fresh-water aquifers overlying shale plays and other tight formations. We collected a total of ~800 water samples, ~500 in the Barnett, ~150 in the Eagle Ford, ~80 in the Haynesville shale plays as well as ~50 in the Delaware Basin of West Texas. Preliminary analytical results suggest that dissolved methane is not widespread in shallow groundwater and that, when present at concentrations exceeding 10 mg/L, it is often of thermogenic origin according to the isotopic signature and to the presence of other light hydrocarbons. The Barnett Shale contains a large methane hotspot (~ 2 miles wide) along the Hood-Parker county line which is likely of natural origin whereas the Eagle Ford and Haynesville shales, neglecting microbial methane, show more distributed methane occurrences. Samples from the Delaware Basin show no methane except close to blowouts.

Water Use by Texas Oil and Gas Industry: A Look towards the Future

NASA Astrophysics Data System (ADS)

Nicot, J.; Ritter, S. M.; Hebel, A. K.

2009-12-01

The Barnett Shale gas play, located in North Texas, has seen a relatively quick growth in the past decade with the development of new “frac” (aka, fracture stimulation) technologies needed to create pathways to produce gas from the very low permeability shales. This technology uses a large amount of fresh water (millions of gallons in a day or two on average) to develop a gas well. Now operators are taking aim at other shale gas plays in Texas including the Haynesville, Woodford, and Pearsall-Eagle Ford shales and at other tight formation such as the Bossier Sand. These promising gas plays are likely to be developed at an even steeper growth rate. There are currently over 12,000 wells producing gas from the Barnett Shale with many more likely to be drilled in the next couple of decades as the play expands out of its core area. Despite the recent gas price slump, thousands more wells may be drilled across the state to access the gas resource in the next few years. As an example, a typical vertical and horizontal well completion in the Barnett Shale consumes approximately 1.2 and 3.0 to 3.5 millions gallons of fresh water, respectively. This could raise some concerns among local communities and other surface water and groundwater stakeholders. We present a preliminary analysis of future water use by the Texas oil and gas industry and compare it to projections of total water use, including municipal use and irrigation. Maps showing large increase in total number of well completions in the Barnett Shale (black dots) from 1998 to 2008. Operators avoided the DFW metro area (center right on the map) until recently. Also shown are the structural limits of the Barnett Shale on its eastern boundaries.

The carpenter fork bed, a new - and older - Black-shale unit at the base of the New Albany shale in central Kentucky: Characterization and significance

USGS Publications Warehouse

Barnett, S.F.; Ettensohn, F.R.; Norby, R.D.

1996-01-01

Black shales previously interpreted to be Late Devonian cave-fill or slide deposits are shown to be much older Middle Devonian black shales only preserved locally in Middle Devonian grabens and structural lows in central Kentucky. This newly recognized - and older -black-shale unit occurs at the base of the New Albany Shale and is named the Carpenter Fork Bed of the Portwood Member of the New Albany Shale after its only known exposure on Carpenter Fork in Boyle County, central Kentucky; two other occurrences are known from core holes in east-central Kentucky. Based on stratigraphic position and conodont biostratigraphy, the unit is Middle Devonian (Givetian: probably Middle to Upper P. varcus Zone) in age and occurs at a position represented by an unconformity atop the Middle Devonian Boyle Dolostone and its equivalents elsewhere on the outcrop belt. Based on its presence as isolated clasts in the overlying Duffin Bed of the Portwood Member, the former distribution of the unit was probably much more widespread - perhaps occurring throughout western parts of the Rome trough. Carpenter Fork black shales apparently represent an episode of subsidence or sea-level rise coincident with inception of the third tectophase of the Acadian orogeny. Deposition, however, was soon interrupted by reactivation of several fault zones in central Kentucky, perhaps in response to bulge migration accompanying start of the tectophase. As a result, much of central Kentucky was uplifted and tilted, and the Carpenter Fork Bed was largely eroded from the top of the Boyle, except in a few structural lows like the Carpenter Fork graben where a nearly complete record of Middle to early Late Devonian deposition is preserved.

Hydrothermal Liquefaction Biocrude Compositions Compared to Petroleum Crude and Shale Oil

DOE Office of Scientific and Technical Information (OSTI.GOV)

Jarvis, Jacqueline M.; Billing, Justin M.; Hallen, Richard T.

We provide a direct and detailed comparison of the chemical composition of petroleum crude oil (from the Gulf of Mexico), shale oil, and three biocrudes (i.e., clean pine, microalgae Chlorella sp., and sewage sludge feedstocks) generated by hydrothermal liquefaction (HTL). Ultrahigh resolution Fourier transform ion cyclotron resonance mass spectrometry (FT-ICR MS) reveals that HTL biocrudes are compositionally more similar to shale oil than petroleum crude oil and that only a few heteroatom classes (e.g., N1, N2, N1O1, and O1) are common to organic sediment- and biomass-derived oils. All HTL biocrudes contain a diverse range of oxygen-containing compounds when compared tomore » either petroleum crude or shale oil. Overall, petroleum crude and shale oil are compositionally dissimilar to HTL oils, and >85% of the elemental compositions identified within the positive-ion electrospray (ESI) mass spectra of the HTL biocrudes were not present in either the petroleum crude or shale oil (>43% for negative-ion ESI). Direct comparison of the heteroatom classes that are common to both organic sedimentand biomass-derived oils shows that HTL biocrudes generally contain species with both smaller core structures and a lower degree of alkylation relative to either the petroleum crude or the shale oil. Three-dimensional plots of carbon number versus molecular double bond equivalents (with observed abundance as the third dimension) for abundant molecular classes reveal the specific relationship of the composition of HTL biocrudes to petroleum and shale oils to inform the possible incorporation of these oils into refinery operations as a partial amendment to conventional petroleum feeds.« less

Thermal maturity of Jurassic shales from the Newark Basin, U.S.A.: influence of hydrothermal fluids and implications to basin modeling

USGS Publications Warehouse

Walters, C.C.; Kotra, R.K.

1990-01-01

Organic geochemical investigations were conducted on a series of cores that systematically sampled the uppermost Jurassic strata from the northern Newark Basin. Each sedimentary unit consists of fluvial red sandstones and siltstones with cyclic deposits of interbedded black lacustrine shales and gray deltaic siltstones. In a suite of organic-rich shales from the Boonton, Towaco and Feltville Formations, organic maturation parameters were used to determine aspects of the thermal history of the Newark Basin. Comparisons of model calculations and measured maturities support39 Ar/40 Ar-geochronometer studies that indicate a hydrothermal event occurred ???175 Ma ago. An increase in the regional geothermal gradient to ???7.5??C/100 m for ???5 Ma best conforms to the organic geochemical observations. Biomarker compounds in Boonton and Towaco strata should have been relatively unaltered by this regional event, but anomalous molecular distributions in the organic-rich rocks may have resulted from localized heating by hydrothermal fluids. The effects of this interaction would be very subtle and may be indistinguishable from variations caused by differences in organic facies. Within this uncertainty, sterane and hopane isomerization and steroid aromatization reactions advanced in the Boonton and Towaco Formation strata primarily because of burial and normal geothermal heating that followed the hydrothermal event. Biomarker kinetic models indicate that ???2400 m of Boonton and post-Boonton strata were eroded after basinal uplift commenced ???50 Ma ago. ?? 1990.

Consistent lithological units and its influence on geomechanical stratification in shale reservoir: case study from Baltic Basin, Poland.

NASA Astrophysics Data System (ADS)

Pachytel, Radomir; Jarosiński, Marek; Bobek, Kinga

2017-04-01

Geomechanical investigations in shale reservoir are crucial to understand rock behavior during hydraulic fracturing treatment and to solve borehole wall stability problem. Anisotropy should be considered as key mechanical parameter while trying to characterize shale properties in variety of scales. We are developing a concept of step-by-step approach to characterize and upscale the Consistent Lithological Units (CLU) at several scales of analysis. We decided that the most regional scale model, comparable to lithostratigraphic formations, is too general for hydraulic fracture propagation study thus a more detailed description is needed. The CLU's hierarchic model aims in upscale elastic properties with their anisotropy based on available data from vertical borehole. For the purpose of our study we have an access to continuous borehole core profile and full set of geophysical logging from several wells in the Pomeranian part of the Ordovician and Silurian shale complex belongs to the Baltic Basin. We are focused on shale properties that might be crucial for mechanical response to hydraulic fracturing: mineral components, porosity, density, elastic parameters and natural fracture pattern. To prepare the precise CLU model we compare several methods of determination and upscaling every single parameter used for consistent units secretion. Mineralogical data taken from ULTRA log, GEM log, X-ray diffraction and X-ray fluorescence were compared with Young modulus from sonic logs and Triaxial Compressive Strength Tests. The results showed the impact of clay content and porosity increase on Young's modulus reduction while carbonates (both calcite and dolomite) have stronger impact on elastic modulus growth, more than quartz, represented here mostly by detrital particles. Comparing the shales of similar composition in a few wells of different depths we concluded that differences in diagenesis and compaction due to variation in formation depth in a range of 1 km has negligible influence on the values of Young modulus. Both mineralogical and mechanical brittleness display differences not only between lithostratigraphic formations, but also for the lower-order CLUs which may influence development of tectonic and technological fractures. Using this approach, we can predict the areas that may be more prone to fracture propagation and branching during hydraulic fracturing treatment and also places that can create barriers to their development. Furthermore, we demonstrate relationship between CLU's mechanical properties and the density of natural fractures determined from core and Electric-Resistivity Borehole Imager analysis. As fracture friction may rule reservoir response to technological loads induced while drilling and fracking we also applied a method of massive determination of static friction coefficient on borehole core. Tuffite beds or other weak intercalations were included in the CLU's model as possible structural barriers for hydraulic fracture propagation. Distinguished set of CLUs is possible to be traced from well to well across tens of kilometers of the Baltic Basin. Our study in the frame of ShaleMech Project funded by Polish Committee for Scientific Research is in progress and the results are preliminary.

Appraisal of transport and deformation in shale reservoirs using natural noble gas tracers

DOE Office of Scientific and Technical Information (OSTI.GOV)

Heath, Jason E.; Kuhlman, Kristopher L.; Robinson, David G.

2015-09-01

This report presents efforts to develop the use of in situ naturally-occurring noble gas tracers to evaluate transport mechanisms and deformation in shale hydrocarbon reservoirs. Noble gases are promising as shale reservoir diagnostic tools due to their sensitivity of transport to: shale pore structure; phase partitioning between groundwater, liquid, and gaseous hydrocarbons; and deformation from hydraulic fracturing. Approximately 1.5-year time-series of wellhead fluid samples were collected from two hydraulically-fractured wells. The noble gas compositions and isotopes suggest a strong signature of atmospheric contribution to the noble gases that mix with deep, old reservoir fluids. Complex mixing and transport of fracturingmore » fluid and reservoir fluids occurs during production. Real-time laboratory measurements were performed on triaxially-deforming shale samples to link deformation behavior, transport, and gas tracer signatures. Finally, we present improved methods for production forecasts that borrow statistical strength from production data of nearby wells to reduce uncertainty in the forecasts.« less

Hydrologic-information needs for oil-shale development, northwestern Colorado

USGS Publications Warehouse

Taylor, O.J.

1982-01-01

Hydrologic information is not adequate for proper development of the large oil-shale reserves of Piceance basin in northwestern Colorado. Exploratory drilling and aquifer testing are needed to define the hydrologic system, to provide wells for aquifer testing, to design mine-drainage techniques, and to explore for additional water supplies. Sampling networks are needed to supply hydrologic data on the quantity and quality of surface water, ground water, and springs. A detailed sampling network is proposed for the White River basin because of expected impacts related to water supplies and waste disposal. Emissions from oil-shale retorts to the atmosphere need additional study because of possible resulting corrosion problems and the destruction of fisheries. Studies of the leachate materials and the stability of disposed retorted shale piles are needed to insure that these materials will not cause problems. Hazards related to in-situ retorts, and the wastes related to oil-shale development in general also need further investigation. (USGS)

Synthesis and analysis of jet fuel from shale oil and coal syncrudes

NASA Technical Reports Server (NTRS)

Gallagher, J. P.; Collins, T. A.; Nelson, T. J.; Pedersen, M. J.; Robison, M. G.; Wisinski, L. J.

1976-01-01

Thirty-two jet fuel samples of varying properties were produced from shale oil and coal syncrudes, and analyzed to assess their suitability for use. TOSCO II shale oil and H-COAL and COED syncrudes were used as starting materials. The processes used were among those commonly in use in petroleum processing-distillation, hydrogenation and catalytic hydrocracking. The processing conditions required to meet two levels of specifications regarding aromatic, hydrogen, sulfur and nitrogen contents at two yield levels were determined and found to be more demanding than normally required in petroleum processing. Analysis of the samples produced indicated that if the more stringent specifications of 13.5% hydrogen (min.) and 0.02% nitrogen (max.) were met, products similar in properties to conventional jet fuels were obtained. In general, shale oil was easier to process (catalyst deactivation was seen when processing coal syncrudes), consumed less hydrogen and yielded superior products. Based on these considerations, shale oil appears to be preferred to coal as a petroleum substitute for jet fuel production.

Bacterial communities associated with production facilities of two newly drilled thermogenic natural gas wells in the Barnett Shale (Texas, USA).

PubMed

Davis, James P; Struchtemeyer, Christopher G; Elshahed, Mostafa S

2012-11-01

We monitored the bacterial communities in the gas-water separator and water storage tank of two newly drilled natural gas wells in the Barnett Shale in north central Texas, using a 16S rRNA gene pyrosequencing approach over a period of 6 months. Overall, the communities were composed mainly of moderately halophilic and halotolerant members of the phyla Firmicutes and Proteobacteria (classes Βeta-, Gamma-, and Epsilonproteobacteria) in both wells at all sampling times and locations. Many of the observed lineages were encountered in prior investigations of microbial communities from various fossil fluid formations and production facilities. In all of the samples, multiple H(2)S-producing lineages were encountered; belonging to the sulfate- and sulfur-reducing class Deltaproteobacteria, order Clostridiales, and phylum Synergistetes, as well as the thiosulfate-reducing order Halanaerobiales. The bacterial communities from the separator and tank samples bore little resemblance to the bacterial communities in the drilling mud and hydraulic-fracture waters that were used to drill these wells, suggesting the in situ development of the unique bacterial communities in such well components was in response to the prevalent geochemical conditions present. Conversely, comparison of the bacterial communities on temporal and spatial scales suggested the establishment of a core microbial community in each sampled location. The results provide the first overview of bacterial dynamics and colonization patterns in newly drilled, thermogenic natural gas wells and highlights patterns of spatial and temporal variability observed in bacterial communities in natural gas production facilities.

The optimized log interpretation method and sweet-spot prediction of gas-bearing shale reservoirs

NASA Astrophysics Data System (ADS)

Tan, Maojin; Bai, Ze; Xu, Jingjing

2017-04-01

Shale gas is one of the most important unconventional oil and gas resources, and its lithology and reservoir type are both different from conventional reservoirs [1,2]. "Where are shale reservoirs" "How to determine the hydrocarbon potential" "How to evaluate the reservoir quality", these are some key problems in front of geophysicists. These are sweet spots prediction and quantitative evaluation. As we known, sweet spots of organic shale include geological sweet spot and engineering sweet spot. Geophysical well logging can provide a lot of in-site formation information along the borehole, and all parameters describing the sweet spots of organic shale are attained by geophysical log interpretation[2]. Based on geological and petrophysical characteristics of gas shale, the log response characteristics of gas shales are summarized. Geological sweet spot includes hydrocarbon potential, porosity, fracture, water saturation and total gas content, which can be calculated by using wireline logs[3]. Firstly, the based-logging hydrocarbon potential evaluation is carried out, and the RBF neural network method is developed to estimate the total organic carbon content (TOC), which was proved more effective and suitable than empirical formula and ΔlogR methods [4]. Next, the optimized log interpretation is achieved by using model-searching, and the mineral concentrations of kerogen, clay, feldspar and pyrite and porosity are calculated. On the other hand, engineering sweet spot of shale refers to the rock physical properties and rock mechanism parameters. Some elastic properties including volume module, shear modulus and Poisson's ratio are correspondingly determined from log interpretation, and the brittleness index (BI), effective stress and pore pressure are also estimated. BI is one of the most important engineering sweet spot parameters. A large number of instances show that the summarized log responses can accurately identify the gas-bearing shale, and the proposed RBF method for TOC prediction has more suitable and flexibility. The mineral contents and porosity from the optimized log interpretation are in good agreement with core XRD experiment and other core experiments. In some polite wells of Jiaoshiba area, china, some parameters in Wufeng-Longmaxi formation are calculated, and geological and engineering sweet spots are finally determined. For the best sweet spot, TOC is about 6%, the porosity is about 8%,the volume of kerogen is about 3%, total gas content is 8m3/t, and the brittleness index is about 90%, and the minimum and maximum horizon stress are about 30MPa and 45 MPa. Therefore, the optimized log interpretation provide an important support for sweet spots prediction and quantitative evaluation of shale gas. References: [1] Sondergeld CH, Ambrose RJ, Rai CS, Moncrieff J. Micro-structure studies of gas shales: in SPE 2012; 131771: 150-166. [2] Ellis D V, Singer J M. 2012. Well Logging for Earth Scientists (2rd edition): Springer Press. [3]Fertl W H, Chillngar G V. 1988. Total organic carbon content determined from well logs: SPE formation evaluation, 407-419. [4] Tan M J, Liu Q, and Zhang S. 2002. A dynamic adaptive radial basis function approach for total organic carbon content prediction in organic shale. Geophysics, 2013, 78(6): 445-459. Acknowledgments: This paper is sponsored by National Natural Science Foundation of China (U1403191, 41172130), the Fundamental Research Funds for the Central Universities (292015209), and National Major Projects "Development of Major Oil& Gas Fields and Coal Bed Methane" (2016ZX05014-001).

The subsurface impact of hydraulic fracturing in shales- Perspectives from the well and reservoir

NASA Astrophysics Data System (ADS)

ter Heege, Jan; Coles, Rhys

2017-04-01

It has been identified that the main risks of subsurface shale gas operations in the U.S.A. and Canada are associated with (1) drilling and well integrity, (2) hydraulic fracturing, and (3) induced seismicity. Although it is unlikely that hydraulic fracturing operations result in direct pathways of enhanced migration between stimulated fracture disturbed rock volume and shallow aquifers, operations may jeopardize well integrity or induce seismicity. From the well perspective, it is often assumed that fluid injection leads to the initiation of tensile (mode I) fractures at different perforation intervals along the horizontal sections of shale gas wells if pore pressure exceeds the minimum principal stress. From the reservoir perspective, rise in pore pressure resulting from fluid injection may lead to initiation of tensile fractures, reactivation of shear (mode II) fractures if the criterion for failure in shear is exceeded, or combinations of different fracturing modes. In this study, we compare tensile fracturing simulations using conventional well-based models with shear fracturing simulations using a fractured shale model with characteristic fault populations. In the fractured shale model, stimulated permeability is described by an analytical model that incorporates populations of reactivated faults and that combines 3D permeability tensors for layered shale matrix, damage zone and fault core. Well-based models applied to wells crosscutting the Posidonia Shale Formation are compared to generic fractured shale models, and fractured shale models are compared to micro-seismic data from the Marcellus Shale. Focus is on comparing the spatial distribution of permeability, stimulated reservoir volume and seismicity, and on differences in fracture initiation pressure and fracture orientation for tensile and shear fracturing end-members. It is shown that incorporation of fault populations (for example resulting from analysis of 3D seismics or outcrops) in hydraulic fracturing models provides better constraints on well pressures, stimulated fracture disturbed volume and induced seismicity. Thereby, it helps assessing the subsurface impact of hydraulic fracturing in shales and mitigating risks associated with loss of loss of well integrity, loss of fracture containment, and induced seismicity.

Microstructural investigation of a locally mirror-like surface collected at 4 km depth in a Pomeranian shale sample

NASA Astrophysics Data System (ADS)

Pluymakers, Anne; Renard, Francois

2016-04-01

The presence of shiny sliding surfaces, or mirror surfaces, is sometimes thought to have been caused by slip at seismic velocities. Many fault mirrors reported so far are described to occur in carbonate-rich rocks. Here we present microstructural data on a mirror-like slip surface in the Pomeranian shale, recovered from approximately 4 km depth. The accommodated sliding of this fault is probably small, not more than one or two centimeter. The Pomeranian shale is a dark-grey to black shale, composed of 40-60% illite plus mica, 1-10% organic matter, 10% chlorite, and 10 % carbonates plus minor amounts of K-feldspar, plagioclase and kaolinite. In this sample, the surface is optically smooth with striations and some patches that reflect light. Observations using a Hitachi TM3000 (table-top) SEM show that the striations are omnipresent, though more prominent in the carbonate patches (determined using EDS analysis). The smooth surface is locally covered by granular material with a grain size up to 10 μm. This is shown to consist of a mixture of elements and thus likely locally derived fault gouge. The clay-rich parts of the smooth surface are equidimensional grains, with sub-micron grain sizes, whereas in the unperturbed part of the shale core the individual clay platelets are easy to distinguish, with lengths up to 10 μm. The striated calcite-rich patches appear as single grains with sizes up to several millimeters, though they occasionally are smeared out in a direction parallel to the striations. We have analyzed surface roughness at magnifications of 2.5x to 100x using a standard White Light Interferometer, parallel and perpendicular to slip. At low magnifications, 2.5x and 5x, Hurst exponents were anomalously low, around 0.1 to 0.2, interpreted to be related to a lack of sufficient resolution to pick up the striations. At higher magnification the Hurst exponent is 0.34 to 0.43 parallel to the striation, and 0.44 to 0.61 perpendicular to the striation. This relatively low Hurst exponent suggests that this surface has not experienced high strains, even though it locally exhibits mirror-like properties. As such, this data supports the notion that the formation of shiny surfaces is related to grain size reduction, but does not necessarily indicate major slip events. Additionally, the more strongly visible striation in the carbonate-rich parts indicates that some mineralogies are more prone to the formation of striations than others. A full interpretation of this sample is of course complicated by its small size, but these data suggest that when examining fault mirrors and the presence of striations spatial difference in mineralogy need to be taken into account.

Geological and geochemical characterization of the Lower Cretaceous Pearsall Formation, Maverick Basin, south Texas: A future shale gas resource?

USGS Publications Warehouse

Hackley, Paul C.

2012-01-01

As part of an assessment of undiscovered hydrocarbon resources in the northern Gulf of Mexico onshore Mesozoic section, the U.S. Geological Survey (USGS) evaluated the Lower Cretaceous Pearsall Formation of the Maverick Basin, south Texas, as a potential shale gas resource. Wireline logs were used to determine the stratigraphic distribution of the Pearsall Formation and to select available core and cuttings samples for analytical investigation. Samples used for this study spanned updip to downdip environments in the Maverick Basin, including several from the current shale gas-producing area of the Pearsall Formation.The term shale does not adequately describe any of the Pearsall samples evaluated for this study, which included argillaceous lime wackestones from more proximal marine depositional environments in Maverick County and argillaceous lime mudstones from the distal Lower Cretaceous shelf edge in western Bee County. Most facies in the Pearsall Formation were deposited in oxygenated environments as evidenced by the presence of biota preserved as shell fragments and the near absence of sediment laminae, which is probably caused by bioturbation. Organic material is poorly preserved and primarily consists of type III kerogen (terrestrial) and type IV kerogen (inert solid bitumen), with a minor contribution from type II kerogen (marine) based on petrographic analysis and pyrolysis. Carbonate dominates the mineralogy followed by clays and quartz. The low abundance and broad size distribution of pyrite are consistent with the presence of oxic conditions during sediment deposition. The Pearsall Formation is in the dry gas window of hydrocarbon generation (mean random vitrinite reflectance values, Ro = 1.2–2.2%) and contains moderate levels of total organic carbon (average 0.86 wt. %), which primarily resides in the inert solid bitumen. Solid bitumen is interpreted to result from in-situ thermal cracking of liquid hydrocarbon generated from original type II kerogen that was prevented from expulsion and migration by low permeability. The temperature of maximum pyrolysis output (Tmax) is a poor predictor of thermal maturity because the pyrolysis (S2) peaks from Rock-Eval analysis are ill defined. Vitrinite reflectance values are consistent with the dry gas window and are the preferred thermal maturity parameter.A Maverick Basin Pearsall shale gas assessment unit was defined using political and geologic boundaries to denote its spatial extent and was evaluated following established USGS hydrocarbon assessment methodology. The assessment estimated a mean undiscovered technically recoverable natural gas resource of 8.8 tcf of gas and 3.4 and 17.8 tcf of gas at the F95 and F5 fractile confidence levels, respectively. Significant engineering challenges will likely need to be met in determining the correct stimulation and completion combination for the successful future development of undiscovered natural gas resources in the Pearsall Formation.

Contributed Review: Nuclear magnetic resonance core analysis at 0.3 T

NASA Astrophysics Data System (ADS)

Mitchell, Jonathan; Fordham, Edmund J.

2014-11-01

Nuclear magnetic resonance (NMR) provides a powerful toolbox for petrophysical characterization of reservoir core plugs and fluids in the laboratory. Previously, there has been considerable focus on low field magnet technology for well log calibration. Now there is renewed interest in the study of reservoir samples using stronger magnets to complement these standard NMR measurements. Here, the capabilities of an imaging magnet with a field strength of 0.3 T (corresponding to 12.9 MHz for proton) are reviewed in the context of reservoir core analysis. Quantitative estimates of porosity (saturation) and pore size distributions are obtained under favorable conditions (e.g., in carbonates), with the added advantage of multidimensional imaging, detection of lower gyromagnetic ratio nuclei, and short probe recovery times that make the system suitable for shale studies. Intermediate field instruments provide quantitative porosity maps of rock plugs that cannot be obtained using high field medical scanners due to the field-dependent susceptibility contrast in the porous medium. Example data are presented that highlight the potential applications of an intermediate field imaging instrument as a complement to low field instruments in core analysis and for materials science studies in general.

Evolution of petrophysical properties of across natural faults: a study on cores from the Tournemire underground research laboratory (France)

NASA Astrophysics Data System (ADS)

Bonnelye, Audrey; David, Christian; Schubnel, Alexandre; Wassermann, Jérôme; Lefèvre, Mélody; Henry, Pierre; Guglielmi, Yves; Castilla, Raymi; Dick, Pierre

2017-04-01

Faults in general, and in clay materials in particular, have complex structures that can be linked to both a polyphased tectonic history and the anisotropic nature of the material. Drilling through faults in shaly materials allows one to measure properties such as the structure, the mineralogical composition, the stress orientation or physical properties. These relations can be investigated in the laboratory in order to have a better understanding on in-situ mechanisms. In this study we used shales of Toarcian age from the Tournemire underground research laboratory (France). We decided to couple different petrophysical measurements on core samples retrieved from a borehole drilled perpendicularly to a fault plane, and the fault size is of the order of tens of meters. This 25m long borehole was sampled in order to perform several types of measurements: density, porosity, saturation directly in the field, and velocity of elastic waves and magnetic susceptibility anisotropy in the laboratory. For all these measurements, special protocols were developed in order to preserve as much as possible the saturation state of the samples. All these measurements were carried out in three zones that intersects the borehole: the intact zone , the damaged zone and the fault core zone. From our measurements, we were able to associate specific properties to each zone of the fault. We then calculated Thomsen's parameters in order to quantify the elastic anisotropy across the fault. Our results show strong variations of the elastic anisotropy with the distance to the fault core as well as the occurrence of anisotropy reversal.

13C Nuclear magnetic resonance studies of kerogen from Cretaceous black shales thermally altered by basaltic intrusions and laboratory simulations

USGS Publications Warehouse

Dennis, L.W.; Maciel, G.E.; Hatcher, P.G.; Simoneit, B.R.T.

1982-01-01

Cretaceous black shales from DSDP Leg 41, Site 368 in the Eastern Atlantic Ocean were thermally altered during the Miocene by an intrusive basalt. The sediments overlying and underlying the intrusive body were subjected to high temperatures (up to ~ 500??C) and, as a result, their kerogen was significantly altered. The extent of this alteration has been determined by examination by means of 13C nuclear magnetic resonance, using cross polarization/magic-angle spinning (CP/MAS). Results indicate that the kerogen becomes progressively more aromatic in the vicinity of the intrusive body. Laboratory heating experiments, simulating the thermal effects of the basaltic intrusion, produced similar results on unaltered shale from the drill core. The 13C CP/MAS results appear to provide a good measure of thermal alteration. ?? 1982.

Estimation of anisotropy parameters in organic-rich shale: Rock physics forward modeling approach

DOE Office of Scientific and Technical Information (OSTI.GOV)

Herawati, Ida, E-mail: ida.herawati@students.itb.ac.id; Winardhi, Sonny; Priyono, Awali

Anisotropy analysis becomes an important step in processing and interpretation of seismic data. One of the most important things in anisotropy analysis is anisotropy parameter estimation which can be estimated using well data, core data or seismic data. In seismic data, anisotropy parameter calculation is generally based on velocity moveout analysis. However, the accuracy depends on data quality, available offset, and velocity moveout picking. Anisotropy estimation using seismic data is needed to obtain wide coverage of particular layer anisotropy. In anisotropic reservoir, analysis of anisotropy parameters also helps us to better understand the reservoir characteristics. Anisotropy parameters, especially ε, aremore » related to rock property and lithology determination. Current research aims to estimate anisotropy parameter from seismic data and integrate well data with case study in potential shale gas reservoir. Due to complexity in organic-rich shale reservoir, extensive study from different disciplines is needed to understand the reservoir. Shale itself has intrinsic anisotropy caused by lamination of their formed minerals. In order to link rock physic with seismic response, it is necessary to build forward modeling in organic-rich shale. This paper focuses on studying relationship between reservoir properties such as clay content, porosity and total organic content with anisotropy. Organic content which defines prospectivity of shale gas can be considered as solid background or solid inclusion or both. From the forward modeling result, it is shown that organic matter presence increases anisotropy in shale. The relationships between total organic content and other seismic properties such as acoustic impedance and Vp/Vs are also presented.« less

Fractal Characteristics of Continental Shale Pores and its Significance to the Occurrence of Shale Oil in China: a Case Study of Biyang Depression

NASA Astrophysics Data System (ADS)

Li, Jijun; Liu, Zhao; Li, Junqian; Lu, Shuangfang; Zhang, Tongqian; Zhang, Xinwen; Yu, Zhiyuan; Huang, Kaizhan; Shen, Bojian; Ma, Yan; Liu, Jiewen

Samples from seven major exploration wells in Biyang Depression of Henan Oilfield were compared using low-temperature nitrogen adsorption and shale oil adsorption experiments. Comprehensive analysis of pore development, oiliness and shale oil flowability was conducted by combining fractal dimension. The results show that the fractal dimension of shale in Biyang Depression of Henan Oilfield was negatively correlated with the average pore size and positively correlated with the specific surface area. Compared with the large pore, the small pore has great fractal dimension, indicating the pore structure is more complicated. Using S1 and chloroform bitumen A to evaluate the relationship between shale oiliness and pore structure, it was found that the more heterogeneous the shale pore structure, the higher the complexity and the poorer the oiliness. Clay minerals are the main carriers involved in crude oil adsorption, affecting the mobility of shale oil. When the pore complexity of shale was high, the content of micro- and mesopores was high, and the high specific surface area could enhance the adsorption and reduce the mobility of shale oil.

Reconstruction of the Paleoproterozoic deeper ocean environment: Preliminary Report of the Ghana Birimian Greenstone Belt Drilling Project (GHB)

NASA Astrophysics Data System (ADS)

Kiyokawa, S.; Yoshimaru, S.; Miki, T.; Sakai, S.; Ikehara, M.; Yamaguchi, K. E.; Ito, T.; Onoue, T.; Takehara, M.; Tetteh, G. M.; Nyame, F. K.

2016-12-01

The Paleoproterozoic Era are one of the most rapid environmental change when the earth surface environment was affected by formation of continents and increasing atmospheric oxygen levels. Major oxidation of Great Oxidation Event (GOE) are reported this ages (eg. Holland, 2006; Condie, 2001; Lyons et al., 2014). The nature of deep sea environments at this time have not been clearly identified and oceanic sediments are mostly involved in subduction. The Paleoproterozoic Birimian Greenstone Belt is an ophiolitic volcaniclastic sequence in Ghana, with depositional age of over 2.3-2.2 Ga (Petersson et al., 2016). Detail research was conducted of the Ashanti (Axim-Konongo) Belt of the Birimian Greenstone Belt along the coast near Cape Three Points area. Very thick volcaniclastic and organic-rich sedimentary rocks, which we now refer to as the Cape Three Points Group, crop out in the lower part of the Birimian Greenstone Belt. Stratigraphically, three unit identified; the lower portion contains thick vesicular volcaniclastic rocks, the middle portion is made up of laminated volcaniclastics and black shale, and the upper portion dominated by fine laminated volcaniclastics with more black shale sequence. Continuous core drilling from Dec 3-12th 2015 of the upper part of the sequence intersected saprolite to a depth of 30m and fresh, well preserved stratigraphy with graded bedding and lamination to a depth of 195m. Half cut cores show well laminated organic rich black shale and relative carbonate rich layers with very fine pyrite grains. SHRIMP age data from a porphyry intrusion into this sequence indicate an age of 2250 Ma. Carbon isotope analysis shows δ13C = -43 to -37‰ for black shale with the very light isotope values for cyanobacterial signature.The fining-upward sequences, well laminated bed and black shales and REE data suggest this sequence situated partly silent stagnant with volcanic activity ocean floor environment around an oceanic island arc condition.

Texture, mineralogy and geochemistry of the continental slope sediments in front of Los Tuxtlas, Gulf of Mexico, Mexico: implications on weathering, origin and depositional environments

NASA Astrophysics Data System (ADS)

Marca-Castillo, M. E.; Armstrong-Altrin, J.

2017-12-01

The textural analysis, mineralogy and geochemistry of two sediment cores recovered from the deep water zone of the southwestern part of the Gulf of Mexico ( 1666 and 1672 m water depth) were studied to infer the provenance and depositional behavior. The textural analysis revealed that both cores are dominated by silt, which occupy more than 50% in both samples and the clay occupy 40%. The petrographic analysis revealed remains of biogenic origin sediments and lithic fragments with an angular shape and low sphericity, indicating a low energy environment and therefore a low level of weathering in the sediment, which suggests that the sediments were not affected by transport and derived from a nearby source rock. In both cores quartz fragments were identified; also volcanic lithic and pyroxenes fragments, which are rocks of intermediate composition and are generally associated with the volcanic activity of the continental margins. SEM-EDS studies showed that the analysed samples have concentrations of minerals such as barite, gibbsite, kaolinite, grossular, magnetite, plagioclase and chlorite, which are probably derived from the mainland to the deep sea zone. In the trace element analysis it was observed a low Sc content, while Co, Ni, V and Cu are slightly enriched with respect to the upper continental crust; this enrichment is related to sediments from intermediate sources. The sediments are classified as shale in the log (SiO2 / Al2O3) - log (Fe2O / K2O) diagram. The fine particles of the shale indicate that a deposit occurred as a result of the gradual sedimentation due to relatively non-turbulent currents, which is consistent with the petrographic analysis. The geochemical features of major and trace elements suggest sediments were derived largely from the natural andesite erosion of coastal regions along the Gulf of Mexico. High values of Fe2O3 and MnO are observed in the upper intervals, reflecting the influence of volcanic sediments. The major element discriminant function diagrams indicate the provenance of sediments from a passive margin, which is consistent with the geology of the Gulf of Mexico.

Multiple sulfur isotope characteristics of 3.46-2.7 Ga sedimentary rocks from drill cores of the Archean Biosphere Drilling Project (Invited)

NASA Astrophysics Data System (ADS)

Watanabe, Y.; Ohmoto, H.

2010-12-01

As part of the Archean Biosphere Drilling Project (ABDP), we have determined the multiple sulfur isotope ratios and examined the mineralogical and geochemical characteristics of the sulfur-bearing minerals (e.g., pyrite, sphalerite, barite) and the host rocks (e.g., major and trace element chemistry; Corg, Ccarb and S contents; δ13Corg and δ13Ccarb) of >100 samples of sedimentary rocks from five ABDP drill cores in the Pilbara Craton, Western Australia. The total ranges of Δ33S and δ34S values of the studied samples are -0.9 to +1.2‰ and -4 to +8‰, respectively. We have found that the Δ33S and δ34S relationships show unique values depending on their depositional environment: (1) Pyrites in the 3.46 Ga Marble Bar Chert Member (ABDP #1), which were formed by submarine hydrothermal fluids, show no AIF-S (anomalously fractionated sulfur isotope) signatures: Δ33S = -0.08 to +0.08‰ and δ34S = -3.3 to +0.6‰ (n = 5). This indicates that the H2S presented in the submarine hydrothermal fluid, which was partly generated through seawater sulfate reduction by Fe2+, did not possess AIF-S signatures. (2) Pyrites in organic C-poor lacustrine shales of the 2.76 Ga Hardey Formation (ABDP #3) also show no or very little AIF-S signatures: Δ33S = -0.38 to +0.25‰ and δ34S = -2.7 to +1.9‰ (n = 18). (3) Pyrites in organic C-poor marine shales of the 2.92 Ga Mosquito Creek Formation (ABDP#5) show no or small negative AIF-S signatures: Δ33S = -0.59 to 0.19 ‰ and all positive δ34S = +1.4 to +7.7‰ (n = 24). (4) Pyrites in organic C-rich (> 1 wt%) and hydrothermally altered marine shales in the 3.46 Ga Panorama Formation (ABDP #2) show constant and small positive AIF-S signatures (+0.44 to +0.61‰) and the smallest variation in δ34S (-1.1 to +1.6‰) (n = 35). In contrast, pyrites in organic C-rich shales in the 2.72 Ga Mt. Roe Basalt show negative Δ33S = -0.50 to -0.10‰ and δ34S = -3.7 to 1.8‰ (n = 10). (5) Pyrites in stromatolitic carbonates of the 2.7 Ga Tumbiana Formation (ABDP #10), which deposited in shallow evaporating marine basins, possess the largest variation in AIF-S signatures among five ABDP cores: Δ33S = -0.86 to 1.19‰ and δ34S = -3.2 to +1.5‰ (n = 10). (6) Compared to the negative Δ33S values (-1.28 to -0.47‰) of barites in the 3.2 Ga Dresser Formation (e.g., Ueno et al., 2009), Δ33S values of barites in the 3.46 Ga Panorama Formation (ABDP #2) are all positive (+0.55 to +0.61‰) and identical to those of reduced sulfur species (sphalerite and pyrite) in the same sample. The observed relationships between AIF-S signatures and depositional environments, and the abundance of samples with no AIF-S signatures, are difficult to explain by the current popular model that links AIF-S to atmospheric UV reactions. However, the data can be best explained by our model that links AIF-S to thermochemical sulfate reduction (TSR) by various solid phases and S-bearing aqueous/gaseous species (e.g., TSR by organic matter; replacement of iron oxides by pyrite) under hydrothermal conditions in a local and/or regional (basin wide) scale. Therefore, the AIF-S record of sedimentary rocks may be linked to the Earth’s thermal and biological evolution, rather than to the atmospheric evolution.

Time-dependent deformation of gas shales - role of rock framework versus reservoir fluids

NASA Astrophysics Data System (ADS)

Hol, Sander; Zoback, Mark

2013-04-01

Hydraulic fracturing operations are generally performed to achieve a fast, drastic increase of permeability and production rates. Although modeling of the underlying short-term mechanical response has proven successful via conventional geomechanical approaches, predicting long-term behavior is still challenging as the formation interacts physically and chemically with the fluids present in-situ. Recent experimental work has shown that shale samples subjected to a change in effective stress deform in a time-dependent manner ("creep"). Although the magnitude and nature of this behavior is strongly related to the composition and texture of the sample, also the choice of fluid used in the experiments affects the total strain response - strongly adsorbing fluids result in more, recoverable creep. The processes underlying time-dependent deformation of shales under in-situ stresses, and the long-term impact on reservoir performance, are at present poorly understood. In this contribution, we report triaxial mechanical tests, and theoretical/thermodynamic modeling work with the aim to identify and describe the main mechanisms that control time-dependent deformation of gas shales. In particular, we focus on the role of the shale solid framework versus the type and pressure of the present pore fluid. Our experiments were mainly performed on Eagle Ford Shale samples. The samples were subjected to cycles of loading and unloading, first in the dry state, and then again after equilibrating them with (adsorbing) CO2 and (non-adsorbing) He at fluid pressures of 4 MPa. Stresses were chosen close to those persisting under in-situ conditions. The results of our tests demonstrate that likely two main types of deformation mechanisms operate that relate to a) the presence of microfractures as a dominating feature in the solid framework of the shale, and b) the adsorbing potential of fluids present in the nanoscale voids of the shale. To explain the role of adsorption in the observed compaction creep, we postulate a serial coupling between 1) stress-driven desorption of the fluid species, 2) diffusion of the desorbed species out of the solid, and 3) consequent shrinkage. We propose a model in which the total shrinkage of the solid (Step 3) that is measured as bulk compaction, is driven by a change in stress state (Step 1), and evolves in time controlled by the diffusion characteristics of the system (Step 2). Our experimental and modeling study shows that both the nature of the solid framework of the shale, as well as the type and pressure of pore fluids affect the long-term in-situ mechanical behavior of gas shale reservoirs.

Multiscale study for stochastic characterization of shale samples

NASA Astrophysics Data System (ADS)

Tahmasebi, Pejman; Javadpour, Farzam; Sahimi, Muhammad; Piri, Mohammad

2016-03-01

Characterization of shale reservoirs, which are typically of low permeability, is very difficult because of the presence of multiscale structures. While three-dimensional (3D) imaging can be an ultimate solution for revealing important complexities of such reservoirs, acquiring such images is costly and time consuming. On the other hand, high-quality 2D images, which are widely available, also reveal useful information about shales' pore connectivity and size. Most of the current modeling methods that are based on 2D images use limited and insufficient extracted information. One remedy to the shortcoming is direct use of qualitative images, a concept that we introduce in this paper. We demonstrate that higher-order statistics (as opposed to the traditional two-point statistics, such as variograms) are necessary for developing an accurate model of shales, and describe an efficient method for using 2D images that is capable of utilizing qualitative and physical information within an image and generating stochastic realizations of shales. We then further refine the model by describing and utilizing several techniques, including an iterative framework, for removing some possible artifacts and better pattern reproduction. Next, we introduce a new histogram-matching algorithm that accounts for concealed nanostructures in shale samples. We also present two new multiresolution and multiscale approaches for dealing with distinct pore structures that are common in shale reservoirs. In the multiresolution method, the original high-quality image is upscaled in a pyramid-like manner in order to achieve more accurate global and long-range structures. The multiscale approach integrates two images, each containing diverse pore networks - the nano- and microscale pores - using a high-resolution image representing small-scale pores and, at the same time, reconstructing large pores using a low-quality image. Eventually, the results are integrated to generate a 3D model. The methods are tested on two shale samples for which full 3D samples are available. The quantitative accuracy of the models is demonstrated by computing their morphological and flow properties and comparing them with those of the actual 3D images. The success of the method hinges upon the use of very different low- and high-resolution images.

Determination of elemental composition of shale rocks by laser induced breakdown spectroscopy

NASA Astrophysics Data System (ADS)

Sanghapi, Hervé K.; Jain, Jinesh; Bol'shakov, Alexander; Lopano, Christina; McIntyre, Dustin; Russo, Richard

2016-08-01

In this study laser induced breakdown spectroscopy (LIBS) is used for elemental characterization of outcrop samples from the Marcellus Shale. Powdered samples were pressed to form pellets and used for LIBS analysis. Partial least squares regression (PLS-R) and univariate calibration curves were used for quantification of analytes. The matrix effect is substantially reduced using the partial least squares calibration method. Predicted results with LIBS are compared to ICP-OES results for Si, Al, Ti, Mg, and Ca. As for C, its results are compared to those obtained by a carbon analyzer. Relative errors of the LIBS measurements are in the range of 1.7 to 12.6%. The limits of detection (LODs) obtained for Si, Al, Ti, Mg and Ca are 60.9, 33.0, 15.6, 4.2 and 0.03 ppm, respectively. An LOD of 0.4 wt.% was obtained for carbon. This study shows that the LIBS method can provide a rapid analysis of shale samples and can potentially benefit depleted gas shale carbon storage research.

Comparison of organic geochemistry and metal enrichment in two black shales: Cambrian Alum Shale of Sweden and Devonian Chattanooga Shale of United States

USGS Publications Warehouse

Leventhal, J.S.

1991-01-01

In most black shales, such as the Chattanooga Shale and related shales of the eastern interior United States, increased metal and metalloid contents are generally related to increased organic carbon content, decreased sedimentation rate, organic matter type, or position in the basin. In areas where the stratigraphic equivalents of the Chattanooga Shale are deeply buried and and the organic material is thermally mature, metal contents are essentially the same as in unheated areas and correlate with organic C or S contents. This paradigm does not hold for the Cambrian Alum Shale Formation of Sweden where increased metal content does not necessarily correlate with organic matter content nor is metal enrichment necessarily related to land derived humic material because this organic matter is all of marine source. In southcentral Sweden the elements U, Mo, V, Ni, Zn, Cd and Pb are all enriched relative to average black shales but only U and Mo correlate to organic matter content. Tectonically disturbed and metamorphosed allochthonous samples of Alum Shale on the Caledonian front in western Sweden have even higher amounts for some metals (V, Ni, Zn and Ba) relative to the autochthonous shales in this area and those in southern Sweden. ?? 1991 Springer-Verlag.

Comparative acute toxicity of shale and petroleum derived distillates.

PubMed

Clark, C R; Ferguson, P W; Katchen, M A; Dennis, M W; Craig, D K

1989-12-01

In anticipation of the commercialization of its shale oil retorting and upgrading process, Unocal Corp. conducted a testing program aimed at better defining potential health impacts of a shale industry. Acute toxicity studies using rats and rabbits compared the effects of naphtha, Jet-A, JP-4, diesel and "residual" distillate fractions of both petroleum derived crude oils and hydrotreated shale oil. No differences in the acute oral (greater than 5 g/kg LD50) and dermal (greater than 2 g/kg LD50) toxicities were noted between the shale and petroleum derived distillates and none of the samples were more than mildly irritating to the eyes. Shale and petroleum products caused similar degrees of mild to moderate skin irritation. None of the materials produced sensitization reactions. The LC50 after acute inhalation exposure to Jet-A, shale naphtha, (greater than 5 mg/L) and JP-4 distillate fractions of petroleum and shale oils was greater than 5 mg/L. The LC50 of petroleum naphtha (greater than 4.8 mg/L) and raw shale oil (greater than 3.95 mg/L) also indicated low toxicity. Results demonstrate that shale oil products are of low acute toxicity, mild to moderately irritating and similar to their petroleum counterparts. The results further demonstrate that hydrotreatment reduces the irritancy of raw shale oil.

Sedimentary provenance of Maastrichtian oil shales, Central Eastern Desert, Egypt

NASA Astrophysics Data System (ADS)

Fathy, Douaa; Wagreich, Michael; Mohamed, Ramadan S.; Zaki, Rafat

2017-04-01

Maastrichtian oil shales are distributed within the Central Eastern Desert in Egypt. In this study elemental geochemical data have been applied to investigate the probable provenance of the sedimentary detrital material of the Maastrichtian oil shale beds within the Duwi and the Dakhla formations. The Maastrichtian oil shales are characterized by the enrichment in Ca, P, Mo, Ni, Zn, U, Cr and Sr versus post-Archean Australian shales (PAAS). The chondrite-normalized patterns of the Maastrichtian oil shale samples are showing LREE enrichment, HREE depletion, slightly negative Eu anomaly, no obvious Ce anomaly and typical shale-like PAAS-normalized patterns. The total REE well correlated with Si, Al, Fe, K and Ti, suggesting that the REE of the Maastrichtian oil shales are derived from terrigenous source. Chemical weathering indices such as Chemical Index of Alteration (CIA), Chemical Proxy of Alteration (CPA) and Plagioclase Index of Alteration (PIA) indicate moderate to strong chemical weathering. We suggest that the Maastrichtian oil shale is mainly derived from first cycle rocks especially intermediate rocks without any significant inputs from recycled or mature sources. The proposed data illustrated the impact of the parent material composition on evolution of oil shale chemistry. Furthermore, the paleo-tectonic setting of the detrital source rocks for the Maastrichtian oil shale is probably related to Proterozoic continental island arcs

New type of kinematic indicator in bed-parallel veins, Late Jurassic-Early Cretaceous Vaca Muerta Formation, Argentina: E-W shortening during Late Cretaceous vein opening

NASA Astrophysics Data System (ADS)

Ukar, Estibalitz; Lopez, Ramiro G.; Gale, Julia F. W.; Laubach, Stephen E.; Manceda, Rene

2017-11-01

In the Late Jurassic-Early Cretaceous Vaca Muerta Formation, previously unrecognized yet abundant structures constituting a new category of kinematic indicator occur within bed-parallel fibrous calcite veins (BPVs) in shale. Domal shapes result from localized shortening and thickening of BPVs and the intercalation of centimeter-thick, host-rock shale inclusions within fibrous calcite beef, forming thrust fault-bounded pop-up structures. Ellipsoidal and rounded structures show consistent orientations, lineaments of interlayered shale and fibrous calcite, and local centimeter-scale offset thrust faults that at least in some cases cut across the median line of the BPV and indicate E-W shortening. Continuity of crystal fibers shows the domal structures are contemporaneous with BPV formation and help establish timing of fibrous vein growth in the Late Cretaceous, when shortening directions were oriented E-W. Differences in the number of opening stages and the deformational style of the different BPVs indicate they may have opened at different times. The new domal kinematic indicators described in this study are small enough to be captured in core. When present in the subsurface, domal structures can be used to either infer paleostress orientation during the formation of BPVs or to orient core in cases where the paleostress is independently known.

Mesoarchean black shale -iron sedimentary sequences in Cleaverville Formation, Pilbara Australia: drilling preliminary result of DXCL2

NASA Astrophysics Data System (ADS)

Kiyokawa, S.; Ito, T.; Ikehara, M.; Yamaguchi, K. E.; Onoue, T.; Horie, K.; Sakamoto, R.; Teraji, S.; Aihara, Y.

2012-12-01

The 3.2-3.1 Ga Dixon island-Cleaverville formations are well-preserved hydrothermal oceanic sequence at oceanic island arc setting (Kiyokawa et al., 2002, 2006, 2012). The Dixon Island (3195+15 Ma) - Cleaverville (3108+13 Ma) formations formed volcano-sedimentary sequences with hydrothermal chert, black shale and banded iron formation to the top. Based on the scientific drilling as DXCL1 at 2007 and DXCL2 at 2011, lithology was clearly understood. Four drilling holes had been done at coastal sites; the Dixon Island Formation is DX site (100m) and the Cleaverville Formation is CL2 (40m), CL1 (60m) and CL3 (200m) sites and from stratigraphic bottom to top. These sequences formed coarsening and thickening upward black shale-BIF sequences. The Dixon Island Formation consists komatiite-rhyolite sequences with many hydrothermal veins and very fine laminated cherty rocks above them. The Cleaverville Formation contains black shale, fragments-bearing pyroclastic beds, white chert, greenish shale and BIF. Especially, CL3 core, which drilled through the Iron formation, shows siderite-chert beds above black shale identified before magnetite lamination bed. The magnetite bed formed very thin laminated bed with siderite lamination. This magnetite bed was covered by black shale beds again. New U-Pb SHRIMP data of the pyroclastic in black shale is 3109Ma. Estimated 2-8 cm/1000year sedimentation rate are identified in these sequences. Our preliminary result show that siderite and chert layers formed before magnetite iron sedimentation. The lower-upper sequence of organic carbon rich black shales are similar amount of organic content and 13C isotope (around -30per mill). So we investigate that the Archean iron formation, especially Cleaverville iron formation, was highly related by hydrothermal input and started pre-syn iron sedimentation at anoxic oceanic condition.

Multi-physics and multi-scale characterization of shale anisotropy

NASA Astrophysics Data System (ADS)

Sarout, J.; Nadri, D.; Delle Piane, C.; Esteban, L.; Dewhurst, D.; Clennell, M. B.

2012-12-01

Shales are the most abundant sedimentary rock type in the Earth's shallow crust. In the past decade or so, they have attracted increased attention from the petroleum industry as reservoirs, as well as more traditionally for their sealing capacity for hydrocarbon/CO2 traps or underground waste repositories. The effectiveness of both fundamental and applied shale research is currently limited by (i) the extreme variability of physical, mechanical and chemical properties observed for these rocks, and by (ii) the scarce data currently available. The variability in observed properties is poorly understood due to many factors that are often irrelevant for other sedimentary rocks. The relationships between these properties and the petrophysical measurements performed at the field and laboratory scales are not straightforward, translating to a scale dependency typical of shale behaviour. In addition, the complex and often anisotropic micro-/meso-structures of shales give rise to a directional dependency of some of the measured physical properties that are tensorial by nature such as permeability or elastic stiffness. Currently, fundamental understanding of the parameters controlling the directional and scale dependency of shale properties is far from complete. Selected results of a multi-physics laboratory investigation of the directional and scale dependency of some critical shale properties are reported. In particular, anisotropic features of shale micro-/meso-structures are related to the directional-dependency of elastic and fluid transport properties: - Micro-/meso-structure (μm to cm scale) characterization by electron microscopy and X-ray tomography; - Estimation of elastic anisotropy parameters on a single specimen using elastic wave propagation (cm scale); - Estimation of the permeability tensor using the steady-state method on orthogonal specimens (cm scale); - Estimation of the low-frequency diffusivity tensor using NMR method on orthogonal specimens (<μm scale). For each of the above properties, leading-edge experimental techniques have been associated with novel interpretation tools. In this contribution, these experimental and interpretation methods are described. Relationships between the measured properties and the corresponding micro-/meso-structural features are discussed. For example, P-wave velocity was measured along 100 different propagation paths on a single cylindrical shale specimen using miniature ultrasonic transducers. Assuming that (i) the elastic tensor of this shale is transversely isotropic; and (i) the sample has been cored perfectly perpendicular to the bedding plane (symmetry plane is horizontal), Thomsen's anisotropy parameters inverted from the measured velocities are: - P-wave velocity along the symmetry axis (perpendicular to the bedding plane) αo=3.45km/s; - P-wave anisotropy ɛ=0.12; - Parameter controlling the wave front geometry δ=0.058. A novel inversion algorithm allows for recovering these parameters without assuming a priori a horizontal bedding (symmetry) plane. The inversion of the same data set using this algorithm yields (i) αo=3.23km/s, ɛ=0.25 and δ=0.18, and (ii) the elastic symmetry axis is inclined of ω=30° with respect to the specimen's axis. Such difference can have strong impact on field applications (AVO, ray tracing, tomography).

Experimental Determination of P-V-T-X Properties and Adsorption Kinetics in the CO2-CH4 System under Shale Gas Reservoir Conditions

NASA Astrophysics Data System (ADS)

Xiong, Y.; Wang, Y.

2014-12-01

Shale gas production via hydrofracturing has profoundly changed the energy portfolio in the USA and other parts of the world. Under the shale gas reservior conditions, CO2 and H2O, either in residence or being injected during hydrofracturing or both, co-exist with CH4. One important feature characteristic of shale is the presence of nanometer-scale (1-100 nm) pores in shale or mudstone. The interactions among CH4, CO2 and H2O in those nano-sized pores directly impact shale gas storage and gas release from the shale matrix. Therefore, a fundamental understanding of interactions among CH4, CO2 and H2O in nanopore confinement would provide guidance in addressing a number of problems such as rapid decline in production after a few years and low recovery rates. We are systematically investigating the P-V-T-X properties and adsorption kinetics in the CH4-CO2-H2O system under the reservior conditions. We have designed and constructed a unique high temperature and pressure experimental system that can measure both of the P-V-T-X properties and adsorption kinetics sequentially. We measure the P-V-T-X properties of CH4-CO2 mixtures with CH4 up to 95 vol. %, and adsorption kinetics of various materials, under the conditions relevant to shale gas reservoir. We use three types of materials: (I) model materials, (II) single solid phases separated from shale samples, and (III) crushed shale samples from both the known shale gas producing formations and the shale gas barren formations. The model materials are well characterized in terms of pore sizes. Therefore, the results associated with the model material serve as benchmarks for our model development. Sandia National Laboratories is a multi-program laboratory operated by Sandia Corporation, a wholly owned subsidiary of Lockheed Martin Corporation, for the U.S. Department of Energy's National Nuclear Security Administration under contract DE-AC04-94AL85000. This research is supported by a Geoscience Foundation LDRD.

Effects of acid-volatile sulfide on metal bioavailability and toxicity to midge (Chironomus tentans) larvae in black shale sediments

USGS Publications Warehouse

Ogendi, G.M.; Brumbaugh, W.G.; Hannigan, R.E.; Farris, J.L.

2007-01-01

Metal bioavailability and toxicity to aquatic organisms are greatly affected by variables such as pH, hardness, organic matter, and sediment acid-volatile sulfide (AVS). Sediment AVS, which reduces metal bioavailability and toxicity by binding and immobilizing metals as insoluble sulfides, has been studied intensely in recent years. Few studies, however, have determined the spatial variability of AVS and its interaction with simultaneously extracted metals (SEM) in sediments containing elevated concentrations of metals resulting from natural geochemical processes, such as weathering of black shales. We collected four sediment samples from each of four headwater bedrock streams in northcentral Arkansa (USA; three black shale-draining streams and one limestone-draining stream). We conducted 10-d acute whole-sediment toxicity tests using the midge Chironomus tentans and performed analyses for AVS, total metals, SEMs, and organic carbon. Most of the sediments from shale-draining streams had similar total metal and SEM concentrations but considerable differences in organic carbon and AVS. Zinc was the leading contributor to the SEM molar sum, averaging between 68 and 74%, whereas lead and cadmium contributed less than 3%. The AVS concentration was very low in all but two samples from one of the shale streams, and the sum of the SEM concentrations was in molar excess of AVS for all shale stream sediments. No significant differences in mean AVS concentrations between sediments collected from shale-draining or limestone-draining sites were noted (p > 0.05). Midge survival and growth in black shale-derived sediments were significantly less (p < 0.001) than that of limestone-derived sediments. On the whole, either SEM alone or SEM-AVS explained the total variation in midge survival and growth about equally well. However, survival and growth were significantly greater (p < 0.05) in the two sediment samples that contained measurable AVS compared with the two sediments from the same stream that contained negligible AVS. ?? 2007 SETAC.

Oil shale resources in the Eocene Green River Formation, Greater Green River Basin, Wyoming, Colorado, and Utah

USGS Publications Warehouse

,

2011-01-01

The U.S. Geological Survey (USGS) recently completed a comprehensive assessment of in-place oil in oil shales in the Eocene Green River in the Greater Green River Basin, Wyoming, Colorado, and Utah. This CD-ROM includes reports, data, and an ArcGIS project describing the assessment. A database was compiled that includes about 47,000 Fischer assays from 186 core holes and 240 rotary drill holes. Most of the oil yield data were analyzed by the former U.S. Bureau of Mines oil shale laboratory in Laramie, Wyoming, and some analyses were made by private laboratories. Location data for 971 Wyoming oil-shale drill holes are listed in a spreadsheet and included in the CD-ROM. Total in-place resources for the three assessed units in the Green River Formation are: (1) Tipton Shale Member, 362,816 million barrels of oil (MMBO), (2) Wilkins Peak Member, 704,991 MMBO, and (3) LaClede Bed of the Laney Member, 377,184 MMBO, for a total of 1.44 trillion barrels of oil in place. This compares with estimated in-place resources for the Piceance Basin of Colorado of 1.53 trillion barrels and estimated in-place resources for the Uinta Basin of Utah and Colorado of 1.32 trillion barrels.

Assessing Radium Activity in Shale Gas Produced Brine

NASA Astrophysics Data System (ADS)

Fan, W.; Hayes, K. F.; Ellis, B. R.

2015-12-01

The high volumes and salinity associated with shale gas produced water can make finding suitable storage or disposal options a challenge, especially when deep well brine disposal or recycling for additional well completions is not an option. In such cases, recovery of commodity salts from the high total dissolved solids (TDS) of the brine wastewater may be desirable, yet the elevated concentrations of the naturally occurring radionuclides such as Ra-226 and Ra-228 in produced waters (sometimes substantially greater than the EPA limit of 5 pCi/L) may concentrate during these steps and limit salt recovery options. Therefore, assessing the potential presence of these Ra radionuclides in produced water from shale gas reservoir properties is desirable. In this study, we seek to link U and Th content within a given shale reservoir to the expected Ra content of produced brine by accounting for secular equilibrium within the rock and subsequent release to Ra to native brines. Produced brine from a series of Antrim shale wells and flowback from a single Utica-Collingwood shale well in Michigan were sampled and analyzed via ICP-MS to measure Ra content. Gamma spectroscopy was used to verify the robustness of this new Ra analytical method. Ra concentrations were observed to be up to an order of magnitude higher in the Antrim flowback water samples compared to those collected from the Utica-Collingwood well. The higher Ra content in Antrim produced brines correlates well with higher U content in the Antrim (19 ppm) relative to the Utica-Collingwood (3.5 ppm). We also observed an increase in Ra activity with increasing TDS in the Antrim samples. This Ra-TDS relationship demonstrates the influence of competing divalent cations in controlling Ra mobility in these clay-rich reservoirs. In addition, we will present a survey of geochemical data from other shale gas plays in the U.S. correlating shale U, Th content with produced brine Ra content. A goal of this study is to develop a method to predict the expected Ra activity in shale gas produced brines on a regional or play-specific basis in an effort to guide wastewater management practices or optimize regional treatment strategies.

Fractal Characteristics of Pores in Taiyuan Formation Shale from Hedong Coal Field, China

NASA Astrophysics Data System (ADS)

Li, Kunjie; Zeng, Fangui; Cai, Jianchao; Sheng, Guanglong; Xia, Peng; Zhang, Kun

For the purpose of investigating the fractal characteristics of pores in Taiyuan formation shale, a series of qualitative and quantitative experiments were conducted on 17 shale samples from well HD-1 in Hedong coal field of North China. The results of geochemical experiments show that Total organic carbon (TOC) varies from 0.67% to 5.32% and the organic matters are in the high mature or over mature stage. The shale samples consist mainly of clay minerals and quartz with minor pyrite and carbonates. The FE-SEM images indicate that three types of pores, organic-related pores, inorganic-related pores and micro-fractures related pores, are developed well, and a certain number of intragranular pores are found inside quartz and carbonates formed by acid liquid corrosion. The pore size distributions (PSDs) broadly range from several to hundreds nanometers, but most pores are smaller than 10nm. As the result of different adsorption features at relative pressure (0-0.5) and (0.5-1) on the N2 adsorption isotherm, two fractal dimensions D1 and D2 were obtained with the Frenkel-Halsey-Hill (FHH) model. D1 and D2 vary from 2.4227 to 2.6219 and from 2.6049 to 2.7877, respectively. Both TOC and brittle minerals have positive effect on D1 and D2, whereas clay minerals, have a negative influence on them. The fractal dimensions are also influenced by the pore structure parameters, such as the specific surface area, BJH pore volume, etc. Shale samples with higher D1 could provide more adsorption sites leading to a greater methane adsorption capacity, whereas shale samples with higher D2 have little influence on methane adsorption capacity.

Assessment of in-place oil shale resources of the Eocene Green River Formation, a foundation for calculating recoverable resources

USGS Publications Warehouse

Johnson, Ronald C.; Mercier, Tracy

2011-01-01

The recently completed assessment of in-place resources of the Eocene Green River Formation in the Piceance Basin, Colorado; the Uinta Basin, Utah and Colorado; and the Greater Green River Basin Wyoming, Colorado, and Utah and their accompanying ArcGIS projects will form the foundation for estimating technically-recoverable resources in those areas. Different estimates will be made for each of the various above-ground and in-situ recovery methodologies currently being developed. Information required for these estimates include but are not limited to (1) estimates of the amount of oil shale that exceeds various grades, (2) overburden calculations, (3) a better understanding of oil shale saline facies, and (4) a better understanding of the distribution of various oil shale mineral facies. Estimates for the first two are on-going, and some have been published. The present extent of the saline facies in all three basins is fairly well understood, however, their original extent prior to ground water leaching has not been studied in detail. These leached intervals, which have enhanced porosity and permeability due to vugs and fractures and contain significant ground water resources, are being studied from available core descriptions. A database of all available xray mineralogy data for the oil shale interval is being constructed to better determine the extents of the various mineral facies. Once these studies are finished, the amount of oil shale with various mineralogical and physical properties will be determined.

Milankovitch Cyclicity in the Eocene Green River Formation of Colorado and Wyoming

NASA Astrophysics Data System (ADS)

Machlus, M.; Olsen, P. E.; Christie-Blick, N.; Hemming, S. R.

2001-12-01

The Eocene Green River Formation is a classic example of cyclic lacustrine sediments. Following Bradley (1929, U.S.G.S. Prof. Paper 158-E), many descriptive studies suggested precession and eccentricity as the probable climatic forcing to produce the cyclic pattern. Here we report spectral analysis results that confirm this hypothesis. Furthermore, we have identified the presence of a surprisingly large amplitude obliquity cycle, the long-period eccentricity cycle (400 k.y.) and the long period modulators of obliquity. Spectral analyses of data from Colorado were undertaken on an outcrop section and core data using two different proxies for lake depth. In a section measured in the west Piceance Creek basin, three lithologies (ranks) were used as a proxy for relative water depth, from relatively shallow to deep water: laminated marlstones; microlaminated, light-colored oil-shales; and microlaminated black oil shales. A multi-tapered spectrum of the 190-m-thick record in the depth domain shows significant peaks at periods of 2.1, 3.4, 12 and 39 m. These are interpreted as the precession, obliquity and eccentricity cycles. The precession cycle confirms Bradley's independent estimate of 2.4 m per 20 k.y. cycle, based on varve counts at the same location. A high-amplitude, continuous 3.4 m (obliquity) cycle exists in the evolutive spectrum of this record. A second spectral analysis of an oil-shale-yield record was made on a 530 m core near the basin depocenter. This record includes the time-equivalent of the outcrop section, spans a longer interval of time, and has a higher sedimentation rate. Peaks are found at 5, 10, 25 and 79 m. Again, the probable obliquity peak, at 10 m, is continuous along the record. Initial tuning of this record to a 39.9 k.y. cosine wave improves the resolution of the precession, short and long eccentricity cycles. Spectral analysis of oil shale yield and sonic velocity data of cores from the Green River basin, Wyoming, gives similar results. Spectral peaks at 6, 13, 31 and 122 m appear mainly in the Tipton and the Wilkins Peak members. The correlation between oil shale yield, lithology and relative water depth was examined in the upper part of the Wilkins Peak Member and the Lower part of the Laney Member. The succession from microlaminated black oil shale to laminated micrite corresponds with documented lateral changes in facies from deep to shallow environments, thus confirming the use of these facies as relative water-depth proxies. Furthermore, the upsection record of oil shale yields correlates with these facies, with higher yields corresponding to deeper water facies. This correlation supports the use of the oil shale yield record as a proxy for short-term lake-level changes, and therefore a proxy for climate. The spectral analysis results from both basins show the importance of the obliquity cycle in these continental records. This cycle cannot be identified by cycle-counting, and therefore was not previously recognized. Earlier published attempts at spectral analysis of short records from the Piceance Creek and Uinta basins misinterpreted the observed cycles. This is the first time both the obliquity cycle and the long-term eccentricity cycle have been identified in the Green River and Piceance Creek basins.

Increasing influence of exotic terranes as sources of shales from the Sevier and Taconic Foreland basins : Evidence from Nd isotopes

DOE Office of Scientific and Technical Information (OSTI.GOV)

Samson, S.D.; Andersen, C.B.

1994-03-01

The influence of outboard tectonostratigraphic terranes as a source of sediment to Ordovician foreland basins is unknown. To determine if there were changes in provenance, or changes in the importance of a given source region, the authors have analyzed shales from two foreland basins, the Tactonic Foreland basin of central New York and the Sevier Foreland basin of Tennessee, for their Nd isotopic compositions. Shales from the Taconic basin include those from the lower portion of Utica shale, Corynoides americanus graptolite Zone, and the uppermost portion of the Utica shale, including the Geniculograptus pygmaeus graptolite Zone. Initial [epsilon][sub Nd] valuesmore » for the oldest Taconic basin shales are [minus]12. Initial [epsilon][sub Nd] values for the younger Taconic basin shales range from [minus]9.7 to [minus]8.4. This increase in [epsilon][sub Nd] may reflect an increased influence of terranes outboard of the Laurentian margin. Samples from the Sevier basin include those from the Blockhouse and Tellico Formations. A sample of the lower Blockhouse Fm. has an initial [epsilon][sub Nd] of [minus]9.4, while mid-formation levels have [epsilon][sub Nd] = [minus]8.8. Initial [epsilon][sub Nd] ranges from [minus]8.0 to [minus]7.2 from Tellico Formation shales. Thus a trend towards increasing [epsilon][sub Nd] with decreasing age is also seen in the Sevier basin. This again suggests the possibility of an increasing influence from nearby terranes. The fact that the [epsilon][sub Nd] values are higher in the Sevier basin than in the Taconic basin indicates that the Sevier shales received detritus with a less evolved isotopic composition. This may reflect fundamentally different sources, such as a more juvenile terrane as an important source of Sevier basin shales.« less

Complex permeability structure of a fault zone crosscutting a sequence of sandstones and shales and its influence on hydraulic head distribution

NASA Astrophysics Data System (ADS)

Cilona, A.; Aydin, A.; Hazelton, G.

2013-12-01

Characterization of the structural architecture of a 5 km-long, N40°E-striking fault zone provides new insights for the interpretation of hydraulic heads measured across and along the fault. Of interest is the contaminant transport across a portion of the Upper Cretaceous Chatsworth Formation, a 1400 m-thick turbidite sequence of sandstones and shales exposed in the Simi Hills, south California. Local bedding consistently dips about 20° to 30° to NW. Participating hydrogeologists monitor the local groundwater system by means of numerous boreholes used to define the 3D distribution of the groundwater table around the fault. Sixty hydraulic head measurements consistently show differences of 10s of meters, except for a small area. In this presentation, we propose a link between this distribution and the fault zone architecture. Despite an apparent linear morphological trend, the fault is made up of at least three distinct segments named here as northern, central and southern segments. Key aspects of the fault zone architecture have been delineated at two sites. The first is an outcrop of the central segment and the second is a borehole intersecting the northern segment at depth. The first site shows the fault zone juxtaposing sandstones against shales. Here the fault zone consists of a 13 meter-wide fault rock including a highly deformed sliver of sandstone on the northwestern side. In the sandstone, shear offset was resolved along N42°E striking and SE dipping fracture surfaces localized within a 40 cm thick strand. Here the central core of the fault zone is 8 m-wide and contains mostly shale characterized by highly diffuse deformation. It shows a complex texture overprinted by N30°E-striking carbonate veins. At the southeastern edge of the fault zone exposure, a shale unit dipping 50° NW towards the fault zone provides the key information that the shale unit was incorporated into the fault zone in a manner consistent with shale smearing. At the second site, a borehole more than 194 meter-long intersects the fault zone at its bottom. Based on an optical televiewer image supplemented by limited recovered rock cores, a juxtaposition plane (dipping 75° SE) between a fractured sandstone and a highly-deformed shale fault rock has been interpreted as the southeastern boundary of the fault zone. The shale fault rock estimated to be thicker than 4 meters is highly folded and brecciated with locally complex cataclastic texture. The observations and interpretations of the fault architecture presented above suggest that the drop of hydraulic head detected across the fault segments is due primarily to the low-permeability shaly fault rock incorporated into the fault zone by a shale smearing mechanism. Interestingly, at around the step between the northern and the central fault segments, where the fault offset is expected to diminish (no hard link and no significant shaly fault rock), the groundwater levels measured on either sides of the fault zone are more-or-less equal.

Organic geochemistry: Effects of organic components of shales on adsorption: Progress report

DOE Office of Scientific and Technical Information (OSTI.GOV)

Ho, P.C.

1988-11-01

The Sedimentary Rock Program at the Oak Ridge National Laboratory is investigating shale to determine its potential suitability as a host rock for the disposal of high-level radioactive wastes (HLW). The selected shales are Upper Dowelltown, Pierre, Green River Formation, and two Conasauga (Nolichucky and Pumpkin Valley) Shales, which represent mineralogical and compositional extremes of shales in the United States. According to mineralogical studies, the first three shales contain 5 to 13 wt % of organic matter, and the two Conasauga Shales only contain trace amounts (2 wt %) of organic matter. Soxhlet extraction with chloroform and a mixture ofmore » chloroform and methanol can remove 0.07 to 5.9 wt % of the total organic matter from these shales. Preliminary analysis if these organic extracts reveals the existence of organic carboxylic acids and hydrocarbons in these samples. Adsorption of elements such as Cs(I), Sr(II) and Tc(VII) on the organic-extracted Upper Dowelltown, Pierre, green River Formation and Pumpkin Valley Shales in synthetic groundwaters (simulating groundwaters in the Conasauga Shales) and in 0.03-M NaHCO/sub 3/ solution indicates interaction between each of the three elements and the organic-extractable bitumen. 28 refs., 8 figs., 10 tabs.« less

Extraction of hydrocarbons from high-maturity Marcellus Shale using supercritical carbon dioxide

USGS Publications Warehouse

Jarboe, Palma B.; Philip A. Candela,; Wenlu Zhu,; Alan J. Kaufman,

2015-01-01

Shale is now commonly exploited as a hydrocarbon resource. Due to the high degree of geochemical and petrophysical heterogeneity both between shale reservoirs and within a single reservoir, there is a growing need to find more efficient methods of extracting petroleum compounds (crude oil, natural gas, bitumen) from potential source rocks. In this study, supercritical carbon dioxide (CO2) was used to extract n-aliphatic hydrocarbons from ground samples of Marcellus shale. Samples were collected from vertically drilled wells in central and western Pennsylvania, USA, with total organic carbon (TOC) content ranging from 1.5 to 6.2 wt %. Extraction temperature and pressure conditions (80 °C and 21.7 MPa, respectively) were chosen to represent approximate in situ reservoir conditions at sample depth (1920−2280 m). Hydrocarbon yield was evaluated as a function of sample matrix particle size (sieve size) over the following size ranges: 1000−500 μm, 250−125 μm, and 63−25 μm. Several methods of shale characterization including Rock-Eval II pyrolysis, organic petrography, Brunauer−Emmett−Teller surface area, and X-ray diffraction analyses were also performed to better understand potential controls on extraction yields. Despite high sample thermal maturity, results show that supercritical CO2 can liberate diesel-range (n-C11 through n-C21) n-aliphatic hydrocarbons. The total quantity of extracted, resolvable n-aliphatic hydrocarbons ranges from approximately 0.3 to 12 mg of hydrocarbon per gram of TOC. Sieve size does have an effect on extraction yield, with highest recovery from the 250−125 μm size fraction. However, the significance of this effect is limited, likely due to the low size ranges of the extracted shale particles. Additional trends in hydrocarbon yield are observed among all samples, regardless of sieve size: 1) yield increases as a function of specific surface area (r2 = 0.78); and 2) both yield and surface area increase with increasing TOC content (r2 = 0.97 and 0.86, respectively). Given that supercritical CO2 is able to mobilize residual organic matter present in overmature shales, this study contributes to a better understanding of the extent and potential factors affecting the extraction process.

Preliminary results report: Conasauga near-surface heater experiment

DOE Office of Scientific and Technical Information (OSTI.GOV)

Krumhansl, J.L.

From November 1977 to August 1978, two near-surface heater experiments were operated in two somewhat different stratigraphic sequences within the Conasauga formation which consist predominantly of shale. Specific phenomena investigated were the thermal and mechanical responses of the formation to an applied heat load, as well as the mineralogical changes induced by heating. Objective was to provide a minimal integrated field and laboratory study that would supply a data base which could be used in planning more expensive and complex vault-type experiments in other localities. The experiments were operated with heater power levels of between 6 and 8 kW formore » heater mid-plane temperatures of 385/sup 0/C. The temperature fields within the shale were measured and analysis is in progress. Steady state conditions were achieved within 90 days. Conduction appears to be the principal mechanism of heat transport through the formation. Limited mechanical response measurements consisting of vertical displacement and stress data indicate general agreement with predictions. Posttest data, collection of which await experiment shutdown and cooling of the formation, include the mineralogy of posttest cores, posttest transmissivity measurements and corrosion data on metallurgical samples.« less

Post-GOE redox insights from Mo isotopes, Ce anomalies, and Mn from the 2.24 Ga Kazput Formation

NASA Astrophysics Data System (ADS)

Thoby, M.; Konhauser, K.; Philippot, P.; Killingsworth, B.; Warchola, T.; Lalonde, S.

2017-12-01

Following the Great Oxidation event (GOE) defined from 2.45 to 2.2 Ga, an event marking the first appearance of widespread atmospheric oxygen, a combination of decreased Mn(II) supply from land and increased Mn(IV)-precipitation in the oceans should have resulted in lower concentrations of Mn in seawater. Nevertheless, it appears that some early Proterozoic marine sediments record high seawater Mn concentrations hundreds of millions of years after the GOE. Here we investigate a Mn excursion associated with marine carbonates and shales of the 2.31 Ga Kazput Formation. Samples were recovered from drill core collected during the Turee Creek Drilling Project (TCDP). Using molybdenum (Mo) isotope data coupled with cerium (Ce) anomalies, we define the redox condition of the Kazput depositional environment. Initial results show no Mo fractionation and few cerium anomalies in carbonates, pointing to an anoxic basin without Mn oxide precipitates. Additionally, XRF data on the shales indicates an association of Mn with calcium (Ca) suggesting an anoxic environment at the time of their deposition. Our results provide new insights into the nature and environment of the Turee Creek basin and the extent of oxygenation of surface waters after the GOE.

Examination of the Reelfoot Rift Petroleum System, south-central United States, and the elements that remain for potential exploration and development

USGS Publications Warehouse

Coleman, James; Pratt, Thomas L.

2016-01-01

No production has been established in the Reel-foot rift. However, at least nine of 22 exploratory wells have reported petroleum shows, mainly gas shows with some asphalt or solid hydrocarbon residue. Regional seismic profiling shows the presence of two large inversion structures (Blytheville arch and Pascola arch). The Blytheville arch is marked by a core of structurally thickened Elvins Shale, whereas the Pascola arch reflects the structural uplift of a portion of the entire rift basin. Structural uplift and faulting within the Reelfoot rift since the late Paleozoic appear to have disrupted older conventional hydrocarbon traps and likely spilled any potential conventional petroleum accumulations. The remaining potential resources within the Reelfoot rift are likely shale gas accumulations within the Elvins Shale; however, reservoir continuity and porosity as well as pervasive faulting appear to be significant future challenges for explorers and drillers.

Radium content of oil- and gas-field produced waters in the northern Appalachian Basin (USA)—Summary and discussion of data

USGS Publications Warehouse

Rowan, E.L.; Engle, M.A.; Kirby, C.S.; Kraemer, T.F.

2011-01-01

Radium activity data for waters co-produced with oil and gas in New York and Pennsylvania have been compiled from publicly available sources and are presented together with new data for six wells, including one time series. When available, total dissolved solids (TDS), and gross alpha and gross beta particle activities also were compiled. Data from the 1990s and earlier are from sandstone and limestone oil/gas reservoirs of Cambrian-Mississippian age; however, the recent data are almost exclusively from the Middle Devonian Marcellus Shale. The Marcellus Shale represents a vast resource of natural gas the size and significance of which have only recently been recognized. Exploitation of the Marcellus involves hydraulic fracturing of the shale to release tightly held gas. Analyses of the water produced with the gas commonly show elevated levels of salinity and radium. Similarities and differences in radium data from reservoirs of different ages and lithologies are discussed. The range of radium activities for samples from the Marcellus Shale (less than detection to 18,000 picocuries per liter (pCi/L)) overlaps the range for non-Marcellus reservoirs (less than detection to 6,700 pCi/L), and the median values are 2,460 pCi/L and 734 pCi/L, respectively. A positive correlation between the logs of TDS and radium activity can be demonstrated for the entire dataset, and controlling for this TDS dependence, Marcellus shale produced water samples contain statistically more radium than non-Marcellus samples. The radium isotopic ratio, Ra-228/Ra-226, in samples from the Marcellus Shale is generally less than 0.3, distinctly lower than the median values from other reservoirs. This ratio may serve as an indicator of the provenance or reservoir source of radium in samples of uncertain origin.

Mechanical Properties of Gas Shale During Drilling Operations

NASA Astrophysics Data System (ADS)

Yan, Chuanliang; Deng, Jingen; Cheng, Yuanfang; Li, Menglai; Feng, Yongcun; Li, Xiaorong

2017-07-01

The mechanical properties of gas shale significantly affect the designs of drilling, completion, and hydraulic fracturing treatments. In this paper, the microstructure characteristics of gas shale from southern China containing up to 45.1% clay were analyzed using a scanning electron microscope. The gas shale samples feature strongly anisotropic characteristics and well-developed bedding planes. Their strength is controlled by the strength of both the matrix and the bedding planes. Conventional triaxial tests and direct shear tests are further used to study the chemical effects of drilling fluids on the strength of shale matrix and bedding planes, respectively. The results show that the drilling fluid has a much larger impact on the strength of the bedding plane than that of the shale matrix. The impact of water-based mud (WBM) is much larger compared with oil-based mud. Furthermore, the borehole collapse pressure of shale gas wells considering the effects of drilling fluids are analyzed. The results show that the collapse pressure increases gradually with the increase of drilling time, especially for WBM.

Oil/source rock correlations in the Polish Flysch Carpathians and Mesozoic basement and organic facies of the Oligocene Menilite Shales: Insights from hydrous pyrolysis experiments

USGS Publications Warehouse

Curtis, John B.; Kotarba, M.J.; Lewan, M.D.; Wieclaw, D.

2004-01-01

The Oligocene Menilite Shales in the study area in the Polish Flysch Carpathians are organic-rich and contain varying mixtures of Type-II, Type-IIS and Type-III kerogen. The kerogens are thermally immature to marginally mature based on atomic H/C ratios and Rock-Eval data. This study defined three organic facies, i.e., sedimentary strata with differing hydrocarbon-generation potentials due to varying types and concentrations of organic matter. These facies correspond to the Silesian Unit and the eastern and western portions of the Skole Unit. Analysis of oils generated by hydrous pyrolysis of outcrop samples of Menilite Shales demonstrates that natural crude oils reservoired in the flysch sediments appear to have been generated from the Menilite Shales. Natural oils reservoired in the Mesozoic basement of the Carpathian Foredeep appear to be predominantly derived and migrated from Menilite Shales, with a minor contribution from at least one other source rock most probably within Middle Jurassic strata. Definition of organic facies may have been influenced by the heterogeneous distribution of suitable Menilite Shales outcrops and producing wells, and subsequent sample selection during the analytical phases of the study. ?? 2004 Elsevier Ltd. All rights reserved.

Mongolian Oil Shale, hosted in Mesozoic Sedimentary Basins

NASA Astrophysics Data System (ADS)

Bat-Orshikh, E.; Lee, I.; Norov, B.; Batsaikhan, M.

2016-12-01

Mongolia contains several Mesozoic sedimentary basins, which filled >2000 m thick non-marine successions. Late Triassic-Middle Jurassic foreland basins were formed under compression tectonic conditions, whereas Late Jurassic-Early Cretaceous rift valleys were formed through extension tectonics. Also, large areas of China were affected by these tectonic events. The sedimentary basins in China host prolific petroleum and oil shale resources. Similarly, Mongolian basins contain hundreds meter thick oil shale as well as oil fields. However, petroleum system and oil shale geology of Mongolia remain not well known due to lack of survey. Mongolian oil shale deposits and occurrences, hosted in Middle Jurassic and Lower Cretaceous units, are classified into thirteen oil shale-bearing basins, of which oil shale resources were estimated to be 787 Bt. Jurassic oil shale has been identified in central Mongolia, while Lower Cretaceous oil shale is distributed in eastern Mongolia. Lithologically, Jurassic and Cretaceous oil shale-bearing units (up to 700 m thick) are similar, composed mainly of alternating beds of oil shale, dolomotic marl, siltstone and sandstone, representing lacustrine facies. Both Jurassic and Cretaceous oil shales are characterized by Type I kerogen with high TOC contents, up to 35.6% and low sulfur contents ranging from 0.1% to 1.5%. Moreover, S2 values of oil shales are up to 146 kg/t. The numbers indicate that the oil shales are high quality, oil prone source rocks. The Tmax values of samples range from 410 to 447, suggesting immature to early oil window maturity levels. PI values are consistent with this interpretation, ranging from 0.01 to 0.03. According to bulk geochemistry data, Jurassic and Cretaceous oil shales are identical, high quality petroleum source rocks. However, previous studies indicate that known oil fields in Eastern Mongolia were originated from Lower Cretaceous oil shales. Thus, further detailed studies on Jurassic oil shale and its petroleum potential are required.

Shale gas development effects on the songbird community in a central Appalachian forest

USGS Publications Warehouse

Farwell, Laura S.; Wood, Petra; Sheehan, James; George, Gregory A.

2016-01-01

In the last decade, unconventional drilling for natural gas from the Marcellus-Utica shale has increased exponentially in the central Appalachians. This heavily forested region contains important breeding habitat for many neotropical migratory songbirds, including several species of conservation concern. Our goal was to examine effects of unconventional gas development on forest habitat and breeding songbirds at a predominantly forested site from 2008 to 2015. Construction of gas well pads and infrastructure (e.g., roads, pipelines) contributed to an overall 4.5% loss in forest cover at the site, a 12.4% loss in core forest, and a 51.7% increase in forest edge density. We evaluated the relationship between land-cover metrics and species richness within three avian guilds: forest-interior, early-successional, and synanthropic, in addition to abundances of 21 focal species. Land-cover impacts were evaluated at two spatial extents: a point-level within 100-m and 500-m buffers of each avian survey station, and a landscape-level across the study area (4326 ha). Although we observed variability in species-specific responses, we found distinct trends in long-term response among the three avian guilds. Forest-interior guild richness declined at all points across the site and at points impacted within 100 m by shale gas but did not change at unimpacted points. Early-successional and synanthropic guild richness increased at all points and at impacted points. Our results suggest that shale gas development has the potential to fragment regional forests and alter avian communities, and that efforts to minimize new development in core forests will reduce negative impacts to forest dependent species.

Stratigraphic and structural data for the Conasauga Group and the Rome Formation on the Copper Creek fault block near Oak Ridge, Tennessee: preliminary results from test borehole ORNL-JOY No. 2

DOE Office of Scientific and Technical Information (OSTI.GOV)

Haase, C.S.; Walls, E.C.; Farmer, C.D.

1985-06-01

To resolve long-standing problems with the stratigraphy of the Conasauga Group and the Rome Formation on the Copper Creek fault block near Oak Ridge National Laboratory (ORNL), an 828.5-m-deep test borehole was drilled. Continuous rock core was recovered from the 17.7- to 828.5-m-deep interval; temperature, caliper, neutron, gamma-ray, and acoustic (velocity and televiewer) logs were obtained. The Conasauga Group at the study site is 572.4 m thick and comprises six formations that are - in descending stratigraphic order - Maynardville Limestone (98.8 m), Nolichucky Shale (167.9 m), Maryville Limestone (141.1 m), Rogersville Shale (39.6 m), Rutledge Limestone (30.8 m), andmore » Pumpkin Valley Shale (94.2 m). The formations are lithologically complex, ranging from clastics that consist of shales, mudstones, and siltstones to carbonates that consist of micrites, wackestones, packstones, and conglomerates. The Rome Formation is 188.1 m thick and consists of variably bedded mudstones, siltstones, and sandstones. The Rome Formation thickness represents 88.1 m of relatively undeformed section and 100.0 m of highly deformed, jumbled, and partially repeated section. The bottom of the Rome Formation is marked by a tectonic disconformity that occurs within a 46-m-thick, intensely deformed interval caused by motion along the Copper Creek fault. Results from this study establish the stratigraphy and the lithology of the Conasauga Group and the Rome Formation near ORNL and, for the first time, allow for the unambiguous correlation of cores and geophysical logs from boreholes elsewhere in the ORNL vicinity. 45 refs., 26 figs., 2 tabs.« less

The Importance of Field Demonstration Sites: The View from the Unconventional Resource Region of the Appalachian Basin

NASA Astrophysics Data System (ADS)

Carr, T.

2017-12-01

The Appalachian basin with the Marcellus and Utica shale units is one of the most active unconventional resource plays in North America. Unconventional resource plays are critical and rapidly-growing areas of energy, where research lags behind exploration and production activity. There remains a poor overall understanding of physical, chemical and biological factors that control shale gas production efficiency and possible environmental impacts associated with shale gas development. We have developed an approach that works with local industrial partners and communities and across research organizations. The Marcellus Shale Energy and Environment Laboratory (MSEEL) consists of a multidisciplinary and multi-institutional team undertaking integrated geoscience, engineering and environmental studies in cooperation with the Department of Energy. This approach is being expanded to other sites and to the international arena. MSEEL consists of four horizontal production wells, which are instrumented, a cored and logged vertical pilot bore-hole, and a microseismic observation well. MSEEL has integrated geophysical observations (microseismic and surface), fiber-optic monitoring for distributed acoustic (DAS) and temperature sensing (DTS), well logs, core data and production logging and continued monitoring, to characterize subsurface rock properties, and the propagation pattern of induced fractures in the stimulated reservoir volume. Significant geologic heterogeneity along the lateral affects fracture stimulation efficiency - both completion efficiency (clusters that receive effective stimulation), and production efficiency (clusters effectively contributing to production). MSEEL works to develop new knowledge of subsurface geology and engineering, and surface environmental impact to identify best practices that can optimize hydraulic fracture stimulation to increase flow rates, estimated ultimate recovery in order to reduce the number of wells and environmental impact.

The atmospheric inventory of Xenon and noble cases in shales The plastic bag experiment

NASA Technical Reports Server (NTRS)

Bernatowicz, T. J.; Podosek, F. A.; Honda, M.; Kramer, F. E.

1984-01-01

A novel trapped gas analysis protocol is applied to five shales in which the samples are sealed in air to eliminate the possibility of gas loss in the preanalysis laboratory vacuum exposure of a conventional protocol. The test is aimed at a determination concerning the hypothesis that atmospheric noble gases occur in the same proportion as planetary gases in meteorites, and that the factor-of-23 deficiency of air Xe relative to planetary Xe is made up by Xe stored in shales or other sedimentary rocks. The results obtained do not support the shale hypothesis.

Local CO2-induced swelling of shales

NASA Astrophysics Data System (ADS)

Pluymakers, Anne; Dysthe, Dag Kristian

2017-04-01

In heterogeneous shale rocks, CO2 adsorbs more strongly to organic matter than to the other components. CO2-induced swelling of organic matter has been shown in coal, which is pure carbon. The heterogeneity of the shale matrix makes an interesting case study. Can local swelling through adsorption of CO2 to organic matter induce strain in the surrounding shale matrix? Can fractures close due to CO2-induced swelling of clays and organic matter? We have developed a new generation of microfluidic high pressure cells (up to 100 bar), which can be used to study flow and adsorption phenomena at the microscale in natural geo-materials. The devices contain one transparent side and a shale sample on the other side. The shale used is the Pomeranian shale, extracted from 4 km depth in Poland. This formation is a potential target of a combined CO2-storage and gas extraction project. To answer the first question, we place the pressure cell under a Veeco NT1100 Interferometer, operated in Vertical Scanning Interferometry mode and equipped with a Through Transmissive Media objective. This allows for observation of local swelling or organic matter with nanometer vertical resolution and micrometer lateral resolution. We expose the sample to CO2 atmospheres at different pressures. Comparison of the interferometry data and using SEM-EDS maps plus optical microscopy delivers local swelling maps where we can distinguish swelling of different mineralogies. Preliminary results indicate minor local swelling of organic matter, where the total amount is both time- and pressure-dependent.

Soils as a Record of Anthropogenic Metal Inputs: From Susquehanna Shale Hills Critical Zone Observatory to Marietta, Ohio

NASA Astrophysics Data System (ADS)

Carter, M.; Herndon, E.; Brantley, S. L.

2012-12-01

Atmospheric deposition of metals emitted by anthropogenic activities has been a significant source of metal loading into soils in the United States for more than 200 years. Based on research at the Susquehanna Shale Hills CZO, we began investigating Mn inputs to soils in the northeastern U.S.A. from widespread atmospheric Mn emissions from steel manufacturers and coal-burning power plants. Total Mn inputs to Shale Hills soils at ridgetops are calculated to be 42 mg Mn/cm2. In order to more directly evaluate the link between Mn emissions and Mn enrichment in soils, we are now investigating soils around a ferromanganese refinery in Marietta, Ohio that is currently the largest emission source of manganese (Mn) into the atmosphere in the U.S.A. Particulate emissions during production are up to 31-34% percent manganese oxide (MnO) by weight. These particles range in diameter from 0.05 to 0.4 μm, making them both highly mobile and respirable. In order to assess the role of soils in Marietta as sinks for atmospherically-derived Mn, a series of soil cores have been collected from a range of distances (0.5 - 35 km) from the refinery. Mn is enriched at the soil surface up to 8 times above parent material composition sampled at 1 m depth near the source and decreases as a function of distance. Total mass of Mn added to soils per unit land area integrated over the soil depth core was calculated to be 50 mg Mn/cm2¬¬ near the refinery. In contrast, 10 mg Mn/cm2 was lost from the soil profile at a distance of 35 km from the facility. Enrichment of chromium (Cr) up to 3 times was also found in surface soils near the refinery, consistent with the production of ferrochromium at the Marietta plant. Further trace element analyses are being used to fingerprint atmospheric inputs from the refinery into the soil. Models of Mn addition to soils are also being developed and compared to known rates of emission.

Coupled Fracture and Flow in Shale in Hydraulic Fracturing

NASA Astrophysics Data System (ADS)

Carey, J. W.; Mori, H.; Viswanathan, H.

2014-12-01

Production of hydrocarbon from shale requires creation and maintenance of fracture permeability in an otherwise impermeable shale matrix. In this study, we use a combination of triaxial coreflood experiments and x-ray tomography characterization to investigate the fracture-permeability behavior of Utica shale at in situ reservoir conditions (25-50 oC and 35-120 bars). Initially impermeable shale core was placed between flat anvils (compression) or between split anvils (pure shear) and loaded until failure in the triaxial device. Permeability was monitored continuously during this process. Significant deformation (>1%) was required to generate a transmissive fracture system. Permeability generally peaked at the point of a distinct failure event and then dropped by a factor of 2-6 when the system returned to hydrostatic failure. Permeability was very small in compression experiments (< 1 mD), possibly because of limited fracture connectivity through the anvils. In pure share experiments, shale with bedding planes perpendicular to shear loading developed complex fracture networks with narrow apertures and peak permeability of 30 mD. Shale with bedding planes parallel to shear loading developed simple fractures with large apertures and a peak permeability as high as 1 D. Fracture systems held at static conditions for periods of several hours showed little change in effective permeability at hydrostatic conditions as high as 140 bars. However, permeability of fractured systems was a function of hydrostatic pressure, declining in a pseudo-linear, exponential fashion as pressure increased. We also observed that permeability decreased with increasing fluid flow rate indicating that flow did not follow Darcy's Law, possibly due to non-laminar flow conditions, and conformed to Forscheimer's law. The coupled deformation and flow behavior of Utica shale, particularly the large deformation required to initiate flow, indicates the probable importance of activation of existing fractures in hydraulic fracturing and that these fractures can have adequate permeability for the production of hydrocarbon.

Effect of confining pressure on diffusion coefficients in clay-rich, low-permeability sedimentary rocks.

PubMed

Xiang, Y; Al, T; Mazurek, M

2016-12-01

The effect of confining pressure (CP) on the diffusion of tritiated-water (HTO) and iodide (I - ) tracers through Ordovician rocks from the Michigan Basin, southwestern Ontario, Canada, and Opalinus Clay from Schlattingen, Switzerland was investigated in laboratory experiments. Four samples representing different formations and lithologies in the Michigan Basin were studied: Queenston Formation shale, Georgian Bay Formation shale, Cobourg Formation limestone and Cobourg Formation argillaceous limestone. Estimated in situ vertical stresses at the depths from which the samples were retrieved range from 12.0 to 17.4MPa (Michigan Basin) and from 21 to 23MPa (Opalinus Clay). Effective diffusion coefficients (D e ) were determined in through-diffusion experiments. With HTO tracer, applying CP resulted in decreases in D e of 12.5% for the Queenston Formation shale (CP max =12MPa), 30% for the Georgian Bay Formation shale (15MPa), 34% for the Cobourg Formation limestone (17.4MPa), 31% for the Cobourg Formation argillaceous limestone (17.4MPa) and 43-46% for the Opalinus Clay (15MPa). Decreases in D e were larger for the I - tracer: 13.8% for the Queenston shale, 42% for the Georgian Bay shale, 50% for the Cobourg Formation limestone, 55% for the Cobourg Formation argillaceous limestone and 63-68% for the Opalinus Clay. The tracer-specific nature of the response is attributed to an increasing influence of anion exclusion as the pore size decreases at higher CP. Results from the shales (including Opalinus Clay) indicate that the pressure effect on D e can be represented by a linear relationship between D e and ln(CP), which provides valuable predictive capability. The nonlinearity results in a relatively small change in D e at high CP, suggesting that it is not necessary to apply the exact in situ pressure conditions in order to obtain a good estimate of the in situ diffusion coefficient. Most importantly, the CP effect on shale is reversible (±12%) suggesting that, for argillaceous rocks, it is possible to obtain D e values that are representative of the in-situ condition by conducting measurements on re-pressurized samples that were obtained with standard drilling practices. This may not be the case for brittle rock samples as the results from limestone suggest that irreversible damage occurred during the pressure cycling. Copyright © 2016 Elsevier B.V. All rights reserved.

Geomechanical Anisotropy and Rock Fabric in Shales

NASA Astrophysics Data System (ADS)

Huffman, K. A.; Connolly, P.; Thornton, D. A.

2017-12-01

Digital rock physics (DRP) is an emerging area of qualitative and quantitative scientific analysis that has been employed on a variety of rock types at various scales to characterize petrophysical, mechanical, and hydraulic rock properties. This contribution presents a generic geomechanically focused DRP workflow involving image segmentation by geomechanical constituents, generation of finite element (FE) meshes, and application of various boundary conditions (i.e. at the edge of the domain and at boundaries of various components such as edges of individual grains). The generic workflow enables use of constituent geological objects and relationships in a computational based approach to address specific questions in a variety of rock types at various scales. Two examples are 1) modeling stress dependent permeability, where it occurs and why it occurs at the grain scale; 2) simulating the path and complexity of primary fractures and matrix damage in materials with minerals or intervals of different mechanical behavior. Geomechanical properties and fabric characterization obtained from 100 micron shale SEM images using the generic DRP workflow are presented. Image segmentation and development of FE simulation composed of relatively simple components (elastic materials, frictional contacts) and boundary conditions enable the determination of bulk static elastic properties. The procedure is repeated for co-located images at pertinent orientations to determine mechanical anisotropy. The static moduli obtained are benchmarked against lab derived measurements since material properties (esp. frictional ones) are poorly constrained at the scale of investigation. Once confidence in the input material parameters is gained, the procedure can be used to characterize more samples (i.e. images) than is possible from rock samples alone. Integration of static elastic properties with grain statistics and geologic (facies) conceptual models derived from core and geophysical logs enables quantification of the impact that variations in rock fabric and grain interactions have on bulk mechanical rock behavior. When considered in terms of the stratigraphic framework of two different shale reservoirs it is found that silica distribution, clay content and orientation play a first order role in mechanical anisotropy.

[Analyzing and modeling methods of near infrared spectroscopy for in-situ prediction of oil yield from oil shale].

PubMed

Liu, Jie; Zhang, Fu-Dong; Teng, Fei; Li, Jun; Wang, Zhi-Hong

2014-10-01

In order to in-situ detect the oil yield of oil shale, based on portable near infrared spectroscopy analytical technology, with 66 rock core samples from No. 2 well drilling of Fuyu oil shale base in Jilin, the modeling and analyzing methods for in-situ detection were researched. By the developed portable spectrometer, 3 data formats (reflectance, absorbance and K-M function) spectra were acquired. With 4 different modeling data optimization methods: principal component-mahalanobis distance (PCA-MD) for eliminating abnormal samples, uninformative variables elimination (UVE) for wavelength selection and their combina- tions: PCA-MD + UVE and UVE + PCA-MD, 2 modeling methods: partial least square (PLS) and back propagation artificial neural network (BPANN), and the same data pre-processing, the modeling and analyzing experiment were performed to determine the optimum analysis model and method. The results show that the data format, modeling data optimization method and modeling method all affect the analysis precision of model. Results show that whether or not using the optimization method, reflectance or K-M function is the proper spectrum format of the modeling database for two modeling methods. Using two different modeling methods and four different data optimization methods, the model precisions of the same modeling database are different. For PLS modeling method, the PCA-MD and UVE + PCA-MD data optimization methods can improve the modeling precision of database using K-M function spectrum data format. For BPANN modeling method, UVE, UVE + PCA-MD and PCA- MD + UVE data optimization methods can improve the modeling precision of database using any of the 3 spectrum data formats. In addition to using the reflectance spectra and PCA-MD data optimization method, modeling precision by BPANN method is better than that by PLS method. And modeling with reflectance spectra, UVE optimization method and BPANN modeling method, the model gets the highest analysis precision, its correlation coefficient (Rp) is 0.92, and its standard error of prediction (SEP) is 0.69%.

Modeling Dynamic Helium Release as a Tracer of Rock Deformation

DOE PAGES

Gardner, W. Payton; Bauer, Stephen J.; Kuhlman, Kristopher L.; ...

2017-11-03

Here, we use helium released during mechanical deformation of shales as a signal to explore the effects of deformation and failure on material transport properties. A dynamic dual-permeability model with evolving pore and fracture networks is used to simulate gases released from shale during deformation and failure. Changes in material properties required to reproduce experimentally observed gas signals are explored. We model two different experiments of 4He flow rate measured from shale undergoing mechanical deformation, a core parallel to bedding and a core perpendicular to bedding. We also found that the helium signal is sensitive to fracture development and evolutionmore » as well as changes in the matrix transport properties. We constrain the timing and effective fracture aperture, as well as the increase in matrix porosity and permeability. Increases in matrix permeability are required to explain gas flow prior to macroscopic failure, and the short-term gas flow postfailure. Increased matrix porosity is required to match the long-term, postfailure gas flow. This model provides the first quantitative interpretation of helium release as a result of mechanical deformation. The sensitivity of this model to changes in the fracture network, as well as to matrix properties during deformation, indicates that helium release can be used as a quantitative tool to evaluate the state of stress and strain in earth materials.« less

Multi-Scale Multi-Physics Modeling of Matrix Transport Properties in Fractured Shale Reservoirs

NASA Astrophysics Data System (ADS)

Mehmani, A.; Prodanovic, M.

2014-12-01

Understanding the shale matrix flow behavior is imperative in successful reservoir development for hydrocarbon production and carbon storage. Without a predictive model, significant uncertainties in flowback from the formation, the communication between the fracture and matrix as well as proper fracturing practice will ensue. Informed by SEM images, we develop deterministic network models that couple pores from multiple scales and their respective fluid physics. The models are used to investigate sorption hysteresis as an affordable way of inferring the nanoscale pore structure in core scale. In addition, restricted diffusion as a function of pore shape, pore-throat size ratios and network connectivity is computed to make correct interpretation of the 2D NMR maps possible. Our novel pore network models have the ability to match sorption hysteresis measurements without any tuning parameters. The results clarify a common misconception of linking type 3 nitrogen hysteresis curves to only the shale pore shape and show promising sensitivty for nanopore structre inference in core scale. The results on restricted diffusion shed light on the importance of including shape factors in 2D NMR interpretations. A priori "weighting factors" as a function of pore-throat and throat-length ratio are presented and the effect of network connectivity on diffusion is quantitatively assessed. We are currently working on verifying our models with experimental data gathered from the Eagleford formation.

Modeling Dynamic Helium Release as a Tracer of Rock Deformation

DOE Office of Scientific and Technical Information (OSTI.GOV)

Gardner, W. Payton; Bauer, Stephen J.; Kuhlman, Kristopher L.

Here, we use helium released during mechanical deformation of shales as a signal to explore the effects of deformation and failure on material transport properties. A dynamic dual-permeability model with evolving pore and fracture networks is used to simulate gases released from shale during deformation and failure. Changes in material properties required to reproduce experimentally observed gas signals are explored. We model two different experiments of 4He flow rate measured from shale undergoing mechanical deformation, a core parallel to bedding and a core perpendicular to bedding. We also found that the helium signal is sensitive to fracture development and evolutionmore » as well as changes in the matrix transport properties. We constrain the timing and effective fracture aperture, as well as the increase in matrix porosity and permeability. Increases in matrix permeability are required to explain gas flow prior to macroscopic failure, and the short-term gas flow postfailure. Increased matrix porosity is required to match the long-term, postfailure gas flow. This model provides the first quantitative interpretation of helium release as a result of mechanical deformation. The sensitivity of this model to changes in the fracture network, as well as to matrix properties during deformation, indicates that helium release can be used as a quantitative tool to evaluate the state of stress and strain in earth materials.« less

Shale characterization in mass transport complex as a potential source rock: An example from onshore West Java Basin, Indonesia

NASA Astrophysics Data System (ADS)

Nugraha, A. M. S.; Widiarti, R.; Kusumah, E. P.

2017-12-01

This study describes a deep-water slump facies shale of the Early Miocene Jatiluhur/Cibulakan Formation to understand its potential as a source rock in an active tectonic region, the onshore West Java. The formation is equivalent with the Gumai Formation, which has been well-known as another prolific source rock besides the Oligocene Talang Akar Formation in North West Java Basin, Indonesia. The equivalent shale formation is expected to have same potential source rock towards the onshore of Central Java. The shale samples were taken onshore, 150 km away from the basin. The shale must be rich of organic matter, have good quality of kerogen, and thermally matured to be categorized as a potential source rock. Investigations from petrography, X-Ray diffractions (XRD), and backscattered electron show heterogeneous mineralogy in the shales. The mineralogy consists of clay minerals, minor quartz, muscovite, calcite, chlorite, clinopyroxene, and other weathered minerals. This composition makes the shale more brittle. Scanning Electron Microscope (SEM) analysis indicate secondary porosities and microstructures. Total Organic Carbon (TOC) shows 0.8-1.1 wt%, compared to the basinal shale 1.5-8 wt%. The shale properties from this outcropped formation indicate a good potential source rock that can be found in the subsurface area with better quality and maturity.

Stress anisotropy and velocity anisotropy in low porosity shale

NASA Astrophysics Data System (ADS)

Kuila, U.; Dewhurst, D. N.; Siggins, A. F.; Raven, M. D.

2011-04-01

Shales are known for often marked intrinsic anisotropy of many of their properties, including strength, permeability and velocity for example. In addition, it is well known that anisotropic stress fields can also have a significant impact on anisotropy of velocity, even in an isotropic medium. This paper sets out to investigate the ultrasonic velocity response of well-characterised low porosity shales from the Officer Basin in Western Australia to both isotropic and anisotropic stress fields and to evaluate the velocity response to the changing stress field. During consolidated undrained multi-stage triaxial tests on core plugs cut normal to bedding, V pv increases monotonically with increasing effective stress and V s1 behaves similarly although with some scatter. V ph and V sh remain constant initially but then decrease within each stage of the multi-stage test, although velocity from stage to stage at any given differential stress increases. This has the impact of decreasing both P-wave (ɛ) and S-wave anisotropy (γ) through application of differential stress within each loading stage. However, increasing the magnitude of an isotropic stress field has little effect on the velocity anisotropies. The intrinsic anisotropy of the shale remains reasonably high at the highest confining pressures. The results indicate the magnitude and orientation of the stress anisotropy with respect to the shale microfabric has a significant impact on the velocity response to changing stress fields.

Quantification of Organic Porosity and Water Accessibility in Marcellus Shale Using Neutron Scattering

DOE PAGES

Gu, Xin; Mildner, David F. R.; Cole, David R.; ...

2016-04-28

Pores within organic matter (OM) are a significant contributor to the total pore system in gas shales. These pores contribute most of the storage capacity in gas shales. Here we present a novel approach to characterize the OM pore structure (including the porosity, specific surface area, pore size distribution, and water accessibility) in Marcellus shale. By using ultrasmall and small-angle neutron scattering, and by exploiting the contrast matching of the shale matrix with suitable mixtures of deuterated and protonated water, both total and water-accessible porosity were measured on centimeter-sized samples from two boreholes from the nanometer to micrometer scale withmore » good statistical coverage. Samples were also measured after combustion at 450 °C. Analysis of scattering data from these procedures allowed quantification of OM porosity and water accessibility. OM hosts 24–47% of the total porosity for both organic-rich and -poor samples. This porosity occupies as much as 29% of the OM volume. In contrast to the current paradigm in the literature that OM porosity is organophilic and therefore not likely to contain water, our results demonstrate that OM pores with widths >20 nm exhibit the characteristics of water accessibility. In conclusion, our approach reveals the complex structure and wetting behavior of the OM porosity at scales that are hard to interrogate using other techniques.« less

Quantification of Organic Porosity and Water Accessibility in Marcellus Shale Using Neutron Scattering

DOE Office of Scientific and Technical Information (OSTI.GOV)

Gu, Xin; Mildner, David F. R.; Cole, David R.

Pores within organic matter (OM) are a significant contributor to the total pore system in gas shales. These pores contribute most of the storage capacity in gas shales. Here we present a novel approach to characterize the OM pore structure (including the porosity, specific surface area, pore size distribution, and water accessibility) in Marcellus shale. By using ultrasmall and small-angle neutron scattering, and by exploiting the contrast matching of the shale matrix with suitable mixtures of deuterated and protonated water, both total and water-accessible porosity were measured on centimeter-sized samples from two boreholes from the nanometer to micrometer scale withmore » good statistical coverage. Samples were also measured after combustion at 450 °C. Analysis of scattering data from these procedures allowed quantification of OM porosity and water accessibility. OM hosts 24–47% of the total porosity for both organic-rich and -poor samples. This porosity occupies as much as 29% of the OM volume. In contrast to the current paradigm in the literature that OM porosity is organophilic and therefore not likely to contain water, our results demonstrate that OM pores with widths >20 nm exhibit the characteristics of water accessibility. In conclusion, our approach reveals the complex structure and wetting behavior of the OM porosity at scales that are hard to interrogate using other techniques.« less

Estimating emissions of toxic hydrocarbons from natural gas production sites in the Barnett Shale region

NASA Astrophysics Data System (ADS)

Marrero, J. E.; Townsend-Small, A.; Lyon, D. R.; Tsai, T.; Meinardi, S.; Blake, D. R.

2015-12-01

Throughout the past decade, shale gas operations have moved closer to urban centers and densely populated areas, contributing to growing public concerns regarding exposure to hazardous air pollutants (HAPs). These HAPs include gases like hexane, 1,3-butadiene and BTEX compounds, which can cause minor health effects from short-term exposure or possibly cancer due to prolonged exposure. During the Barnett Shale Coordinated Campaign in October, 2013, ground-based whole air samples revealed enhancements in several of these toxic volatile organic compounds (VOCs) downwind of natural gas well pads and compressor stations. Two methods were used to estimate the emission rate of several HAPs in the Barnett Shale. The first method utilized CH4 flux measurements derived from the Picarro Mobile Flux Plane (MFP) and taken concurrently with whole air samples, while the second used a CH4 emissions inventory developed for the Barnett Shale region. From these two approaches, the regional emission estimate for benzene (C6H6) ranged from 48 ± 16 to 84 ± 26 kg C6H6 hr-1. A significant regional source of atmospheric benzene is evident, despite measurement uncertainty and limited number of samples. The extent to which these emission rates equate to a larger public health risk is unclear, but is of particular interest as natural gas productions continues to expand.

Organic matter from the Bunte Breccia of the Ries Crater, southern Germany: investigating possible thermal effects of the impact

NASA Astrophysics Data System (ADS)

Hofmann, P.; Leythaeuser, D.; Schwark, L.

2001-07-01

In order to determine thermal effects of the Ries impact, southern Germany, on organic matter in its ejecta blanket, the maturity of organic matter of Posidonia Shale components from the Bunte Breccia at Harburg and Gundelsheim is compared with the maturity of organic matter of a reference section of Posidonia Shale outside the impact site at Hesselberg. Three black shale samples from the Bunte Breccia were identified as corresponding to the organic matter-rich Posidonia Shale based on the molecular composition of extractable organic matter. They show n-alkane patterns with a maximum of n-C 17, a predominance of odd over even n-alkanes in the range from n-C 26 to n-C 35, a dominance of unsaturated sterenes over steranes and monoaromatic over triaromatic steroids, and contain isorenieratene. The maturity of the organic matter from the Bunte Breccia samples corresponds to 0.32-0.35% random vitrinite reflectance ( Rr) and a spectral red/green quotient ( Q) of 0.32-0.34. The organic matter from the Bunte Breccia is more mature than the Posidonia Shale sample from the reference site Hesselberg (0.25% Rr; 0.21 for Q). The thermal overprint is presumed to be too high to be explained by differences in the burial history prior to the impact alone and is, therefore, attributed to processes related to the displacement of the Bunte Breccia.

The Description of Shale Reservoir Pore Structure Based on Method of Moments Estimation

PubMed Central

Li, Wenjie; Wang, Changcheng; Shi, Zejin; Wei, Yi; Zhou, Huailai; Deng, Kun

2016-01-01

Shale has been considered as good gas reservoir due to its abundant interior nanoscale pores. Thus, the study of the pore structure of shale is of great significance for the evaluation and development of shale oil and gas. To date, the most widely used approaches for studying the shale pore structure include image analysis, radiation and fluid invasion methods. The detailed pore structures can be studied intuitively by image analysis and radiation methods, but the results obtained are quite sensitive to sample preparation, equipment performance and experimental operation. In contrast, the fluid invasion method can be used to obtain information on pore size distribution and pore structure, but the relative simple parameters derived cannot be used to evaluate the pore structure of shale comprehensively and quantitatively. To characterize the nanoscale pore structure of shale reservoir more effectively and expand the current research techniques, we proposed a new method based on gas adsorption experimental data and the method of moments to describe the pore structure parameters of shale reservoir. Combined with the geological mixture empirical distribution and the method of moments estimation principle, the new method calculates the characteristic parameters of shale, including the mean pore size (x¯), standard deviation (σ), skewness (Sk) and variation coefficient (c). These values are found by reconstructing the grouping intervals of observation values and optimizing algorithms for eigenvalues. This approach assures a more effective description of the characteristics of nanoscale pore structures. Finally, the new method has been applied to analyze the Yanchang shale in the Ordos Basin (China) and Longmaxi shale from the Sichuan Basin (China). The results obtained well reveal the pore characteristics of shale, indicating the feasibility of this new method in the study of the pore structure of shale reservoir. PMID:26992168

The Description of Shale Reservoir Pore Structure Based on Method of Moments Estimation.

PubMed

Li, Wenjie; Wang, Changcheng; Shi, Zejin; Wei, Yi; Zhou, Huailai; Deng, Kun

2016-01-01

Shale has been considered as good gas reservoir due to its abundant interior nanoscale pores. Thus, the study of the pore structure of shale is of great significance for the evaluation and development of shale oil and gas. To date, the most widely used approaches for studying the shale pore structure include image analysis, radiation and fluid invasion methods. The detailed pore structures can be studied intuitively by image analysis and radiation methods, but the results obtained are quite sensitive to sample preparation, equipment performance and experimental operation. In contrast, the fluid invasion method can be used to obtain information on pore size distribution and pore structure, but the relative simple parameters derived cannot be used to evaluate the pore structure of shale comprehensively and quantitatively. To characterize the nanoscale pore structure of shale reservoir more effectively and expand the current research techniques, we proposed a new method based on gas adsorption experimental data and the method of moments to describe the pore structure parameters of shale reservoir. Combined with the geological mixture empirical distribution and the method of moments estimation principle, the new method calculates the characteristic parameters of shale, including the mean pore size (mean), standard deviation (σ), skewness (Sk) and variation coefficient (c). These values are found by reconstructing the grouping intervals of observation values and optimizing algorithms for eigenvalues. This approach assures a more effective description of the characteristics of nanoscale pore structures. Finally, the new method has been applied to analyze the Yanchang shale in the Ordos Basin (China) and Longmaxi shale from the Sichuan Basin (China). The results obtained well reveal the pore characteristics of shale, indicating the feasibility of this new method in the study of the pore structure of shale reservoir.

Application of binomial-edited CPMG to shale characterization

USGS Publications Warehouse

Washburn, Kathryn E.; Birdwell, Justin E.

2014-01-01

Unconventional shale resources may contain a significant amount of hydrogen in organic solids such as kerogen, but it is not possible to directly detect these solids with many NMR systems. Binomial-edited pulse sequences capitalize on magnetization transfer between solids, semi-solids, and liquids to provide an indirect method of detecting solid organic materials in shales. When the organic solids can be directly measured, binomial-editing helps distinguish between different phases. We applied a binomial-edited CPMG pulse sequence to a range of natural and experimentally-altered shale samples. The most substantial signal loss is seen in shales rich in organic solids while fluids associated with inorganic pores seem essentially unaffected. This suggests that binomial-editing is a potential method for determining fluid locations, solid organic content, and kerogen–bitumen discrimination.

Molecular characterization and comparison of shale oils generated by different pyrolysis methods using FT-ICR mass spectrometry

USGS Publications Warehouse

Jin, J.M.; Kim, S.; Birdwell, J.E.

2011-01-01

Fourier transform ion cyclotron resonance mass spectrometry (FT ICR-MS) was applied in the analysis of shale oils generated using two different pyrolysis systems under laboratory conditions meant to simulate surface and in situ oil shale retorting. Significant variations were observed in the shale oils, particularly the degree of conjugation of the constituent molecules. Comparison of FT ICR-MS results to standard oil characterization methods (API gravity, SARA fractionation, gas chromatography-flame ionization detection) indicated correspondence between the average Double Bond Equivalence (DBE) and asphaltene content. The results show that, based on the average DBE values and DBE distributions of the shale oils examined, highly conjugated species are enriched in samples produced under low pressure, high temperature conditions and in the presence of water.

Porosity of the Marcellus Shale: A contrast matching small-angle neutron scattering study

USGS Publications Warehouse

Bahadur, Jitendra; Ruppert, Leslie F.; Pipich, Vitaliy; Sakurovs, Richard; Melnichenko, Yuri B.

2018-01-01

Neutron scattering techniques were used to determine the effect of mineral matter on the accessibility of water and toluene to pores in the Devonian Marcellus Shale. Three Marcellus Shale samples, representing quartz-rich, clay-rich, and carbonate-rich facies, were examined using contrast matching small-angle neutron scattering (CM-SANS) at ambient pressure and temperature. Contrast matching compositions of H2O, D2O and toluene, deuterated toluene were used to probe open and closed pores of these three shale samples. Results show that although the mean pore radius was approximately the same for all three samples, the fractal dimension of the quartz-rich sample was higher than for the clay-rich and carbonate-rich samples, indicating different pore size distributions among the samples. The number density of pores was highest in the clay-rich sample and lowest in the quartz-rich sample. Contrast matching with water and toluene mixtures shows that the accessibility of pores to water and toluene also varied among the samples. In general, water accessed approximately 70–80% of the larger pores (>80 nm radius) in all three samples. At smaller pore sizes (~5–80 nm radius), the fraction of accessible pores decreases. The lowest accessibility to both fluids is at pore throat size of ~25 nm radii with the quartz-rich sample exhibiting lower accessibility than the clay- and carbonate-rich samples. The mechanism for this behaviour is unclear, but because the mineralogy of the three samples varies, it is likely that the inaccessible pores in this size range are associated with organics and not a specific mineral within the samples. At even smaller pore sizes (~<2.5 nm radius), in all samples, the fraction of accessible pores to water increases again to approximately 70–80%. Accessibility to toluene generally follows that of water; however, in the smallest pores (~<2.5 nm radius), accessibility to toluene decreases, especially in the clay-rich sample which contains about 30% more closed pores than the quartz- and carbonate-rich samples. Results from this study show that mineralogy of producing intervals within a shale reservoir can affect accessibility of pores to water and toluene and these mineralogic differences may affect hydrocarbon storage and production and hydraulic fracturing characteristics

The Eagle Ford Shale, Texas: an initial insight into Late Cretaceous organic-rich mudrock palaeoenvironments

NASA Astrophysics Data System (ADS)

Forshaw, Joline; Jarvis, Ian; Trabucho-Alexandre, João; Tocher, Bruce; Pearce, Martin

2014-05-01

The hypothesised reduction of oxygen within the oceans during the Cretaceous is believed to have led to extended intervals of regional anoxia in bottom waters, resulting in increased preservation of organic matter and the deposition of black shales. Episodes of more widespread anoxia, and even euxinia, in both bottom and surface waters are associated with widespread black shale deposition during Ocean Anoxic Events (OAEs). The most extensive Late Cretaceous OAE, which occurred ~ 94 Ma during Cenomanian-Turonian boundary times, and was particularly well developed in the proto-North Atlantic and Tethyan regions, lasted for around 500 kyr (OAE2). Although the causes of this and other events are still hotly debated, research is taking place internationally to produce a global picture of the causes and consequences of Cretaceous OAEs. Understanding OAEs will enable a better interpretation of the climate fluctuations that ensued, and their association with the widespread deposition of black shales, rising temperatures, increased pCO2, enhanced weathering, and increased nutrient fluxes. The Eagle Ford Formation, of Cenomanian - Turonian age, is a major shale gas play in SW and NE Texas, extending over an area of more than 45,000 km2. The formation, which consists predominantly of black shales (organic-rich calcareous mudstones), was deposited during an extended period of relative tectonic quiescence in the northern Gulf Coast of the Mexico Basin, bordered by reefs along the continental shelf. The area offers an opportunity to study the effects of OAE2 in an organic-rich shelf setting. The high degree of organic matter preservation in the formation has produced excellent oil and gas source rocks. Vast areas of petroleum-rich shales are now being exploited in the Southern States of the US for shale gas, and the Eagle Ford Shale is fast becoming one of the countries largest producers of gas, oil and condensate. The Eagle Ford Shale stratigraphy is complex and heterogeneous, making further study essential before these resources can be fully developed. Therefore, a thorough understanding of the subsurface sediments within a coherent stratigraphic framework is required before exploitation can be optimimised. Here, we present initial palynological data (dinoflagellate cyst abundance), in conjunction with geochemistry, from material obtained from the Maverick Basin in the southwestern area of Eagle Ford Shale deposition. Results are presented as part of a wider study of the Eagle Ford Shale, utilising both core and outcrop material, that is using dinoflagellate cysts and chemostratigraphy to develop an improved stratigraphic framework and to reconstruct depositional palaeoenvironments in the basin.

Ecological risks of shale oil and gas development to wildlife, aquatic resources and their habitats

USGS Publications Warehouse

Brittingham, Margaret C.; Maloney, Kelly O.; Farag, Aïda M.; Harper, David D.; Bowen, Zachary H.

2014-01-01

Technological advances in hydraulic fracturing and horizontal drilling have led to the exploration and exploitation of shale oil and gas both nationally and internationally. Extensive development of shale resources has occurred within the United States over the past decade, yet full build out is not expected to occur for years. Moreover, countries across the globe have large shale resources and are beginning to explore extraction of these resources. Extraction of shale resources is a multistep process that includes site identification, well pad and infrastructure development, well drilling, high-volume hydraulic fracturing and production; each with its own propensity to affect associated ecosystems. Some potential effects, for example from well pad, road and pipeline development, will likely be similar to other anthropogenic activities like conventional gas drilling, land clearing, exurban and agricultural development and surface mining (e.g., habitat fragmentation and sedimentation). Therefore, we can use the large body of literature available on the ecological effects of these activities to estimate potential effects from shale development on nearby ecosystems. However, other effects, such as accidental release of wastewaters, are novel to the shale gas extraction process making it harder to predict potential outcomes. Here, we review current knowledge of the effects of high-volume hydraulic fracturing coupled with horizontal drilling on terrestrial and aquatic ecosystems in the contiguous United States, an area that includes 20 shale plays many of which have experienced extensive development over the past decade. We conclude that species and habitats most at risk are ones where there is an extensive overlap between a species range or habitat type and one of the shale plays (leading to high vulnerability) coupled with intrinsic characteristics such as limited range, small population size, specialized habitat requirements, and high sensitivity to disturbance. Examples include core forest habitat and forest specialists, sagebrush habitat and specialists, vernal pond inhabitants and stream biota. We suggest five general areas of research and monitoring that could aid in development of effective guidelines and policies to minimize negative impacts and protect vulnerable species and ecosystems: (1) spatial analyses, (2) species-based modeling, (3) vulnerability assessments, (4) ecoregional assessments, and (5) threshold and toxicity evaluations.

Ecological risks of shale oil and gas development to wildlife, aquatic resources and their habitats.

PubMed

Brittingham, Margaret C; Maloney, Kelly O; Farag, Aïda M; Harper, David D; Bowen, Zachary H

2014-10-07

Technological advances in hydraulic fracturing and horizontal drilling have led to the exploration and exploitation of shale oil and gas both nationally and internationally. Extensive development of shale resources has occurred within the United States over the past decade, yet full build out is not expected to occur for years. Moreover, countries across the globe have large shale resources and are beginning to explore extraction of these resources. Extraction of shale resources is a multistep process that includes site identification, well pad and infrastructure development, well drilling, high-volume hydraulic fracturing and production; each with its own propensity to affect associated ecosystems. Some potential effects, for example from well pad, road and pipeline development, will likely be similar to other anthropogenic activities like conventional gas drilling, land clearing, exurban and agricultural development and surface mining (e.g., habitat fragmentation and sedimentation). Therefore, we can use the large body of literature available on the ecological effects of these activities to estimate potential effects from shale development on nearby ecosystems. However, other effects, such as accidental release of wastewaters, are novel to the shale gas extraction process making it harder to predict potential outcomes. Here, we review current knowledge of the effects of high-volume hydraulic fracturing coupled with horizontal drilling on terrestrial and aquatic ecosystems in the contiguous United States, an area that includes 20 shale plays many of which have experienced extensive development over the past decade. We conclude that species and habitats most at risk are ones where there is an extensive overlap between a species range or habitat type and one of the shale plays (leading to high vulnerability) coupled with intrinsic characteristics such as limited range, small population size, specialized habitat requirements, and high sensitivity to disturbance. Examples include core forest habitat and forest specialists, sagebrush habitat and specialists, vernal pond inhabitants and stream biota. We suggest five general areas of research and monitoring that could aid in development of effective guidelines and policies to minimize negative impacts and protect vulnerable species and ecosystems: (1) spatial analyses, (2) species-based modeling, (3) vulnerability assessments, (4) ecoregional assessments, and (5) threshold and toxicity evaluations.

Organic and inorganic composition and microbiology of produced waters from Pennsylvania shale gas wells

USGS Publications Warehouse

Akob, Denise M.; Cozzarelli, Isabelle M.; Dunlap, Darren S.; Rowan, Elisabeth L.; Lorah, Michelle M.

2015-01-01

Hydraulically fractured shales are becoming an increasingly important source of natural gas production in the United States. This process has been known to create up to 420 gallons of produced water (PW) per day, but the volume varies depending on the formation, and the characteristics of individual hydraulic fracture. PW from hydraulic fracturing of shales are comprised of injected fracturing fluids and natural formation waters in proportions that change over time. Across the state of Pennsylvania, shale gas production is booming; therefore, it is important to assess the variability in PW chemistry and microbiology across this geographical span. We quantified the inorganic and organic chemical composition and microbial communities in PW samples from 13 shale gas wells in north central Pennsylvania. Microbial abundance was generally low (66–9400 cells/mL). Non-volatile dissolved organic carbon (NVDOC) was high (7–31 mg/L) relative to typical shallow groundwater, and the presence of organic acid anions (e.g., acetate, formate, and pyruvate) indicated microbial activity. Volatile organic compounds (VOCs) were detected in four samples (∼1 to 11.7 μg/L): benzene and toluene in the Burket sample, toluene in two Marcellus samples, and tetrachloroethylene (PCE) in one Marcellus sample. VOCs can be either naturally occurring or from industrial activity, making the source of VOCs unclear. Despite the addition of biocides during hydraulic fracturing, H2S-producing, fermenting, and methanogenic bacteria were cultured from PW samples. The presence of culturable bacteria was not associated with salinity or location; although organic compound concentrations and time in production were correlated with microbial activity. Interestingly, we found that unlike the inorganic chemistry, PW organic chemistry and microbial viability were highly variable across the 13 wells sampled, which can have important implications for the reuse and handling of these fluids

Porosity evolution during weathering of Marcellus shale

NASA Astrophysics Data System (ADS)

Gu, X.; Brantley, S.

2017-12-01

Weathering is an important process that continuously converts rock to regolith. Shale weathering is of particular interest because 1) shale covers about 25% of continental land mass; 2) recent development of unconventional shale gas generates large volumes of rock cuttings. When cuttings are exposed at earth's surface, they can release toxic trace elements during weathering. In this study, we investigated the evolution of pore structures and mineral transformation in an outcrop of Marcellus shale - one of the biggest gas shale play in North America - at Frankstown, Pennsylvania. A combination of neutron scattering and imaging was used to characterize the pore structures from nm to mm. The weathering profile of Marcellus shale was also compared to the well-studied Rose Hill shale from the Susquehanna Shale Hills critical zone observatory nearby. This latter shale has a similar mineral composition as Marcellus shale but much lower concentrations of pyrite and OC. The Marcellus shale formation in outcrop overlies a layer of carbonate at 10 m below land surface with low porosity (<3%). All the shale samples above the carbonate layer are almost completely depleted in carbonate, plagioclase, chlorite and pyrite. The porosities in the weathered Marcellus shale are twice as high as in protolith. The pore size distribution exhibits a broad peak for pores of size in the range of 10s of microns, likely due to the loss of OC and/or dissolution of carbonate during weathering. In the nearby Rose Hill shale, the pyrite and carbonate are sharply depleted close to the water table ( 15-20 m at ridgetop); while chlorite and plagioclase are gradually depleted toward the land surface. The greater weathering extent of silicates in the Marcellus shale despite the similarity in climate and erosion rate in these two neighboring locations is attributed to 1) the formation of micron-size pores increases the infiltration rate into weathered Marcellus shale and therefore promotes mineral weathering; 2) the pyrite/carbonate ratio is higher in the Marcellus shale than in Rose Hill shale, and thus excess acidity generated through pyrite oxidation enhances the dissolution of silicates. We seek to use these and other observations to develop a global model for shale weathering that incorporates both mineral composition and porosity change.

United States Air Force Shale Oil to Fuels. Phase II.

DTIC Science & Technology

1981-11-01

and modified so that any off-gas from the LPS, stripper column, product drums, spent caustic drums, and sample ports would be sent to the caustic ...product, or in the spent caustic . After the desalted Paraho shale oil was processed in Production Run No. 2, the catalyst bed was flushed with light cycle...58 20 First-Stage Hydrotreating of Occidental Shale Oil -- Spent Catalyst Analysis - Run 1 ....... 59 21 First-Stage Hydrotreating of Occidental

Understanding public perception of hydraulic fracturing: a case study in Spain.

PubMed

Costa, D; Pereira, V; Góis, J; Danko, A; Fiúza, A

2017-12-15

Public acceptance is crucial for the implementation of energy technologies. Hydraulic fracturing is a technology widely used in the USA for natural gas production from shale formations, but currently finds strong public opposition worldwide, especially in Europe. Shale gas exploitation and exploration have the potential to significantly reduce import dependency in several countries, including Spain. To better understand public opinion on this issue, this article reports a survey targeting both the entire Spanish population and the inhabitants of the province of Burgos, the location where shale gas exploration permits have already been issued. Results demonstrate that half of the Spanish population opposes shale gas, and this opposition increases in autonomous communities that are closer to possible exploration sites. The results also show that socio-demographic aspects are not strong predictors of opposition. In addition, Burgos' population show different behaviours toward shale gas that demonstrates that proximity and prospect of shale gas development affects opinion. Finally, there is still a great level of unfamiliarity with high volume hydraulic fracturing and shale gas in both populations sampled. Copyright © 2017 Elsevier Ltd. All rights reserved.

Reconnaissance for uranium in black shale, Northern Rocky Mountains and Great Plains, 1953

USGS Publications Warehouse

Mapel, W.J.

1954-01-01

Reconnaissance examinations for uranium in 22 formations containing black shale were conducted in parts of Montana, North Dakota, Utah, Idaho, and Oregon during 1953. About 150 samples from 80 outcrop localities and 5 oil and gas wells were submitted for uranium determinations. Most of the black shale deposits examined contain less than 0.003 percent uranium; however, thin beds of black shale at the base of the Mississippian system contain 0.005 percent uranium at 2 outcrop localities in southwestern Montana and as much as 0.007 percent uranium in a well in northeastern Montana. An eight-foot bed of phosphatic black shale at the base of the Brazer limestone of Late Mississippian age in Rich County, Utah, contains as much as 0.009 percent uranium. Commercial gamma ray logs of oil and gas wells drilled in Montana and adjacent parts of the Dakotas indicate that locally the Heath shale of Late Mississippian age contains as much as 0.01 percent equivalent uranium, and black shales of Late Cretaceous age contain as much as 0.008 percent equivalent uranium.

Methane Occurrence in a Drinking Water Aquifer Before and During Natural Gas Production from the Marcellus Shale

NASA Astrophysics Data System (ADS)

Saiers, J. E.; Barth-Naftilan, E.

2017-12-01

More than 4,000 thousand wells have punctured aquifers of Pennsylvania's northern tier to siphon natural gas from the underlying Marcellus Shale. As drilling and hydraulic fracturing ramped up a decade ago, homeowner reports of well water contamination by methane and other contaminants began to emerge. Although made infrequently compared to the number of gas wells drilled, these reports were troubling and motivated our two-year, prospective study of groundwater quality within the Marcellus Shale Play. We installed multi-level sampling wells within a bedrock aquifer of a 25 km2 area that was targeted for shale gas development. These wells were sampled on a monthly basis before, during, and after seven shale gas wells were drilled, hydraulically fractured, and placed into production. The groundwater samples, together with surface water samples collected from nearby streams, were analyzed for hydrocarbons, trace metals, major ions, and the isotopic compositions of methane, ethane, water, strontium, and dissolved inorganic carbon. With regard to methane in particular, concentrations ranged from under 0.1 to over 60 mg/L, generally increased with aquifer depth, and, at some sites, exhibited considerable temporal variability. The isotopic composition of methane and hydrocarbon ratios also spanned a large range, suggesting that methane origins are diverse and, notably, shift on the time scale of this study. We will present inferences on factors governing methane occurrence across our study area by interpreting time-series data on methane concentrations and isotopic composition in context of local hydrologic variation, companion measurements of groundwater chemistry, and the known timing of key stages of natural gas extraction.

Fracturing and brittleness index analyses of shales

NASA Astrophysics Data System (ADS)

Barnhoorn, Auke; Primarini, Mutia; Houben, Maartje

2016-04-01

The formation of a fracture network in rocks has a crucial control on the flow behaviour of fluids. In addition, an existing network of fractures , influences the propagation of new fractures during e.g. hydraulic fracturing or during a seismic event. Understanding of the type and characteristics of the fracture network that will be formed during e.g. hydraulic fracturing is thus crucial to better predict the outcome of a hydraulic fracturing job. For this, knowledge of the rock properties is crucial. The brittleness index is often used as a rock property that can be used to predict the fracturing behaviour of a rock for e.g. hydraulic fracturing of shales. Various terminologies of the brittleness index (BI1, BI2 and BI3) exist based on mineralogy, elastic constants and stress-strain behaviour (Jin et al., 2014, Jarvie et al., 2007 and Holt et al., 2011). A maximum brittleness index of 1 predicts very good and efficient fracturing behaviour while a minimum brittleness index of 0 predicts a much more ductile shale behaviour. Here, we have performed systematic petrophysical, acoustic and geomechanical analyses on a set of shale samples from Whitby (UK) and we have determined the three different brittleness indices on each sample by performing all the analyses on each of the samples. We show that each of the three brittleness indices are very different for the same sample and as such it can be concluded that the brittleness index is not a good predictor of the fracturing behaviour of shales. The brittleness index based on the acoustic data (BI1) all lie around values of 0.5, while the brittleness index based on the stress strain data (BI2) give an average brittleness index around 0.75, whereas the mineralogy brittleness index (BI3) predict values below 0.2. This shows that by using different estimates of the brittleness index different decisions can be made for hydraulic fracturing. If we would rely on the mineralogy (BI3), the Whitby mudstone is not a suitable candidate for hydraulic fracturing while if we would rely on stress-strain data (BI2) the Whitby mudstone would be a very good candidate. We are aiming to perform these kind of measurements on a wide variety of shales with varying compositions and origins etc. and compare all results and come up with a better brittleness index, as well as link the brittleness indices to the fracturing behaviour seen in the samples. References: Holt, R., Fjaer, E., Nes, O. & Alassi, H., 2011. A shaly look at brittleness. 45th U.S. Rock Mechanics / Geomechanics Symposium, ARMA-11-366 Jarvie, D., Hill, J., Ruble, T. & Pollastro, R., 2007. Unconventional shale-gas system: The Mississippian Barnett Shale of North-Central Texas as one model for thermogenic shale-gas assessment. AAPG, 91(doi: 10.1306/12190606068), pp. 475-499. Jin, X., Shah, S. N., Rogiers, J.-C. & Zhang, B., 2014. Fraccability Evaluation in Shale Reservoirs - An Integrated Petrophysics and Geomechanics Approach. Woodlands, Texas, SPE.

Hierarchical Pore Morphology of Cretaceous Shale: A Small-Angle Neutron Scattering and Ultrasmall-Angle Neutron Scattering Study

DOE PAGES

Bahadur, J.; Melnichenko, Y. B.; Mastalerz, Maria; ...

2014-09-25

Shale reservoirs are becoming an increasingly important source of oil and natural gas supply and a potential candidate for CO 2 sequestration. Understanding the pore morphology in shale may provide clues to making gas extraction more efficient and cost-effective. The porosity of Cretaceous shale samples from Alberta, Canada, collected from different depths with varying mineralogical compositions, has been investigated by small- and ultrasmall-angle neutron scattering. Moreover these samples come from the Second White Specks and Belle Fourche formations, and their organic matter content ranges between 2 and 3%. The scattering length density of the shale specimens has been estimated usingmore » the chemical composition of the different mineral components. Scattering experiments reveal the presence of fractal and non-fractal pores. It has been shown that the porosity and specific surface area are dominated by the contribution from meso- and micropores. The fraction of closed porosity has been calculated by comparing the porosities estimated by He pycnometry and scattering techniques. There is no correlation between total porosity and mineral components, a strong correlation has been observed between closed porosity and major mineral components in the studied specimens.« less

Oxidation and mobilization of selenium by nitrate in irrigation drainage

USGS Publications Warehouse

Wright, W.G.

1999-01-01

Selenium (Se) can be oxidized by nitrate (NO3-) from irrigation on Cretaceous marine shale in western Colorado. Dissolved Se concentrations are positively correlated with dissolved NO3- concentrations in surface water and ground water samples from irrigated areas. Redox conditions dominate in the mobilization of Se in marine shale hydrogeologic settings; dissolved Se concentrations increase with increasing platinum-electrode potentials. Theoretical calculations for the oxidation of Se by NO3- and oxygen show favorable Gibbs free energies for the oxidation of Se by NO3-, indicating NO3- can act as an electron acceptor for the oxidation of Se. Laboratory batch experiments were performed by adding Mancos Shale samples to zero- dissolved-oxygen water containing 0, 5, 50, and 100 mg/L NO3- as N (mg N/L). Samples were incubated in airtight bottles at 25??C for 188 d; samples collected from the batch experiment bottles show increased Se concentrations over time with increased NO3- concentrations. Pseudo first-order rate constants for NO3- oxidation of Se ranged from 0.0007 to 0.0048/d for 0 to 100 mg N/L NO3- concentrations, respectively. Management of N fertilizer applications in Cretaceous shale settings might help to control the oxidation and mobilization of Se and other trace constituents into the environment.

Chemical and mineralogical analysis of devonian black-shale samples from Martin County, Kentucky; Carroll and Washington counties, Ohio; Wise County, Virginia; and Overton County, Tennessee, U.S.A.

USGS Publications Warehouse

Leventhal, J.S.; Hosterman, J.W.

1982-01-01

Core samples of Devonian shales from five localities in the Appalachian basin have been analyzed chemically and mineralogically. The amounts of major elements are similar; however, the minor constituents, organic C, S, phosphate and carbonate show ten-fold variations in amounts. Trace elements Mo, Ni, Cu, V, Co, U, Zn, Hg, As and Mn show variations in amounts that can be related to the minor constituents. All samples contain major amounts of quartz, illite, two types of mixed-layer clays, and chlorite in differing quantities. Pyrite, calcite, feldspar and kaolinite are also present in many samples in minor amounts. Dolomite, apatite, gypsum, barite, biotite and marcasite are present in a few samples in trace amounts. Trace elements listed above are strongly controlled by organic C with the exception of Mn which is associated with carbonate minerals. Amounts of organic C generally range from 3 to 6%, and S is in the range of 2-5%. Amounts of trace elements show the following general ranges in ppm (parts per million): Co, 20-40; Cu, 40-70; U, 10-40; As, 20-40; V, 150-300; Ni, 80-150; high values are as much as twice these values. The organic C was probably the concentrating agent, and the organic C and sulfide S together created an environment that immobilized and preserved these trace elements. Closely spaced samples showing an abrupt transition in color also show changes in organic C, S and trace-element contents. Several associations exist between mineral and chemical content. Pyrite and marcasite are the only minerals found to contain sulfide-S. In general, the illite-chlorite mixed-layer clay mineral shows covariation with organic C if calcite is not present. The enriched trace elements are not related to the clay types, although the clay and organic matter are intimately associated as the bulk fabric of the rock. ?? 1982.

USAF shale oil program status

NASA Technical Reports Server (NTRS)

Delaney, C. L.

1984-01-01

The test and evaluation program on shale derived fuel being conducted by the Air Force is intended to accomplish the minimum amount of testing necessary to assure both the safe use of shale oil derived turbine fuels in operational USAF aircraft and its compatibility with USAF handling systems. This program, which was designed to take advantage of existing R&D testing programs, began in 1981. However, due to a problem in acquiring the necessary fuel, the testing program was suspended until July 1983 when an additional sample of shale derived fuel was received. Tentatively, the Air Force is planning to make three relatively minor revisions to the procurement specifications requirements for the production shale derived fuel. These are: (1) Aromatic Contest (min) - 9% (by volume); (2) Nitrogen (max - 20 ppm by weight); and (3) Antioxidants - 9.1 g/100 gal (U.S.)

Impact of Oxidative Dissolution on Black Shale Fracturing: Implication for Shale Fracturing Treatment Design

NASA Astrophysics Data System (ADS)

You, L.; Chen, Q.; Kang, Y.; Cheng, Q.; Sheng, J.

2017-12-01

Black shales contain a large amount of environment-sensitive compositions, e.g., clay minerals, carbonate, siderite, pyrite, and organic matter. There have been numerous studies on the black shales compositional and pore structure changes caused by oxic environments. However, most of the studies did not focus on their ability to facilitate shale fracturing. To test the redox-sensitive aspects of shale fracturing and its potentially favorable effects on hydraulic fracturing in shale gas reservoirs, the induced microfractures of Longmaxi black shales exposed to deionized water, hydrochloric acid, and hydrogen peroxide at room-temperature for 240 hours were imaged by scanning electron microscopy (SEM) and CT-scanning in this paper. Mineral composition, acoustic emission, swelling, and zeta potential of the untreated and oxidative treatment shale samples were also recorded to decipher the coupled physical and chemical effects of oxidizing environments on shale fracturing processes. Results show that pervasive microfractures (Fig.1) with apertures ranging from tens of nanometers to tens of microns formed in response to oxidative dissolution by hydrogen peroxide, whereas no new microfracture was observed after the exposure to deionized water and hydrochloric acid. The trajectory of these oxidation-induced microfractures was controlled by the distribution of phyllosilicate framework and flaky or stringy organic matter in shale. The experiments reported in this paper indicate that black shales present the least resistance to crack initiation and subcritical slow propagation in hydrogen peroxide, a process we refer to as oxidation-sensitive fracturing, which are closely related to the expansive stress of clay minerals, dissolution of redox-sensitive compositions, destruction of phyllosilicate framework, and the much lower zeta potential of hydrogen peroxide solution-shale system. It could mean that the injection of fracturing water with strong oxidizing aqueous solution may play an important role in improving hydraulic fracturing of shale formation by reducing the energy requirements for crack growth. However, additional work is needed to the selection of highly-effective, economical, and environmentally friendly oxidants.

Total arsenic and selenium analysis in Marcellus shale, high-salinity water, and hydrofracture flowback wastewater.

PubMed

Balaba, Ronald S; Smart, Ronald B

2012-11-01

Trace levels of arsenic and selenium can be toxic to living organisms yet their quantitation in high ionic strength or high salinity aqueous media is difficult due to the matrix interferences which can either suppress or enhance the analyte signal. A modified thiol cotton fiber (TCF) method employing lower flow rates and centrifugation has been used to remove the analyte from complex aqueous media and minimize the matrix interferences. This method has been tested using a USGS (SGR-1b) certified reference shale. It has been used to analyze Marcellus shale samples following microwave digestion as well as spiked samples of high salinity water (HSW) and flow back wastewater (WRF6) obtained from an actual gas well drilling operation. Quantitation of arsenic and selenium is carried out by graphite furnace atomic spectroscopy (GFAAS). Extraction of arsenic and selenium from Marcellus shale exposed to HSW and WRF6 for varying lengths of time is also reported. Copyright © 2012 Elsevier Ltd. All rights reserved.

Refining of Military Jet Fuels from Shale Oil. Volume I. Part II. Preparation of Laboratory-Scale Fuel Samples.

DTIC Science & Technology

1982-03-01

ON SPEC Meeting Specifications *1 OXY Test Series on In Situ Shale Oil P Pressure (P + N) Paraffins and Naphthenes PHO Test Series on Above-Ground...material, the crude shale is heated and processed through caustic desalt- ing similar to conventional technology. The desalted oil is mixed with recycle...with hot regenerated catalyst. Spent catalyst and oil vapors are disengaqed by -.eans of high temperature cyclones. The spent catalyst first passes

Simultaneous Neutron and X-ray Tomography for Quantitative analysis of Geological Samples

NASA Astrophysics Data System (ADS)

LaManna, J.; Hussey, D. S.; Baltic, E.; Jacobson, D. L.

2016-12-01

Multiphase flow is a critical area of research for shale gas, oil recovery, underground CO2 sequestration, geothermal power, and aquifer management. It is critical to understand the porous structure of the geological formations in addition to the fluid/pore and fluid/fluid interactions. Difficulties for analyzing flow characteristics of rock cores are in obtaining 3D distribution information on the fluid flow and maintaining the cores in a state for other analysis methods. Two powerful non-destructive methods for obtaining 3D structural and compositional information are X-ray and neutron tomography. X-ray tomography produces information on density and structure while neutrons excel at acquiring the liquid phase and produces compositional information. These two methods can offer strong complementary information but are typically conducted at separate times and often at different facilities. This poses issues for obtaining dynamic and stochastic information as the sample will change between analysis modes. To address this, NIST has developed a system that allows for multimodal, simultaneous tomography using thermal neutrons and X-rays by placing a 90 keVp micro-focus X-ray tube 90° to the neutron beam. High pressure core holders that simulate underground conditions have been developed to facilitate simultaneous tomography. These cells allow for the control of confining pressure, axial load, temperature, and fluid flow through the core. This talk will give an overview the simultaneous neutron and x-ray tomography capabilities at NIST, the benefits of multimodal imaging, environmental equipment for geology studies, and several case studies that have been conducted at NIST.

Composition of the Rex Chert and associated rocks of the Permian Phosphoria Formation: Soda Springs area, SE Idaho

USGS Publications Warehouse

Hein, James R.; McIntyre, Brandie; Perkins, Robert B.; Piper, David Z.; Evans, James

2002-01-01

This study, one in a series, reports bulk chemical and mineralogical compositions, as well as petrographic and outcrop descriptions of rocks collected from three measured outcrop sections of the Rex Chert member of the Phosphoria Formation in SE Idaho. The three measured sections were chosen from ten outcrops of Rex Chert that were described in the field. The Rex Chert overlies the Meade Peak Phosphatic Shale Member of the Phosphoria Formation, the source of phosphate ore in the region. Rex Chert removed as overburden comprises part of the material disposed in waste-rock piles during phosphate mining. It has been proposed that the chert be used to cap and isolate waste piles, thereby inhibiting the leaching of potentially toxic elements into the environment. It is also used to surface roads in the mining district. The rock samples studied here constitute a set of individual chert beds that are representative of each stratigraphic section sampled. The informally named cherty shale member that overlies the Rex Chert in measured section 1 was also described and sampled. The upper Meade Peak and the transition zone to the Rex Chert were described and sampled in section 7. The cherts are predominantly spicularite composed of granular and mosaic quartz, and sponge spicules, with various but minor amounts of other fossils and detrital grains. The cherty shale member and transition rocks between the Meade Peak and Rex Chert are siliceous siltstones and argillaceous cherts with ghosts of sponge spicules and somewhat more detrital grains than the chert. The overwhelmingly dominant mineral is quartz, although carbonate beds are rare in each section and are composed predominantly of calcite and dolomite in addition to quartz. Feldspar, mica, clay minerals, calcite, dolomite, and carbonate fluorapatite are minor to trace minerals in the chert. The mean concentrations of oxides and elements in the Rex Chert and the cherty shale member are dominated by SiO2, which averages 94.6%. Organic-carbon contents are generally very low in the chert, but are up to 1.8 wt. % in cherty shale member samples and up to 3.3% in samples from the transition between the Meade Peak and Rex Chert. Likewise, phosphate (P2O5) is generally low in the chert, but can be up to 3.1% in individual beds. Selenium concentrations in Rex Chert and cherty shale member samples vary from Q-mode factors are interpreted to represent the following rock and mineral components: chert-silica component consisting of Si (± Ba); phosphorite-phosphate component composed of P, Ca, As, Y, V, Cr, Sr, and La (± Fe, Zn, Cu, Ni, Li, Se, Nd, Hg); shale component composed of Al, Na, Zr, K, Ba, Li, and organic C (± Ti, Mg, Se, Ni, Fe, Sr, V, Mn, Zn); carbonate component (dolomite, calcite, silicified carbonates) composed of carbonate C, Mg, Ca, and Si (± Mn); tentatively organic matter-hosted elements (and/or sulfide-sulfate phases) composed of Cu (± organic C, Zn, Mn Si, Ni, Hg, and Li). Selenium shows a dominant association with the shale component, but correlations and Qmode factors also indicate that organic matter (within the shale component) and carbonate fluorapatite may host a portion of the Se. Consideration of larger numbers of factors in Qmode analysis indicates that native Se (a factor containing Se (± Ba)) may also comprise a minor component of the Se compliment.

Munsell color value as related to organic carbon in Devonian shale of Appalachian basin

USGS Publications Warehouse

Hosterman, J.W.; Whitlow, S.I.

1981-01-01

Comparison of Munsell color value with organic carbon content of 880 samples from 50 drill holes in Appalachian basin shows that a power curve is the best fit for the data. A color value below 3 to 3.5 indicates the presence of organic carbon but is meaningless in determining the organic carbon content because a large increase in amount of organic carbon causes only a minor decrease in color value. Above 4, the color value is one of the factors that can be used in calculating the organic content. For samples containing equal amounts of organic carbon, calcareous shale containing more than 5% calcite is darker than shale containing less than 5% calcite.-Authors

The use of shale ash in dry mix construction materials

NASA Astrophysics Data System (ADS)

Gulbe, L.; Setina, J.; Juhnevica, I.

2017-10-01

The research was made to determine the use of shale ash usage in dry mix construction materials by replacing part of cement amount. Cement mortar ZM produced by SIA Sakret and two types of shale ashes from Narva Power plant (cyclone ash and electrostatic precipitator ash) were used. Fresh mortar properties, hardened mortar bulk density, thermal conductivity (λ10, dry) (table value) were tested in mortar ZM samples and mortar samples in which 20% of the amount of cement was replaced by ash. Compressive strenght, frost resistance and resistance to sulphate salt solutions were checked. It was stated that the use of electrostatic precipitator ash had a little change of the material properties, but the cyclone ash significantly reduced the mechanical strength of the material.

Refining of Military Jet Fuels from Shale Oil. Part II. Volume III. Above Ground Shale Oil Process Data.

DTIC Science & Technology

1982-03-01

system. Regenerator flue gas composi- tion, spent catalyst carbon content and regenerated cata- lyst content are monitored for material balance purposes...and good material balance closures obtained. During each run pro- duct gas samples, regenerator flue gas samples, spent and -85- regenerated...TEMPERATURE DEPENDENCE OF DENITROGENATION AT 2 LHSV ON CO/MO ......................... 26 111-2 TEMPERATURE DEPENDENCE OF DESULFURIZATION AT 2 LHSV ON

Methane occurrence in groundwater of south-central New York State, 2012: summary of findings

USGS Publications Warehouse

Heisig, Paul M.; Scott, Tia-Marie

2013-01-01

A survey of methane in groundwater was undertaken to document methane occurrence on the basis of hydrogeologic setting within a glaciated 1,810-square-mile area of south-central New York that has not seen shale-gas resource development. The adjacent region in northeastern Pennsylvania has undergone shale-gas resource development from the Marcellus Shale. Well construction and subsurface data were required for each well sampled so that the local hydrogeologic setting could be classified. All wells were also at least 1 mile from any known gas well (active, exploratory, or abandoned). Sixty-six domestic wells and similar purposed supply wells were sampled during summer 2012. Field water-quality characteristics (pH, specific conductance, dissolved oxygen, and temperature) were measured at each well, and samples were collected and analyzed for dissolved gases, including methane and short-chain hydrocarbons. Carbon and hydrogen isotopic ratios of methane were measured in 21 samples that had at least 0.3 milligram per liter (mg/L) methane.

Using Archean and Paleoproterozoic Shales and Tillites as a Window into Crustal Evolution and Surface Conditions

NASA Astrophysics Data System (ADS)

Bindeman, I. N.; Bekker, A.; Zakharov, D. O.

2014-12-01

Precambrian shales and tillites have been insufficiently studied so far. We present oxygen and hydrogen isotope data for 103 bulk shale and tillites that were collected from drillholes on all continents from 3.2 to 1.4Ga. These samples have also been analyzed for total organic and inorganic carbon, total sulfur, δ13Corg values and by XRF for major and trace elements to calculate chemical index of alteration (CIA). Having uncompromised fresh samples from drillcores is a must for this kind of investigation. We have a particularly good coverage for the ca. 2.7-2.2 Ga time interval when Earth experienced 3-4 Snowball Earth glaciations associated with the rapid rise in atmospheric O2 and fluctuations in CO2, thus affecting weathering cycle and attainment of isotopic fractionation. All units have similar to Phanerozoic ranges in δ13Corg values (-23 to -33‰ PDB) and Corg content (0.1 to 10 wt. %). Compared to Phanerozoic shales, Precambrian shales have comparable ranges in δ18O values (+7 to +20‰), with slightly decreasing means with increasing age, and identical δ17O-δ18O slope (0.528). Shales in some drill holes display wide δ18O ranges over short stratigraphic intervals suggesting significant variability in the provenance. We however observe a significant, several permil downward shift and decrease in the range of δ18O values (7-9‰) in 2.2-2.5 Ga shales from several continents that are associated with the Paleoproterozoic glaciations. Scattered negative correlation of CIA with δ18O, for some of these shales broadly associated with the Paleoproterozoic glaciations suggest contact with glacial meltwater having ultra-low-δ18O values during deposition or diagenesis of these shales. The δD values of shales range from -50 to -75‰, and are comparable to Phanerozoic values, with the exception of the ~2.5-2.2 Ga shales that reach to -100‰. We also compare O isotope values of ultra-low-δ18O, +8 to -27‰ SMOW subglacial hydrothermal rocks recently discovered in Karelia (Russia), quartz amygdules in mafics and their relations to our global shale dataset. The overall conclusion is that despite first-order changes in areal mass, exposed surface conditions, pCO2, pO2 affecting chemical/physical weathering cycle, it was not dramatically different before and after the rise of atmospheric oxygen at ~2.3-2.4 Ga.

Dual pore-connectivity and flow-paths affect shale hydrocarbon production

NASA Astrophysics Data System (ADS)

Hayman, N. W.; Daigle, H.; Kelly, E. D.; Milliken, K. L.; Jiang, H.

2016-12-01

Aided with integrated characterization approaches of droplet contact angle measurement, mercury intrusion capillary pressure, low-pressure gas physisorption, scanning electron microscopy, and small angle neutron scattering, we have systematically studied how pore connectivity and wettability are associated with mineral and organic matter phases of shales (Barnett, Bakken, Eagle Ford), as well as their influence on macroscopic fluid flow and hydrocarbon movement, from the following complementary tests: vacuum saturation with vacuum-pulling on dry shale followed with tracer introduction and high-pressure intrusion, tracer diffusion into fluid-saturated shale, fluid and tracer imbibition into partially-saturated shale, and Wood's metal intrusion followed with imaging and elemental mapping. The first three tests use tracer-bearing fluids (hydrophilic API brine and hydrophobic n-decane) fluids with a suite of wettability tracers of different sizes and reactivities developed in our laboratory. These innovative and integrated approaches indicate a Dalmatian wettability behavior at a scale of microns, limited connectivity (<500 microns from shale sample edge) shale pores, and disparity of well-connected hydrophobic pore network ( 10 nm) and sparsely connected hydrophilic pore systems (>50-100 nm), which is linked to the steep initial decline and low overall recovery because of the limited connection of hydrocarbon molecules in the shale matrix to the stimulated fracture network.

Nanoscale simulation of shale transport properties using the lattice Boltzmann method: Permeability and diffusivity

DOE Office of Scientific and Technical Information (OSTI.GOV)

Chen, Li; Zhang, Lei; Kang, Qinjun

Here, porous structures of shales are reconstructed using the markov chain monte carlo (MCMC) method based on scanning electron microscopy (SEM) images of shale samples from Sichuan Basin, China. Characterization analysis of the reconstructed shales is performed, including porosity, pore size distribution, specific surface area and pore connectivity. The lattice Boltzmann method (LBM) is adopted to simulate fluid flow and Knudsen diffusion within the reconstructed shales. Simulation results reveal that the tortuosity of the shales is much higher than that commonly employed in the Bruggeman equation, and such high tortuosity leads to extremely low intrinsic permeability. Correction of the intrinsicmore » permeability is performed based on the dusty gas model (DGM) by considering the contribution of Knudsen diffusion to the total flow flux, resulting in apparent permeability. The correction factor over a range of Knudsen number and pressure is estimated and compared with empirical correlations in the literature. We find that for the wide pressure range investigated, the correction factor is always greater than 1, indicating Knudsen diffusion always plays a role on shale gas transport mechanisms in the reconstructed shales. Specifically, we found that most of the values of correction factor fall in the slip and transition regime, with no Darcy flow regime observed.« less

Shale characterization on Barito field, Southeast Kalimantan for shale hydrocarbon exploration

NASA Astrophysics Data System (ADS)

Sumotarto, T. A.; Haris, A.; Riyanto, A.; Usman, A.

2017-07-01

Exploration and exploitation in Indonesia now are still focused on conventional hydrocarbon energy than unconventional hydrocarbon energy such as shale gas. Tanjung Formation is a source rock of Barito Basin located in South Kalimantan that potentially as shale hydrocarbon. In this research, integrated methods using geochemical analysis, mineralogy, petrophysical analysis and seismic interpretation has been applied to explore the shale hydrocarbon potential in Barito Field for Tanjung formation. The first step is conducting geochemical and mineralogy analysis to the shale rock sample. Our analysis shows that the organic richness is ranging from 1.26-5.98 wt.% (good to excellent) with the depth of early mature window of 2170 m. The brittleness index is in an average of 0.44-0.56 (less Brittle) and Kerogen type is classified into II/III type that potentially produces oil and gas. The second step is continued by performing petrophysical analysis, which includes Total Organic Carbon (TOC) calculation and brittleness index continuously. The result has been validated with a laboratory measurement that obtained a good correlation. In addition, seismic interpretation based on inverted acoustic impedance is applied to map the distributions of shale hydrocarbon potential. Our interpretation shows that shale hydrocarbon potential is localized in the eastern and southeastern part of the study area.

Dual pore-connectivity and flow-paths affect shale hydrocarbon production

NASA Astrophysics Data System (ADS)

Hu, Q.; Barber, T.; Zhang, Y.; Md Golam, K.

2017-12-01

Aided with integrated characterization approaches of droplet contact angle measurement, mercury intrusion capillary pressure, low-pressure gas physisorption, scanning electron microscopy, and small angle neutron scattering, we have systematically studied how pore connectivity and wettability are associated with mineral and organic matter phases of shales (Barnett, Bakken, Eagle Ford), as well as their influence on macroscopic fluid flow and hydrocarbon movement, from the following complementary tests: vacuum saturation with vacuum-pulling on dry shale followed with tracer introduction and high-pressure intrusion, tracer diffusion into fluid-saturated shale, fluid and tracer imbibition into partially-saturated shale, and Wood's metal intrusion followed with imaging and elemental mapping. The first three tests use tracer-bearing fluids (hydrophilic API brine and hydrophobic n-decane) fluids with a suite of wettability tracers of different sizes and reactivities developed in our laboratory. These innovative and integrated approaches indicate a Dalmatian wettability behavior at a scale of microns, limited connectivity (<500 microns from shale sample edge) shale pores, and disparity of well-connected hydrophobic pore network ( 10 nm) and sparsely connected hydrophilic pore systems (>50-100 nm), which is linked to the steep initial decline and low overall recovery because of the limited connection of hydrocarbon molecules in the shale matrix to the stimulated fracture network.

Nanoscale simulation of shale transport properties using the lattice Boltzmann method: Permeability and diffusivity

DOE PAGES

Chen, Li; Zhang, Lei; Kang, Qinjun; ...

2015-01-28

Here, porous structures of shales are reconstructed using the markov chain monte carlo (MCMC) method based on scanning electron microscopy (SEM) images of shale samples from Sichuan Basin, China. Characterization analysis of the reconstructed shales is performed, including porosity, pore size distribution, specific surface area and pore connectivity. The lattice Boltzmann method (LBM) is adopted to simulate fluid flow and Knudsen diffusion within the reconstructed shales. Simulation results reveal that the tortuosity of the shales is much higher than that commonly employed in the Bruggeman equation, and such high tortuosity leads to extremely low intrinsic permeability. Correction of the intrinsicmore » permeability is performed based on the dusty gas model (DGM) by considering the contribution of Knudsen diffusion to the total flow flux, resulting in apparent permeability. The correction factor over a range of Knudsen number and pressure is estimated and compared with empirical correlations in the literature. We find that for the wide pressure range investigated, the correction factor is always greater than 1, indicating Knudsen diffusion always plays a role on shale gas transport mechanisms in the reconstructed shales. Specifically, we found that most of the values of correction factor fall in the slip and transition regime, with no Darcy flow regime observed.« less

Nanoscale simulation of shale transport properties using the lattice Boltzmann method: permeability and diffusivity

PubMed Central

Chen, Li; Zhang, Lei; Kang, Qinjun; Viswanathan, Hari S.; Yao, Jun; Tao, Wenquan

2015-01-01

Porous structures of shales are reconstructed using the markov chain monte carlo (MCMC) method based on scanning electron microscopy (SEM) images of shale samples from Sichuan Basin, China. Characterization analysis of the reconstructed shales is performed, including porosity, pore size distribution, specific surface area and pore connectivity. The lattice Boltzmann method (LBM) is adopted to simulate fluid flow and Knudsen diffusion within the reconstructed shales. Simulation results reveal that the tortuosity of the shales is much higher than that commonly employed in the Bruggeman equation, and such high tortuosity leads to extremely low intrinsic permeability. Correction of the intrinsic permeability is performed based on the dusty gas model (DGM) by considering the contribution of Knudsen diffusion to the total flow flux, resulting in apparent permeability. The correction factor over a range of Knudsen number and pressure is estimated and compared with empirical correlations in the literature. For the wide pressure range investigated, the correction factor is always greater than 1, indicating Knudsen diffusion always plays a role on shale gas transport mechanisms in the reconstructed shales. Specifically, we found that most of the values of correction factor fall in the slip and transition regime, with no Darcy flow regime observed. PMID:25627247

Observations of the release of non-methane hydrocarbons from fractured shale.

PubMed

Sommariva, Roberto; Blake, Robert S; Cuss, Robert J; Cordell, Rebecca L; Harrington, Jon F; White, Iain R; Monks, Paul S

2014-01-01

The organic content of shale has become of commercial interest as a source of hydrocarbons, owing to the development of hydraulic fracturing ("fracking"). While the main focus is on the extraction of methane, shale also contains significant amounts of non-methane hydrocarbons (NMHCs). We describe the first real-time observations of the release of NMHCs from a fractured shale. Samples from the Bowland-Hodder formation (England) were analyzed under different conditions using mass spectrometry, with the objective of understanding the dynamic process of gas release upon fracturing of the shale. A wide range of NMHCs (alkanes, cycloalkanes, aromatics, and bicyclic hydrocarbons) are released at parts per million or parts per billion level with temperature- and humidity-dependent release rates, which can be rationalized in terms of the physicochemical characteristics of different hydrocarbon classes. Our results indicate that higher energy inputs (i.e., temperatures) significantly increase the amount of NMHCs released from shale, while humidity tends to suppress it; additionally, a large fraction of the gas is released within the first hour after the shale has been fractured. These findings suggest that other hydrocarbons of commercial interest may be extracted from shale and open the possibility to optimize the "fracking" process, improving gas yields and reducing environmental impacts.

77 FR 62253 - Agency Information Collection Activities: Comment Request

Federal Register 2010, 2011, 2012, 2013, 2014

2012-10-12

... digital geologic information related to coal, coalbed gas, shale gas and other energy resources and... assessments concerning coal and coal bed gas occurrences. Requesting external cooperation is the best way for... organic-rich shale, and obtain other information (including geophysical or seismic data, sample collection...

AFRRI (Armed Forces Radiobiology Research Institute) Annual Research Report 1 October 1980-30 September 1981.

DTIC Science & Technology

1981-09-30

weight of either petroleum-derived jet propulsion fuel number 5 (JP5) or one of three samples of shale-derived JP5 (1). The surviving rats were...sacrificed at 14 days after dosing. In another study, rats were gavaged with one of the four fuel samples at the rate of 24 mI/kg body weight and sacrificed...at 1, 2, or 3 days postdosing. A significant difference was seen in the lethality of the three shale-derived samples , even though all originated from

Arkansas River and Tributaries Arkansas and Oklahoma. Toad Suck Ferry Lock and Dam, Conway Water Supply Foundation Report.

DTIC Science & Technology

1983-06-01

NUMBER CORE BOXES NASH IS ELEV....ION GROUND WATER 6 DIRECTION OF HOLE 3-.. E VETa DATE OLE 5/30/78 5/31/ 7’ 1,7 UtmATJON o TOP 5 OLE / 7 THICKNESS OF...JUN 83 UNCLASSIFIED F/G 13/13 NL mommmmommm 0 I~lmlIIIImEE mhEgEBhEEBhIEE E Eg //EEE n-EEEElgEl- E .II 1.0 II1 l w20 1111.25 111111’.4 1II1.6 MICROCOPY...Kerr Arkansas River Navigation System. e dam was founded on a thick shale layer of the Atoka Formation. Locally, the shale was gray to black, hard to

Response of Velocity Anisotropy of Shale Under Isotropic and Anisotropic Stress Fields

NASA Astrophysics Data System (ADS)

Li, Xiaying; Lei, Xinglin; Li, Qi

2018-03-01

We investigated the responses of P-wave velocity and associated anisotropy in terms of Thomsen's parameters to isotropic and anisotropic stress fields on Longmaxi shales cored along different directions. An array of piezoelectric ceramic transducers allows us to measure P-wave velocities along numerous different propagation directions. Anisotropic parameters, including the P-wave velocity α along a symmetry axis, Thomsen's parameters ɛ and δ, and the orientation of the symmetry axis, could then be extracted by fitting Thomsen's weak anisotropy model to the experimental data. The results indicate that Longmaxi shale displays weakly intrinsic velocity anisotropy with Thomsen's parameters ɛ and δ being approximately 0.05 and 0.15, respectively. The isotropic stress field has only a slight effect on velocity and associated anisotropy in terms of Thomsen's parameters. In contrast, both the magnitude and orientation of the anisotropic stress field with respect to the shale fabric are important in controlling the evolution of velocity and associated anisotropy in a changing stress field. For shale with bedding-parallel loading, velocity anisotropy is enhanced because velocities with smaller angles relative to the maximum stress increase significantly during the entire loading process, whereas those with larger angles increase slightly before the yield stress and afterwards decrease with the increasing differential stress. For shale with bedding-normal loading, anisotropy reversal is observed, and the anisotropy is progressively modified by the applied differential stress. Before reaching the yield stress, velocities with smaller angles relative to the maximum stress increase more significantly and even exceed the level of those with larger angles. After reaching the yield stress, velocities with larger angles decrease more significantly. Microstructural features such as the closure and generation of microcracks can explain the modification of the velocity anisotropy due to the applied stress anisotropy.

Mechanical Characterization of Mancos Shale

NASA Astrophysics Data System (ADS)

Broome, S.; Ingraham, M. D.; Dewers, T. A.

2015-12-01

A series of tests on Mancos shale have been undertaken to determine the failure surface and to characterize anisotropy. This work supports additional studies which are being performed on the same block of shale; fracture toughness, permeability, and chemical analysis. Mechanical tests are being conducted after specimens were conditioned for at least two weeks at 70% constant relative humidity conditions. Specimens are tested under drained conditions, with the constant relative humidity condition maintained on the downstream side of the specimen. The upstream is sealed. Anisotropy is determined through testing specimens that have been cored parallel and perpendicular to the bedding plane. Preliminary results show that when loaded parallel to bedding the shale is roughly 50% weaker. Test are run under constant mean stress conditions when possible (excepting indirect tension, unconfined compression, and hydrostatic). Tests are run in hydrostatic compaction to the desired mean stress, then differential stress is applied axially in displacement control to failure. The constant mean stress condition is maintained by decreasing the confining pressure by half of the increase in the axial stress. Results will be compared to typical failure criteria to investigate the effectiveness of capturing the behavior of the shale with traditional failure theory. Sandia National Laboratories is a multi-program laboratory managed and operated by Sandia Corporation, a wholly owned subsidiary of Lockheed Martin Corporation, for the U.S. Department of Energy's National Nuclear Security Administration under contract DE-AC04-94AL85000. SAND2015-6107 A.

Microfluidic Investigation of Oil Mobilization in Shale Fracture Networks at Reservoir Conditions

NASA Astrophysics Data System (ADS)

Porter, M. L.; Jimenez-Martinez, J.; Carey, J. W.; Viswanathan, H. S.

2015-12-01

Investigations of pore-scale fluid flow and transport phenomena using engineered micromodels has steadily increased in recent years. In these investigations fluid flow is restricted to two-dimensions allowing for real time visualization and quantification of complex flow and reactive transport behavior, which is difficult to obtain in other experimental systems. One drawback to these studies is the use of engineered materials that do not faithfully represent the rock properties (e.g., porosity, wettability, roughness, etc.) encountered in subsurface formations. In this work, we describe a unique high pressure (up to 1500 psi) and temperature (up to 80 °C) microfluidics experimental system in which we investigate fluid flow and transport in geo-material (e.g., shale, Portland cement, etc.) micromodels. The use of geo-material micromodels allows us to better represent fluid-rock interactions including wettability, chemical reactivity, and nano-scale porosity at conditions representative of natural subsurface environments. Here, we present experimental results in fracture systems with applications to hydrocarbon mobility in hydraulically fractured shale. Complex fracture network patterns are derived from 3D x-ray tomography images of actual fractures created in shale rock cores. We use both shale and glass micromodels, allowing for a detailed comparison between flow phenomena in the different materials. We discuss results from two-phase huff-and-puff experiments involving N2 and n-Decane, as well as three-phase displacement experiments involving supercritical CO2, brine, and n-Decane.

Lithologic Controls on Critical Zone Processes in a Variably Metamorphosed Shale-Hosted Watershed

NASA Astrophysics Data System (ADS)

Eldam Pommer, R.; Navarre-Sitchler, A.

2017-12-01

Local and regional shifts in thermal maturity within sedimentary shale systems impart significant variation in chemical and physical rock properties, such as pore-network morphology, mineralogy, organic carbon content, and solute release potential. Even slight variations in these properties on a watershed scale can strongly impact surface and shallow subsurface processes that drive soil formation, landscape evolution, and bioavailability of nutrients. Our ability to map and quantify the effects of this heterogeneity on critical zone processes is hindered by the complex coupling of the multi-scale nature of rock properties, geochemical signatures, and hydrological processes. This study addresses each of these complexities by synthesizing chemical and physical characteristics of variably metamorphosed shales in order to link rock heterogeneity with modern earth surface and shallow subsurface processes. More than 80 samples of variably metamorphosed Mancos Shale were collected in the East River Valley, Colorado, a headwater catchment of the Upper Colorado River Basin. Chemical and physical analyses of the samples show that metamorphism decreases overall rock porosity, pore anisotropy, and surface area, and introduces unique chemical signatures. All of these changes result in lower overall solute release from the Mancos Shale in laboratory dissolution experiments and a change in rock-derived solute chemistry with decreasing organic carbon and cation exchange capacity (Ca, Na, Mg, and K). The increase in rock competency and decrease in reactivity of the more thermally mature shales appear to subsequently control river morphology, with lower channel sinuosity associated with areas of the catchment underlain by metamorphosed Mancos Shale. This work illustrates the formative role of the geologic template on critical zone processes and landscape development within and across watersheds.

Multicomponent seismic reservoir characterization of a steam-assisted gravity drainage (SAGD) heavy oil project, Athabasca oil sands, Alberta

NASA Astrophysics Data System (ADS)

Schiltz, Kelsey Kristine

Steam-assisted gravity drainage (SAGD) is an in situ heavy oil recovery method involving the injection of steam in horizontal wells. Time-lapse seismic analysis over a SAGD project in the Athabasca oil sands deposit of Alberta reveals that the SAGD steam chamber has not developed uniformly. Core data confirm the presence of low permeability shale bodies within the reservoir. These shales can act as barriers and baffles to steam and limit production by prohibiting steam from accessing the full extent of the reservoir. Seismic data can be used to identify these shale breaks prior to siting new SAGD well pairs in order to optimize field development. To identify shale breaks in the study area, three types of seismic inversion and a probabilistic neural network prediction were performed. The predictive value of each result was evaluated by comparing the position of interpreted shales with the boundaries of the steam chamber determined through time-lapse analysis. The P-impedance result from post-stack inversion did not contain enough detail to be able to predict the vertical boundaries of the steam chamber but did show some predictive value in a spatial sense. P-impedance from pre-stack inversion exhibited some meaningful correlations with the steam chamber but was misleading in many crucial areas, particularly the lower reservoir. Density estimated through the application of a probabilistic neural network (PNN) trained using both PP and PS attributes identified shales most accurately. The interpreted shales from this result exhibit a strong relationship with the boundaries of the steam chamber, leading to the conclusion that the PNN method can be used to make predictions about steam chamber growth. In this study, reservoir characterization incorporating multicomponent seismic data demonstrated a high predictive value and could be useful in evaluating future well placement.

A lithology identification method for continental shale oil reservoir based on BP neural network

NASA Astrophysics Data System (ADS)

Han, Luo; Fuqiang, Lai; Zheng, Dong; Weixu, Xia

2018-06-01

The Dongying Depression and Jiyang Depression of the Bohai Bay Basin consist of continental sedimentary facies with a variable sedimentary environment and the shale layer system has a variety of lithologies and strong heterogeneity. It is difficult to accurately identify the lithologies with traditional lithology identification methods. The back propagation (BP) neural network was used to predict the lithology of continental shale oil reservoirs. Based on the rock slice identification, x-ray diffraction bulk rock mineral analysis, scanning electron microscope analysis, and the data of well logging and logging, the lithology was divided with carbonate, clay and felsic as end-member minerals. According to the core-electrical relationship, the frequency histogram was then used to calculate the logging response range of each lithology. The lithology-sensitive curves selected from 23 logging curves (GR, AC, CNL, DEN, etc) were chosen as the input variables. Finally, the BP neural network training model was established to predict the lithology. The lithology in the study area can be divided into four types: mudstone, lime mudstone, lime oil-mudstone, and lime argillaceous oil-shale. The logging responses of lithology were complicated and characterized by the low values of four indicators and medium values of two indicators. By comparing the number of hidden nodes and the number of training times, we found that the number of 15 hidden nodes and 1000 times of training yielded the best training results. The optimal neural network training model was established based on the above results. The lithology prediction results of BP neural network of well XX-1 showed that the accuracy rate was over 80%, indicating that the method was suitable for lithology identification of continental shale stratigraphy. The study provided the basis for the reservoir quality and oily evaluation of continental shale reservoirs and was of great significance to shale oil and gas exploration.

Geophysical evaluation of sandstone aquifers in the Reconcavo-Tucano Basin, Bahia -- Brazil

DOE Office of Scientific and Technical Information (OSTI.GOV)

Lima, O.A.L. de

1993-11-01

The upper clastic sediments in the Reconcavo-Tucano basin comprise a multilayer aquifer system of Jurassic age. Its groundwater is normally fresh down to depths of more than 1,000 m. Locally, however, there are zones producing high salinity or sulfur geothermal water. Analysis of electrical logs of more than 150 wells enabled the identification of the most typical sedimentary structures and the gross geometries for the sandstone units in selected areas of the basin. Based on this information, the thick sands are interpreted as coalescent point bars and the shales as flood plain deposits of a large fluvial environment. The resistivitymore » logs and core laboratory data are combined to develop empirical equations relating aquifer porosity and permeability to log-derived parameters such as formation factor and cementation exponent. Temperature logs of 15 wells were useful to quantify the water leakage through semiconfining shales. The groundwater quality was inferred from spontaneous potential (SP) log deflections under control of chemical analysis of water samples. An empirical chart is developed that relates the SP-derived water resistivity to the true water resistivity within the formations. The patterns of salinity variation with depth inferred from SP logs were helpful in identifying subsurface flows along major fault zones, where extensive mixing of water is taking place. A total of 49 vertical Schlumberger resistivity soundings aid in defining aquifer structures and in extrapolating the log derived results. Transition zones between fresh and saline waters have also been detected based on a combination of logging and surface sounding data. Ionic filtering by water leakage across regional shales, local convection and mixing along major faults and hydrodynamic dispersion away from lateral permeability contrasts are the main mechanisms controlling the observed distributions of salinity and temperature within the basin.« less

Petrographic and reservoir features of Hauterivian (Lower Cretaceous) Shatlyk horizon in the Malay gas field, Amu-Darya basin, east Turkmenia

DOE Office of Scientific and Technical Information (OSTI.GOV)

Naz, H.; Ersan, A.

1996-08-01

Malay gas field in Amu-Darya basin, eastern Turkmenia, is located on the structural high that is on the Malay-Bagadzha arch north of the Repetek-Kelif structure zone. With 500 km{sup 2} areal coverage, 16 producing wells and 200 billion m{sup 3} estimated reserves, the field was discovered in 1978 and production began in 1987 from 2400-m-deep Hauterivian-age (Early Cretaceous) Shatlyk horizon. The Shatlyk elastic sequence shows various thickness up to 100 m in the Malay structural closure and is studied through E-log, core, petrographic data and reservoir characteristics. The Shatlyk consists of poorly indurated, reddish-brown and gray sandstones, and sandy graymore » shales. The overall sand-shale ratio increases up and the shales interleave between the sand packages. The reservoir sandstones are very fine to medium grained, moderately sorted, compositionally immature, subarkosic arenites. The framework grains include quartz, feldspar and volcanic lithic fragments. Quartz grains are monocrystalline in type and most are volcanic in origin. Feldspars consist of K- Feldspar and plagioclase. The orthoclases are affected by preferential alteration. The sandstones show high primary intergranular porosity and variations in permeability. Patch-like evaporate cement and the iron-rich grain coatings are reducing effects in permeability. The coats are pervasive in reddish-brown sandstones but are not observed in the gray sandstones. The evaporate cement is present in all the sandstone samples examined and, in places, follows the oxidation coats. The petrographic evidences and the regional facies studies suggest the deposition in intersection area from continental to marine nearshore deltaic environment.« less

Mixed biogenic and hydrothermal quartz in Permian lacustrine shale of Santanghu Basin, NW China: implications for penecontemporaneous transformation of silica minerals

NASA Astrophysics Data System (ADS)

Jiao, Xin; Liu, Yiqun; Yang, Wan; Zhou, Dingwu; Wang, Shuangshuang; Jin, Mengqi; Sun, Bin; Fan, Tingting

2018-01-01

The cycling of various isomorphs of authigenic silica minerals is a complex and long-term process. A special type of composite quartz (Qc) grains in tuffaceous shale of Permian Lucaogou Formation in the sediment-starved volcanically and hydrothermally active intracontinental lacustrine Santanghu rift basin (NW China) is studied in detail to demonstrate such processes. Samples from one well in the central basin were subject to petrographic, elemental chemical, and fluid inclusion analyses. About 200 Qc-bearing laminae are 0.1-2 mm and mainly 1 mm thick and intercalated within tuffaceous shale laminae. The Qc grains occur as framework grains and are dispersed in igneous feldspar-dominated matrix, suggesting episodic accumulation. The Qc grains are bedding-parallel, uniform in size (100 s µm), elongate, and radial in crystal pattern, suggesting a biogenic origin. Qc grains are composed of a core of anhedral microcrystalline quartz and an outer part of subhedral mega-quartz grains, whose edges are composed of small euhedral quartz crystals, indicating multiple episodic processes of recrystallization and overgrowth. Abundance of Al and Ti in quartz crystals and estimated temperature from fluid inclusions in Qc grains indicate that processes are related to hydrothermal fluids. Finally, the Qc grains are interpreted as original silica precipitation in microorganism (algae?) cysts, which were reworked by bottom currents and altered by hydrothermal fluids to recrystalize and overgrow during penecontemporaneous shallow burial. It is postulated that episodic volcanic and hydrothermal activities had changed lake water chemistry, temperature, and nutrient supply, resulting in variations in microorganic productivities and silica cycling. The transformation of authigenic silica from amorphous to well crystallized had occurred in a short time span during shallow burial.

Laboratory characterization of shale pores

NASA Astrophysics Data System (ADS)

Nur Listiyowati, Lina

2018-02-01

To estimate the potential of shale gas reservoir, one needs to understand the characteristics of pore structures. Characterization of shale gas reservoir microstructure is still a challenge due to ultra-fine grained micro-fabric and micro level heterogeneity of these sedimentary rocks. The sample used in the analysis is a small portion of any reservoir. Thus, each measurement technique has a different result. It raises the question which methods are suitable for characterizing pore shale. The goal of this paper is to summarize some of the microstructure analysis tools of shale rock to get near-real results. The two analyzing pore structure methods are indirect measurement (MIP, He, NMR, LTNA) and direct observation (SEM, TEM, Xray CT). Shale rocks have a high heterogeneity; thus, it needs multiscale quantification techniques to understand their pore structures. To describe the complex pore system of shale, several measurement techniques are needed to characterize the surface area and pore size distribution (LTNA, MIP), shapes, size and distribution of pore (FIB-SEM, TEM, Xray CT), and total porosity (He pycnometer, NMR). The choice of techniques and methods should take into account the purpose of the analysis and also the time and budget.

Experimental investigations of the wettability of clays and shales

NASA Astrophysics Data System (ADS)

Borysenko, Artem; Clennell, Ben; Sedev, Rossen; Burgar, Iko; Ralston, John; Raven, Mark; Dewhurst, David; Liu, Keyu

2009-07-01

Wettability in argillaceous materials is poorly understood, yet it is critical to hydrocarbon recovery in clay-rich reservoirs and capillary seal capacity in both caprocks and fault gouges. The hydrophobic or hydrophilic nature of clay-bearing soils and sediments also controls to a large degree the movement of spilled nonaqueous phase liquids in the subsurface and the options available for remediation of these pollutants. In this paper the wettability of hydrocarbons contacting shales in their natural state and the tendencies for wettability alteration were examined. Water-wet, oil-wet, and mixed-wet shales from wells in Australia were investigated and were compared with simplified model shales (single and mixed minerals) artificially treated in crude oil. The intact natural shale samples (preserved with their original water content) were characterized petrophysically by dielectric spectroscopy and nuclear magnetic resonance, plus scanning electron, optical and fluorescence microscopy. Wettability alteration was studied using spontaneous imbibition, pigment extraction, and the sessile drop method for contact angle measurement. The mineralogy and chemical compositions of the shales were determined by standard methods. By studying pure minerals and natural shales in parallel, a correlation between the petrophysical properties, and wetting behavior was observed. These correlations may potentially be used to assess wettability in downhole measurements.

Application of PAH concentration profiles in lake sediments as indicators for smelting activity.

PubMed

Warner, Wiebke; Ruppert, Hans; Licha, Tobias

2016-09-01

The ability of lake sediment cores to store long-term anthropogenic pollution establishes them as natural archives. In this study, we focus on the influence of copper shale mining and smelting in the Mansfeld area of Germany, using the depth profiles of two sediment cores from Lake Süßer See. The sediment cores provide a detailed chronological deposition history of polycyclic aromatic hydrocarbons (PAHs) and heavy metals in the studied area. Theisen sludge, a fine-grained residue from copper shale smelting, reaches the lake via deflation by wind or through riverine input; it is assumed to be the main source of pollution. To achieve the comparability of absolute contaminant concentrations, we calculated the influx of contaminants based on the sedimentation rate. Compared to the natural background concentrations, PAHs are significantly more enriched than heavy metals. They are therefore more sensitive and selective for source apportionment. We suggest two diagnostic ratios of PAHs to distinguish between Theisen sludge and its leachate: the ratio fluoranthene to pyrene ~2 and the ratio of PAH with logKOW<5.7 to PAH with a logKOW>5.7 converging to an even lower value than 2.3 (the characteristic of Theisen sludge) to identify the particulate input in lake environments. Copyright © 2016 Elsevier B.V. All rights reserved.

Ultraviolet laser-induced lateral photovoltaic response in anisotropic black shale

NASA Astrophysics Data System (ADS)

Miao, Xinyang; Zhu, Jing; Zhao, Kun; Yue, Wenzheng

2017-12-01

The anisotropy of shale has significant impact on oil and gas exploration and engineering. In this paper, a-248 nm ultraviolet laser was employed to assess the anisotropic lateral photovoltaic (LPV) response of shale. Anisotropic angle-depending voltage signals were observed with different peak amplitudes ( V p) and decay times. We employed exponential models to explain the charge carrier transport in horizontal and vertical directions. Dependences of the laser-induced LPV on the laser spot position were observed. Owing to the Dember effect and the layered structure of shale, V p shows an approximately linear dependence with the laser-irradiated position for the 0° shale sample but nonlinearity for the 45° and 90° ones. The results demonstrate that the laser-induced voltage method is very sensitive to the structure of materials, and thus has a great potential in oil and gas reservoir characterization.

VEGETATIVE REHABILITATION OF ARID LAND DISTURBED IN THE DEVELOPMENT OF OIL SHALE AND COAL

EPA Science Inventory

Field experiments were established on sites disturbed by exploratory drilling in the oil shale region of northeastern Utah and on disturbed sites on a potential coal mine in south central Utah. Concurrently, greenhouse studies were carried out using soil samples from disturbed si...

Modeling of gas generation from the Barnett Shale, Fort Worth Basin, Texas

USGS Publications Warehouse

Hill, R.J.; Zhang, E.; Katz, B.J.; Tang, Y.

2007-01-01

The generative gas potential of the Mississippian Barnett Shale in the Fort Worth Basin, Texas, was quantitatively evaluated by sealed gold-tube pyrolysis. Kinetic parameters for gas generation and vitrinite reflectance (Ro) changes were calculated from pyrolysis data and the results used to estimate the amount of gas generated from the Barnett Shale at geologic heating rates. Using derived kinetics for Ro evolution and gas generation, quantities of hydrocarbon gas generated at Ro ??? 1.1% are about 230 L/t (7.4 scf/t) and increase to more that 5800 L/t (186 scf/t) at Ro ??? 2.0% for a sample with an initial total organic carbon content of 5.5% and Ro = 0.44%. The volume of shale gas generated will depend on the organic richness, thickness, and thermal maturity of the shale and also the amount of petroleum that is retained in the shale during migration. Gas that is reservoired in shales appears to be generated from the cracking of kerogen and petroleum that is retained in shales, and that cracking of the retained petroleum starts by Ro ??? 1.1%. This result suggests that the cracking of petroleum retained in source rocks occurs at rates that are faster than what is predicted for conventional siliciclastic and carbonate reservoirs, and that contact of retained petroleum with kerogen and shale mineralogy may be a critical factor in shale-gas generation. Shale-gas systems, together with overburden, can be considered complete petroleum systems, although the processes of petroleum migration, accumulation, and trap formation are different from what is defined for conventional petroleum systems. Copyright ?? 2007. The American Association of Petroleum Geologists. All rights reserved.

4D synchrotron X-ray imaging to understand porosity development in shales during exposure to hydraulic fracturing fluid

NASA Astrophysics Data System (ADS)

Kiss, A. M.; Bargar, J.; Kohli, A. H.; Harrison, A. L.; Jew, A. D.; Lim, J. H.; Liu, Y.; Maher, K.; Zoback, M. D.; Brown, G. E.

2016-12-01

Unconventional (shale) reservoirs have emerged as the most important source of petroleum resources in the United States and represent a two-fold decrease in greenhouse gas emissions compared to coal. Despite recent progress, hydraulic fracturing operations present substantial technical, economic, and environmental challenges, including inefficient recovery, wastewater production and disposal, contaminant and greenhouse gas pollution, and induced seismicity. A relatively unexplored facet of hydraulic fracturing operations is the fluid-rock interface, where hydraulic fracturing fluid (HFF) contacts shale along faults and fractures. Widely used, water-based fracturing fluids contain oxidants and acid, which react strongly with shale minerals. Consequently, fluid injection and soaking induces a host of fluid-rock interactions, most notably the dissolution of carbonates and sulfides, producing enhanced or "secondary" porosity networks, as well as mineral precipitation. The competition between these mechanisms determines how HFF affects reactive surface area and permeability of the shale matrix. The resultant microstructural and chemical changes may also create capillary barriers that can trap hydrocarbons and water. A mechanistic understanding of the microstructure and chemistry of the shale-HFF interface is needed to design new methodologies and fracturing fluids. Shales were imaged using synchrotron micro-X-ray computed tomography before, during, and after exposure to HFF to characterize changes to the initial 3D structure. CT reconstructions reveal how the secondary porosity networks advance into the shale matrix. Shale samples span a range of lithologies from siliceous to calcareous to organic-rich. By testing shales of different lithologies, we have obtained insights into the mineralogic controls on secondary pore network development and the morphologies at the shale-HFF interface and the ultimate composition of produced water from different facies. These results show that mineral texture is a major control over secondary porosity network morphology.

Fundamental Study of Disposition and Release of Methane in a Shale Gas Reservoir

DOE Office of Scientific and Technical Information (OSTI.GOV)

Wang, Yifeng; Xiong, Yongliang; Criscenti, Louise J.

The recent boom in shale gas production through hydrofracturing has reshaped the energy production landscape in the United States. Wellbore production rates vary greatly among the wells within a single field and decline rapidly with time, thus bring up a serious concern with the sustainability of shale gas production. Shale gas production starts with creating a fracture network by injecting a pressurized fluid in a wellbore. The induced fractures are then held open by proppant particles. During production, gas releases from the mudstone matrix, migrates to nearby fractures, and ultimately reaches a production wellbore. Given the relatively high permeability ofmore » the induced fractures, gas release and migration in low-permeability shale matrix is likely to be a limiting step for long-term wellbore production. Therefore, a clear understanding of the underlying mechanisms of methane disposition and release in shale matrix is crucial for the development of new technologies to maximize gas production and recovery. Shale is a natural nanocomposite material with distinct characteristics of nanometer-scale pore sizes, extremely low permeability, high clay contents, significant amounts of organic carbon, and large spatial heterogeneities. Our work has shown that nanopore confinement plays an important role in methane disposition and release in shale matrix. Using molecular simulations, we show that methane release in nanoporous kerogen matrix is characterized by fast release of pressurized free gas (accounting for ~ 30 - 47% recovery) followed by slow release of adsorbed gas as the gas pressure decreases. The first stage is driven by the gas pressure gradient while the second stage is controlled by gas desorption and diffusion. The long-term production decline appears controlled by the second stage of gas release. We further show that diffusion of all methane in nanoporous kerogen behaves differently from the bulk phase, with much smaller diffusion coefficients. The MD simulations also indicate that a significant fraction (3 - 35%) of methane deposited in kerogen can potentially become trapped in isolated nanopores and thus not recoverable. We have successfully established experimental capabilities for measuring gas sorption and desorption on shale and model materials under a wide range of physical and chemical conditions. Both low and high pressure measurements show significant sorption of CH 4 and CO 2 onto clays, implying that methane adsorbed on clay minerals could contribute a significant portion of gas-in-place in an unconventional reservoir. We have also studied the potential impact of the interaction of shale with hydrofracking fluid on gas sorption. We have found that the CH 4-CO 2 sorption capacity for the reacted sample is systematically lower (by a factor of ~2) than that for the unreacted (raw) sample. This difference in sorption capacity may result from a mineralogical or surface chemistry change of the shale sample induced by fluid-rock interaction. Our results shed a new light on mechanistic understanding gas release and production decline in unconventional reservoirs.« less

Oxygen isotope perspective on crustal evolution on early Earth: A record of Precambrian shales with emphasis on Paleoproterozoic glaciations and Great Oxygenation Event

NASA Astrophysics Data System (ADS)

Bindeman, I. N.; Bekker, A.; Zakharov, D. O.

2016-03-01

We present stable isotope and chemical data for 206 Precambrian bulk shale and tillite samples that were collected mostly from drillholes on all continents and span the age range from 0.5 to 3.5 Ga with a dense coverage for 2.5-2.2 Ga time interval when Earth experienced four Snowball Earth glaciations and the irreversible rise in atmospheric O2. We observe significant, downward shift of several ‰ and a smaller range of δ18 O values (7 to 9‰) in shales that are associated with the Paleoproterozoic and, potentially, Neoproterozoic glaciations. The Paleoproterozoic samples consist of more than 50% mica minerals and have equal or higher chemical index of alteration than overlying and underlying formations and thus underwent equal or greater degrees of chemical weathering. Their pervasively low δ18 O and δD (down to - 85 ‰) values provide strong evidence of alteration and diagenesis in contact with ultra-low δ18 O glacial meltwaters in lacustrine, deltaic or periglacial lake (sikussak-type) environments associated with the Paleoproterozoic glaciations. The δDsilicate values for the rest of Precambrian shales range from -75 to - 50 ‰ and are comparable to those for Phanerozoic and Archean shales. Likewise, these samples have similar ranges in δ13Corg values (-23 to - 33 ‰ PDB) and Corg content (0.0 to 10 wt%) to Phanerozoic shales. Precambrian shales have a large range of δ18 O values comparable to that of the Phanerozoic shales in each age group and formation, suggesting similar variability in the provenance and intensity of chemical weathering, except for the earliest 3.3-3.5 Ga Archean shales, which have consistently lower δ18 O values. Moreover, Paleoproterozoic shales that bracket in age the Great Oxidation Event (GOE) overlap in δ18 O values. Absence of a step-wise increase in δ18 O and δD values suggests that despite the first-order change in the composition of the atmosphere, weathering cycle was not dramatically affected by the GOE at ∼2.4-2.3 Ga. Shales do not show comparable δ18 O rise in the early Phanerozoic as is observed in the coeval δ18 O trends for cherts and carbonates. There is however a sharp increase in the average δ18 O value from the Early Archean to the Late Archean followed by a progressively decelerating increase into the Phanerozoic. This decelerating increase with time likely reflects declining contribution of mantle-extracted, normal-δ18 O crust and lends support to crustal maturation and increasing 18O sequestration into the crust and recycling of high-δ18 O (and 87Sr/86Sr) sedimentary rocks. This secular increase in the δ18 O composition of the continental crust could have also had a mild effect on seawater δ18 O composition.

Petroleum source rock evaluation of the Alum and Dictyonema Shales (Upper Cambrian-Lower Ordovician) in the Baltic Basin and Podlasie Depression (eastern Poland)

NASA Astrophysics Data System (ADS)

Kosakowski, Paweł; Kotarba, Maciej J.; Piestrzyński, Adam; Shogenova, Alla; Więcław, Dariusz

2017-03-01

We present geochemical characteristics of the Lower Palaeozoic shales deposited in the Baltic Basin and Podlasie Depression. In the study area, this strata are represented by the Upper Cambrian-Lower Ordovician Alum Shale recognized in southern Scandinavia and Polish offshore and a equivalent the Lower Tremadocian Dictyonema Shale from the northern Estonia and the Podlasie Depression in Poland. Geochemical analyses reveal that the Alum Shale and Dictyonema Shale present high contents of organic carbon. These deposits have the best source quality among the Lower Palaeozoic strata, and they are the best source rocks in the Baltic region. The bituminous shales complex has TOC contents up to ca. 22 wt%. The analysed rocks contain low-sulphur, oil-prone Type-II kerogen deposited in anoxic or sub-oxic conditions. The maturity of the Alum and Dictyonema Shales changes gradually, from the east and north-east to the west and south-west, i.e. in the direction of the Tornquist-Teisseyre Zone. Samples, located in the seashore of Estonia and in the Podlasie region, are immature and in the initial phase of "oil window". The mature shales were found in the central offshore part of the Polish Baltic Basin, and the late mature and overmature are located in the western part of the Baltic Basin. The Alum and Dictyonema Shales are characterized by a high grade of radioactive elements, especially uranium. The enrichment has a syngenetic or early diagenetic origin. The measured content of uranium reached up to 750 ppm and thorium up to 37 ppm.

Mobile measurement of methane and hydrogen sulfide at natural gas production site fence lines in the Texas Barnett Shale.

PubMed

Eapi, Gautam R; Sabnis, Madhu S; Sattler, Melanie L

2014-08-01

Production of natural gas from shale formations is bringing drilling and production operations to regions of the United States that have seen little or no similar activity in the past, which has generated considerable interest in potential environmental impacts. This study focused on the Barnett Shale Fort Worth Basin in Texas, which saw the number of gas-producing wells grow from 726 in 2001 to 15,870 in 2011. This study aimed to measure fence line concentrations of methane and hydrogen sulfide at natural gas production sites (wells, liquid storage tanks, and associated equipment) in the four core counties of the Barnett Shale (Denton, Johnson, Tarrant, and Wise). A mobile measurement survey was conducted in the vicinity of 4788 wells near 401 lease sites, representing 35% of gas production volume, 31% of wells, and 38% of condensate production volume in the four-county core area. Methane and hydrogen sulfide concentrations were measured using a Picarro G2204 cavity ring-down spectrometer (CRDS). Since the research team did not have access to lease site interiors, measurements were made by driving on roads on the exterior of the lease sites. Over 150 hr of data were collected from March to July 2012. During two sets of drive-by measurements, it was found that 66 sites (16.5%) had methane concentrations > 3 parts per million (ppm) just beyond the fence line. Thirty-two lease sites (8.0%) had hydrogen sulfide concentrations > 4.7 parts per billion (ppb) (odor recognition threshold) just beyond the fence line. Measured concentrations generally did not correlate well with site characteristics (natural gas production volume, number of wells, or condensate production). t tests showed that for two counties, methane concentrations for dry sites were higher than those for wet sites. Follow-up study is recommended to provide more information at sites identified with high levels of methane and hydrogen sulfide. Implications: Information regarding air emissions from shale gas production is important given the recent increase in number of wells in various regions in the United States. Methane, the primary natural gas constituent, is a greenhouse gas; hydrogen sulfide, which can be present in gas condensate, is an odor-causing compound. This study surveyed wells representing one-third of the natural gas production volume in the Texas Barnett Shale and identified the percent of sites that warrant further study due to their fence line methane and hydrogen sulfide concentrations.

Shale gas characteristics of the Lower Toarcian Posidonia Shale in Germany: from basin to nanometre scale

NASA Astrophysics Data System (ADS)

Schulz, Hans-Martin; Bernard, Sylvain; Horsfield, Brian; Krüger, Martin; Littke, Ralf; di primio, Rolando

2013-04-01

The Early Toarcian Posidonia Shale is a proven hydrocarbon source rock which was deposited in a shallow epicontinental basin. In southern Germany, Tethyan warm-water influences from the south led to carbonate sedimentation, whereas cold-water influxes from the north controlled siliciclastic sedimentation in the northwestern parts of Germany and the Netherlands. Restricted sea-floor circulation and organic matter preservation are considered to be the consequence of an oceanic anoxic event. In contrast, non-marine conditions led to sedimentation of coarser grained sediments under progressively terrestrial conditions in northeastern Germany The present-day distribution of Posidonia Shale in northern Germany is restricted to the centres of rift basins that formed in the Late Jurassic (e.g., Lower Saxony Basin and Dogger Troughs like the West and East Holstein Troughs) as a result of erosion on the basin margins and bounding highs. The source rock characteristics are in part dependent on grain size as the Posidonia Shale in eastern Germany is referred to as a mixed to non-source rock facies. In the study area, the TOC content and the organic matter quality vary vertically and laterally, likely as a consequence of a rising sea level during the Toarcian. Here we present and compare data of whole Posidonia Shale sections, investigating these variations and highlighting the variability of Posidonia Shale depositional system. During all phases of burial, gas was generated in the Posidonia Shale. Low sedimentation rates led to diffusion of early diagenetically formed biogenic methane. Isochronously formed diagenetic carbonates tightened the matrix and increased brittleness. Thermogenic gas generation occurred in wide areas of Lower Saxony as well as in Schleswig Holstein. Biogenic methane gas can still be formed today in Posidonia Shale at shallow depth in areas which were covered by Pleistocene glaciers. Submicrometric interparticle pores predominate in immature samples. At thermal maturities beyond the oil window, intra-mineral and intra-organic pores develop. In such overmature samples, nanopores occur within pyrobitumen masses. Important for gas storage and transport, they likely result from exsolution of gaseous hydrocarbon. References Bernard S., Wirth R., Schreiber A., Bowen L., Aplin A.C., Mathia E.J., Schulz H-M., & Horsfield B.: FIB-SEM and TEM investigations of an organic-rich shale maturation series (Lower Toarcian Posidonia Shale): Nanoscale pore system and fluid-rock interactions. AAPG Bulletin Special Issue "Electron Microscopy of Shale Hydrocarbon Reservoirs" (in press). Bernard, S., Horsfield, B., Schulz, H-M., Wirth, R., Schreiber, A., & Sherwood, N., 2012, Geochemical evolution of organic-rich shales with increasing maturity: A STXM and TEM study of the Posidonia Shale (Lower Toarcian, northern Germany): Marine and Petroleum Geology 31 (1) 70-89. Lott, G.K., Wong, T.E., Dusar, M., Andsbjerg, J., Mönnig, E., Feldman-Olszewska, A. & Verreussel, R.M.C.H., 2010. Jurassic. In: Doornenbal, J.C. and Stevenson, A.G. (editors): Petroleum Geological Atlas of the Southern Permian Basin Area. EAGE Publications b.v. (Houten): 175-193.

Understanding hydraulic fracturing: a multi-scale problem.

PubMed

Hyman, J D; Jiménez-Martínez, J; Viswanathan, H S; Carey, J W; Porter, M L; Rougier, E; Karra, S; Kang, Q; Frash, L; Chen, L; Lei, Z; O'Malley, D; Makedonska, N

2016-10-13

Despite the impact that hydraulic fracturing has had on the energy sector, the physical mechanisms that control its efficiency and environmental impacts remain poorly understood in part because the length scales involved range from nanometres to kilometres. We characterize flow and transport in shale formations across and between these scales using integrated computational, theoretical and experimental efforts/methods. At the field scale, we use discrete fracture network modelling to simulate production of a hydraulically fractured well from a fracture network that is based on the site characterization of a shale gas reservoir. At the core scale, we use triaxial fracture experiments and a finite-discrete element model to study dynamic fracture/crack propagation in low permeability shale. We use lattice Boltzmann pore-scale simulations and microfluidic experiments in both synthetic and shale rock micromodels to study pore-scale flow and transport phenomena, including multi-phase flow and fluids mixing. A mechanistic description and integration of these multiple scales is required for accurate predictions of production and the eventual optimization of hydrocarbon extraction from unconventional reservoirs. Finally, we discuss the potential of CO2 as an alternative working fluid, both in fracturing and re-stimulating activities, beyond its environmental advantages.This article is part of the themed issue 'Energy and the subsurface'. © 2016 The Author(s).

Understanding hydraulic fracturing: a multi-scale problem

PubMed Central

Hyman, J. D.; Jiménez-Martínez, J.; Viswanathan, H. S.; Carey, J. W.; Porter, M. L.; Rougier, E.; Karra, S.; Kang, Q.; Frash, L.; Chen, L.; Lei, Z.; O’Malley, D.; Makedonska, N.

2016-01-01

Despite the impact that hydraulic fracturing has had on the energy sector, the physical mechanisms that control its efficiency and environmental impacts remain poorly understood in part because the length scales involved range from nanometres to kilometres. We characterize flow and transport in shale formations across and between these scales using integrated computational, theoretical and experimental efforts/methods. At the field scale, we use discrete fracture network modelling to simulate production of a hydraulically fractured well from a fracture network that is based on the site characterization of a shale gas reservoir. At the core scale, we use triaxial fracture experiments and a finite-discrete element model to study dynamic fracture/crack propagation in low permeability shale. We use lattice Boltzmann pore-scale simulations and microfluidic experiments in both synthetic and shale rock micromodels to study pore-scale flow and transport phenomena, including multi-phase flow and fluids mixing. A mechanistic description and integration of these multiple scales is required for accurate predictions of production and the eventual optimization of hydrocarbon extraction from unconventional reservoirs. Finally, we discuss the potential of CO2 as an alternative working fluid, both in fracturing and re-stimulating activities, beyond its environmental advantages. This article is part of the themed issue ‘Energy and the subsurface’. PMID:27597789

Lightweight aggregate production from claystone and shale in Bangladesh

USGS Publications Warehouse

Parker, Norbert A.; Khan, M.A.

1976-01-01

Muffle furnace tests were made on samples of clay, claystone, and shale collected in the Chittagong and Dacca areas of East Pakistan to determine their amenability to bloating for the commercial production of light-weight aggregate. Several areas, sampled in some detail, were selected for investigation because of their proximity to market, and accessibility to fuel and electricity. Muffle furnace tests show that the clay, claystone, and shale are natural bloaters at temperatures in the 1700? to 2200? F range, and do not require additives. The most desirable deposit, insofar as producing a strong aggregate is concerned, can be determined only by pilot-kiln testing and by crushing-strength tests made on concrete test cylinders. Reserves of suitable raw material are large in both the Chittagong and Dacca areas.

Distribution of Hydroxyl Groups in Kukersite Shale Oil: Quantitative Determination Using Fourier Transform Infrared (FT-IR) Spectroscopy.

PubMed

Baird, Zachariah Steven; Oja, Vahur; Järvik, Oliver

2015-05-01

This article describes the use of Fourier transform infrared (FT-IR) spectroscopy to quantitatively measure the hydroxyl concentrations among narrow boiling shale oil cuts. Shale oil samples were from an industrial solid heat carrier retort. Reference values were measured by titration and were used to create a partial least squares regression model from FT-IR data. The model had a root mean squared error (RMSE) of 0.44 wt% OH. This method was then used to study the distribution of hydroxyl groups among more than 100 shale oil cuts, which showed that hydroxyl content increased with the average boiling point of the cut up to about 350 °C and then leveled off and decreased.

Paper 5991: How Much Gas, Condensate, and Oil Will be Produced from Major Shale Plays in the U.S., and Why?

NASA Astrophysics Data System (ADS)

Marder, M. P.; Patzek, T. W.

2014-12-01

A one-dimensional universal model of gas inflow into the hydrofractured horizontal wells (Patzek, et al., PNAS, 110, 2013) was developed for the Barnett shale, and applied to explain historical production and predict future production in 8294 wells there. Subsequently, this model was extended and applied to 3756 wells in the Fayetteville shale, 2199 wells in the Haynesville shale, and 2764 wells in the Marcellus shale. Out of these, 2057, 703, 1515, and 1063 wells in the Barnett, Fayetteville, Haynesville, and Marcellus, respectively, show evidence of pressure interference between consecutive hydrofractures. For the interfering wells, we calculate their EURs and the distributions of effective gas permeability in the reservoir volumes influenced by these wells. For the non-interfering wells we calculate the lower and upper bounds on their EURs. We show that given the available data, a better field-wide prediction of EUR is impossible. The expected EURs vary between 0.4 and 4.3 Bscf in the Barnett, depending on the well quality. In the other shales the expected well EURs are 0.5 - 3.4 Bcf in the Fayetteville, 1.4 - 7.9 Bcf in the Haynesville, and 1 - 9 Bcf in the Marcellus. The respective mean effective gas permeabilities are 400, 1000, 230, and 800 nanodarcy for the same shales, much high than the core values. Work on the Eagle Ford shale is in progress and will be presented in December. In a shale- horizontal well system, we model rectilinear flow of natural gas as dimensionless nonlinear pseudo-pressure diffusion IVBP with gas sorption on the rock and the multiple planar hydrofractures acting as internal sorbing boundaries. After the initial choked flow, wells must decline as the inverse of the square root of time on production, until the gas pressure starts declining at the midplane of a reservoir cell between two consecutive hydrofractures. At this point of time production decline is exponential. The transition between the square-root-of-time and exponential decline is governed by the characteristic pressure diffusion time, τ, and gas mass in place, M. The dimensionless solution of this IVBP problem reduces the cumulative gas production in all wells to a single universal curve for each play. The ultimate recovery is about 15% of gas-in-place and less so for oil.

Research on Utilization of Geo-Energy

NASA Astrophysics Data System (ADS)

Bock, Michaela; Scheck-Wenderoth, Magdalena; GeoEn Working Group

2013-04-01

The world's energy demand will increase year by year and we have to search for alternative energy resources. New concepts concerning the energy production from geo-resources have to be provided and developed. The joint project GeoEn combines research on the four core themes geothermal energy, shale gas, CO2 capture and CO2 storage. Sustainable energy production from deep geothermal energy resources is addressed including all processes related to geothermal technologies, from reservoir exploitation to energy conversion in the power plant. The research on the unconventional natural gas resource, shale gas, is focussed on the sedimentological, diagenetic and compositional characteristics of gas shales. Technologies and solutions for the prevention of the greenhouse gas carbon dioxide are developed in the research fields CO2 capture technologies, utilization, transport, and CO2 storage. Those four core themes are studied with an integrated approach using the synergy of cross-cutting methodologies. New exploration and reservoir technologies and innovative monitoring methods, e.g. CSMT (controlled-source magnetotellurics) are examined and developed. All disciplines are complemented by numerical simulations of the relevant processes. A particular strength of the project is the availability of large experimental infrastructures where the respective technologies are tested and monitored. These include the power plant Schwarze Pumpe, where the Oxyfuel process is improved, the pilot storage site for CO2 in Ketzin and the geothermal research platform Groß Schönebeck, with two deep wells and an experimental plant overground for research on corrosion. In addition to fundamental research, the acceptance of new technologies, especially in the field of CCS is examined. Another focus addressed is the impact of shale gas production on the environment. A further important goal is the education of young scientists in the new field "geo-energy" to fight skills shortage in this field of growing economic and ecologic relevance.

Organic petrology of selected oil shale samples from lower Carboniferous Albert Formation, New Brunswick, Canada

DOE Office of Scientific and Technical Information (OSTI.GOV)

Kalkreuth, W.; Macauley, G.

1984-04-01

Incident light microscopy was used to describe maturation and composition of organic material in oil shale samples from the Lower Carboniferous Albert Formation of New Brunswick. The maturation level was determined in normal (white) light by measuring vitrinite reflectance and in fluorescent light by measuring fluorescence spectral of alginite B. Results indicate low to intermediate maturation for all of the samples. Composition was determined by maceral analysis. Alginite B is the major organic component in all samples having significant oil potential. Oil yields obtained from the Fischer Assay process, and oil and gas potentials from Rock-Eval analyses correlate to themore » amounts of alginite B and bituminite determined in the samples. In some of the samples characterized by similar high concentrations of alginite B, decrease in Fischer Assay yields and oil and gas potentials is related to an increase in maturation, as expected by increase in the fluorescence parameter lambda/sub max/ and red/green quotient of alginite B. Incident light microscopy, particularly with fluorescent light, offers a valuable tool for the identification of the organic matter in oil shales and for the evaluation of their oil and gas potentials.« less

Experimental Study and Numerical Modeling of Fracture Propagation in Shale Rocks During Brazilian Disk Test

NASA Astrophysics Data System (ADS)

Mousavi Nezhad, Mohaddeseh; Fisher, Quentin J.; Gironacci, Elia; Rezania, Mohammad

2018-06-01

Reliable prediction of fracture process in shale-gas rocks remains one of the most significant challenges for establishing sustained economic oil and gas production. This paper presents a modeling framework for simulation of crack propagation in heterogeneous shale rocks. The framework is on the basis of a variational approach, consistent with Griffith's theory. The modeling framework is used to reproduce the fracture propagation process in shale rock samples under standard Brazilian disk test conditions. Data collected from the experiments are employed to determine the testing specimens' tensile strength and fracture toughness. To incorporate the effects of shale formation heterogeneity in the simulation of crack paths, fracture properties of the specimens are defined as spatially random fields. A computational strategy on the basis of stochastic finite element theory is developed that allows to incorporate the effects of heterogeneity of shale rocks on the fracture evolution. A parametric study has been carried out to better understand how anisotropy and heterogeneity of the mechanical properties affect both direction of cracks and rock strength.

Assessment and longitudinal analysis of health impacts and stressors perceived to result from unconventional shale gas development in the Marcellus Shale region.

PubMed

Ferrar, Kyle J; Kriesky, Jill; Christen, Charles L; Marshall, Lynne P; Malone, Samantha L; Sharma, Ravi K; Michanowicz, Drew R; Goldstein, Bernard D

2013-01-01

Concerns for health and social impacts have arisen as a result of Marcellus Shale unconventional natural gas development. Our goal was to document the self-reported health impacts and mental and physical health stressors perceived to result from Marcellus Shale development. Two sets of interviews were conducted with a convenience sample of community members living proximal to Marcellus Shale development, session 1 March-September 2010 (n = 33) and session 2 January-April 2012 (n = 20). Symptoms of health impacts and sources of psychological stress were coded. Symptom and stressor counts were quantified for each interview. The counts for each participant were compared longitudinally. Participants attributed 59 unique health impacts and 13 stressors to Marcellus Shale development. Stress was the most frequently-reported symptom. Over time, perceived health impacts increased (P = 0·042), while stressors remained constant (P = 0·855). Exposure-based epidemiological studies are needed to address identified health impacts and those that may develop as unconventional natural gas extraction continues. Many of the stressors can be addressed immediately.

The effect of mining on the sediment - trace element geochemistry of cores from the Cheyenne River arm of Lake Oahe, South Dakota, U.S.A.

USGS Publications Warehouse

Horowitz, A.J.; Elrick, K.A.; Callender, E.

1988-01-01

Six cores, ranging in length from 1 to 2 m, were collected in the Cheyenne River arm of Lake Oahe, South Dakota, to investigate potential impacts from gold-mining operations around Lead, South Dakota. Sedimentation rates in the river arm appear to be event-dominated and rapid, on the order of 6-7 cm yr.-1. All the chemical concentrations in the core samples fall within the wide ranges previously reported for the Pierre Shale of Cretaceous age and with the exception of As, generally are similar to bed sediment levels in the Cheyenne River, Lake Oahe and Foster Bay. Based on the downcore distribution of Mn, it appears that reducing conditions exist in the sediment column of the river arm below 2-3 cm. The reducing conditions do not appear to be severe enough to produce differentiation of Fe and Mn throughout the sediment column in the river arm. Cross-correlations for high-level metal-bearing strata within the sediment column can be made for several strata and for several cores; however, cross-correlations for all the high-level metal-bearing strata are not feasible. As is the only element which appears enriched in the core samples compared to surface sediment levels. Well-crystallized arsenopyrite was found in high-As bearing strata from two cores and probably was transported in that form from reducing sediment-storage sites in the banks or floodplains of Whitewood Creek and the Belle Fourche River. It has not oxidized due to the reducing conditions in the sediment column of the Cheyenne River arm. Some As may also be transported in association with Fe- and Mn-oxides and -hydroxides, remobilized under the reducing conditions in the river arm, and then reprecipitated in authigenic sulfide phases. In either case, the As appears to be relatively immobile in the sediment column. ?? 1988.

The architecture and frictional properties of faults in shale

NASA Astrophysics Data System (ADS)

De Paola, Nicola; Murray, Rosanne; Stillings, Mark; Imber, Jonathan; Holdsworth, Robert

2015-04-01

The geometry of brittle fault zones and associated fracture patterns in shale rocks, as well as their frictional properties at reservoir conditions, are still poorly understood. Nevertheless, these factors may control the very low recovery factors (25% for gas and 5% for oil) obtained during fracking operations. Extensional brittle fault zones (maximum displacement ≤ 3 m) cut exhumed oil mature black shales in the Cleveland Basin (UK). Fault cores up to 50 cm wide accommodated most of the displacement, and are defined by a stair-step geometry, controlled by the reactivation of en-echelon, pre-existing joints in the protolith. Cores typically show a poorly developed damage zone, up to 25 cm wide, and sharp contact with the protolith rocks. Their internal architecture is characterised by four distinct fault rock domains: foliated gouges; breccias; hydraulic breccias; and a slip zone up to 20 mm thick, composed of a fine-grained black gouge. Hydraulic breccias are located within dilational jogs with aperture of up to 20 cm, composed of angular clasts of reworked fault and protolith rock, dispersed within a sparry calcite cement. Velocity-step and slide-hold-slide experiments at sub-seismic slip rates (microns/s) were performed in a rotary shear apparatus under dry, water and brine-saturated conditions, for displacements of up to 46 cm. Both the protolith shale and the slip zone black gouge display shear localization, velocity strengthening behaviour and negative healing rates. Experiments at seismic slip rates (1.3 m/s), performed on the same materials under dry conditions, show that after initial friction values of 0.5-0.55, friction decreases to steady-state values of 0.1-0.15 within the first 10 mm of slip. Contrastingly, water/brine saturated gouge mixtures, exhibit almost instantaneous attainment of very low steady-state sliding friction (0.1). Our field observations show that brittle fracturing and cataclastic flow are the dominant deformation mechanisms in the fault core of shale faults, where slip localization may lead to the development of a thin slip zone made of very fine-grained gouges. The velocity-strengthening behaviour and negative healing rates observed during our laboratory experiments, suggest that slow, stable sliding faulting should take place within the protolith rocks and slip zone gouges. This behaviour will cause slow fault/fracture propagation, affecting the rate at which new fracture areas are created and, hence, limiting oil and gas production during reservoir stimulation. During slipping events, fluid circulation may be very effective along the fault zone at dilational jogs - where oil and gas production should be facilitated by the creation of large fracture areas - and rather restricted in the adjacent areas of the protolith, due to the lack of a well-developed damage zone and the low permeability of the matrix and slip zone gouge. Finally, our experiments performed at seismic slip rates show that seismic ruptures may still be able to propagate in a very efficient way within the slip zone of fluid-saturated shale faults, due to the attainment of instantaneous weakening.

Mineralogy and geochemistry of the Lower Cretaceous siliciclastic rocks of the Morita Formation, Sierra San José section, Sonora, Mexico

NASA Astrophysics Data System (ADS)

Madhavaraju, J.; Pacheco-Olivas, S. A.; González-León, Carlos M.; Espinoza-Maldonado, Inocente G.; Sanchez-Medrano, P. A.; Villanueva-Amadoz, U.; Monreal, Rogelio; Pi-Puig, T.; Ramírez-Montoya, Erik; Grijalva-Noriega, Francisco J.

2017-07-01

Clay mineralogy and geochemical studies were carried out on sandstone and shale samples collected from the Sierra San José section of the Morita Formation to infer the paleoclimate and paleoweathering conditions that prevailed in the source region during the deposition of these sediments. The clay mineral assemblages (fraction < 2 μm) of the Sierra San José section are composed of chlorite and illite. The abundance of illite and chlorite in the studied samples suggest that the physical weathering conditions were dominant over chemical weathering. Additionally, the illite and chlorite assemblages reflect arid or semi-arid climatic conditions in the source regions. K2O/Al2O3 ratio of shales vary between 0.15 and 0.26, which lie in the range of values for clay minerals, particularly illite composition. Likewise, sandstones vary between 0.06 and 0.13, suggesting that the clay minerals are mostly kaolinte and illite types. On the chondrite-normalized diagrams, sandstone and shale samples show enriched light rare earth elements (LREE), flat heavy rare earth elements (HREE) patterns and negative Eu anomalies. The CIA and PIA values and A-CN-K plot of shales indicate low to moderate degree of weathering in the source regions. However, the sandstones have moderate to high values of CIA and PIA suggesting a moderate to intense weathering in the source regions. The SiO2/Al2O3 ratios, bivariate and ternary plots, discriminant function diagram and elemental ratios indicate the felsic source rocks for sandstone and shale of the Morita Formation.

Petrophysical, Lithological and Mineralogical Characteristics of the Shale Strata of the Volga- Ural Region

NASA Astrophysics Data System (ADS)

Morozov, Vladimir P.; Plotnikova, Irina N.; Pronin, Nikita V.; Nosova, Fidania F.; Pronina, Nailya R.

2014-05-01

The objects of the study are Upper Devonian carbonate rocks in the territory of South-Tatar arch and Melekess basin in the Volga- Urals region. We studied core material of Domanicoid facies from the sediments of Mendymski and Domanik horizons of middle substage of Frasnian stage of the Upper Devonian. Basic analytical research methods included the following: study of the composition, structural and textural features of the rocks, the structure of their voids, filter and reservoir properties and composition of the fluid. The complex research consisted of macroscopic description of the core material, optical microscopy analysis, radiographical analysis, thermal analysis, x-ray tomography, electron microscopy, gas-liquid chromatography, chromate-mass spectrometry, light hydrocarbons analysis using paraphase assay, adsorbed gases analysis, and thermal vacuum degassing method. In addition, we performed isotopic studies of hydrocarbons saturating shale rocks. Shale strata are mainly represented by carbonate-chert rocks. They consist mainly of calcite and quartz. The ratio of these rock-forming minerals varies widely - from 25 to 75 percent. Pyrite, muscovite, albite, and microcline are the most common inclusions. Calcareous and ferruginous dolomite (ankerite), as well as magnesian calcite are tracked down as secondary minerals. While performing the tests we found out that the walls of open fractures filled with oil are stacked by secondary dolomite, which should be considered as an indication moveable oil presence in the open-cut. Electron microscopy data indicate that all the studied samples have porosity - both carbonates and carbonate-siliceous rocks. Idiomorphism of the rock-forming grains and pores that are visible under a microscope bring us to that conclusion. The analysis of the images indicates that the type of reservoir is either porous or granular. The pores are distributed evenly in the volume of rock. Their size is very unstable and varies from 0.5 microns to 100 microns. The lowest value are observed in long carbonate-siliceous rocks, the highest values are found in carbonate rocks. The latter is caused by the fact that there is a very strong recrystallization of calcite and its dolomite substitution in carbonates. Open porosity ranges from 0.65 to 7.98 percent, average value is 4.1percent . Effective porosity has an average value of 0.44 percent, ranging from 0.22 to 1.97. Permeability varies from 0.043 to 1.49 mD, average value is 0,191 mD. Organic matter was found in all samples. Its content varies within the section. The fluctuation range of from 1.0 to 20 percent. The lowest content of carbonates is found in carbonates, while the highest is observed in carbonate-siliceous rocks with a high content of chalcedony. Average organic matter content is 5-7 percent. According to Rock-Eval studies of the core, the catagenetic maturity of organic matter corresponds to MK1 - MK2 degree. We found a connection between the type of organic matter and the composition of adsorbed gas. We also could see that the samples with humic organics present in their organic matter and can be characterized by a fair dominance of methane over other gases. There is a clear relationship between organic matter content and the intensity of the gas saturation of the rock. Organic matter is characteristic mainly of the most siliceous formations. In "pure" carbonates, which are represented by micro-layers with different capacities, OM is not observed at all or its content is quite low.

78 FR 6829 - Agency Information Collection Activities: Submitted for Office of Management and Budget (OMB...

Federal Register 2010, 2011, 2012, 2013, 2014

2013-01-31

... information related to coal, coal bed gas, shale gas and other energy resources and related information..., coal bed gas, and other solid fuel occurrences. Requesting external cooperation is the best way for... organic-rich shale, and obtain other information (including geophysical or seismic data, sample collection...

Total petroleum system assessment of undiscovered resources in the giant Barnett Shale continuous (unconventional) gas accumulation, Fort Worth Basin, Texas

USGS Publications Warehouse

Pollastro, R.M.

2007-01-01

Undiscovered natural gas having potential for additions to reserves in the Mississippian Barnett Shale of the Fort Worth Basin, north-central Texas, was assessed using the total petroleum system assessment unit concept and a cell-based methodology for continuous-type (Unconventional) resources. The Barnett-Paleozoic total petroleum system is defined in the Bend arch-Fort Worth Basin as encompassing the area in which the organic-rich Barnett is the primary source rock for oil and gas produced from Paleozoic carbonate and clastic reservoirs. Exploration, technology, and drilling in the Barnett Shale play have rapidly evolved in recent years, with about 3500 vertical and 1000 horizontal wells completed in the Barnett through 2005 and more than 85% of the them completed since 1999. Using framework geology and historical production data, assessment of the Barnett Shale was performed by the U.S. Geological Survey using vertical wells at the peak of vertical well completions and before a transition to completions with horizontal wells. The assessment was performed after (1) mapping critical geological and geochemical parameters to define assessment unit areas with future potential, (2) defining distributions of drainage area (cell size) and estimating ultimate recovery per cell, and (3) estimating future success rates. Two assessment units are defined and assessed for the Barnett Shale continuous gas accumulation, resulting in a total mean undiscovered volume having potential for additions to reserves of 26.2 TCFG. The greater Newark East fracture-barrier continuous Barnett Shale gas assessment unit represents a core-producing area where thick, organic-rich, siliceous Barnett Shale is within the thermal window for gas generation (Ro ??? 1.1%) and is overlain and underlain by impermeable limestone barriers (Pennsylvanian Marble Falls Limestone and Ordovician Viola Limestone, respectively) that serve to confine induced fractures during well completion to maximize gas recovery. The extended continuous Barnett Shale gas assessment unit, which had been less explored, defines a geographic area where Barnett Shale is (1) within the thermal window for gas generation, (2) greater than 100 ft (30 m) thick, and (3) where at least one impermeable limestone barrier is absent. Mean undiscovered gas having potential for additions to reserves in the greater Newark East assessment unit is estimated at 14.6 tcf, and in the less tested extended assessment unit, a mean resource is estimated at 11.6 TCFG. A third hypothetical basin-arch Barnett Shale oil assessment unit was defined but not assessed because of a lack of production data. Copyright ?? 2007. The American Association of Petroleum Geologists. All rights reserved.

Shale Gas Geomechanics for Development and Performance of Unconventional Reservoirs

NASA Astrophysics Data System (ADS)

Domonik, Andrzej; Łukaszewski, Paweł; Wilczyński, Przemysław; Dziedzic, Artur; Łukasiak, Dominik; Bobrowska, Alicja

2017-04-01

Mechanical properties of individual shale formations are predominantly determined by their lithology, which reflects sedimentary facies distribution, and subsequent diagenetic and tectonic alterations. Shale rocks may exhibit complex elasto-viscoplastic deformation mechanisms depending on the rate of deformation and the amount of clay minerals, also bearing implications for subcritical crack growth and heterogeneous fracture network development. Thus, geomechanics for unconventional resources differs from conventional reservoirs due to inelastic matrix behavior, stress sensitivity, rock anisotropy and low matrix permeability. Effective horizontal drilling and hydraulic fracturing technologies are required to obtain and maintain high performance. Success of these techniques strongly depends on the geomechanical investigations of shales. An inelastic behavior of shales draws increasing attention of investigators [1], due to its role in stress relaxation between fracturing phases. A strong mechanical anisotropy in the vertical plane and a lower and more variable one in the horizontal plane are characteristic for shale rocks. The horizontal anisotropy plays an important role in determining the direction and effectiveness of propagation of technological hydraulic fractures. Non-standard rock mechanics laboratory experiments are being applied in order to obtain the mechanical properties of shales that have not been previously studied in Poland. Novel laboratory investigations were carried out to assess the creep parameters and to determine time-dependent viscoplastic deformation of shale samples, which can provide a limiting factor to tectonic stresses and control stress change caused by hydraulic fracturing. The study was supported by grant no.: 13-03-00-501-90-472946 "An integrated geomechanical investigation to enhance gas extraction from the Pomeranian shale formations", funded by the National Centre for Research and Development (NCBiR). References: Ch. Chang M. D. Zoback. 2009. Viscous creep in room-dried unconsolidated Gulf of Mexico shale (I): Experimental results. Journal of Petroleum Science and Engineering 69: 239-246.

The influence of nitrate on selenium in irrigated agricultural groundwater systems.

PubMed

Bailey, Ryan T; Hunter, William J; Gates, Timothy K

2012-01-01

Selenium (Se) contamination of groundwater is an environmental concern especially in areas where aquifer systems are underlain by Se-bearing geologic formations such as marine shale. This study examined the influence of nitrate (NO₃) on Se species in irrigated soil and groundwater systems and presents results from field and laboratory studies that further clarify this influence. Inhibition of selenate (SeO₄) reduction in the presence of NO₃ and the oxidation of reduced Se from shale by autotrophic denitrification were investigated. Groundwater sampling from piezometers near an alluvium-shale interface suggests that SeO₄ present in the groundwater was due in part to autotrophic denitrification. Laboratory shale oxidation batch studies indicate that autotrophic denitrification is a major driver in the release of SeO₄ and sulfate. Similar findings occurred for a shale oxidation flow-through column study, with 70 and 31% more reduced Se and S mass, respectively, removed from the shale material in the presence of NO₃ than in its absence. A final laboratory flow-through column test was performed with shallow soil samples to assess the inhibition of SeO₄ reduction in the presence of NO₃, with results suggesting that a concentration of NO₃ of approximately 5 mg L or greater will diminish the reduction of SeO₄. The inclusion of the fate and transport of NO₃ and dissolved oxygen is imperative when studying or simulating the fate and transport of Se species in soil and groundwater systems. Copyright © by the American Society of Agronomy, Crop Science Society of America, and Soil Science Society of America, Inc.

Characterization and Analysis of Liquid Waste from Marcellus Shale Gas Development.

PubMed

Shih, Jhih-Shyang; Saiers, James E; Anisfeld, Shimon C; Chu, Ziyan; Muehlenbachs, Lucija A; Olmstead, Sheila M

2015-08-18

Hydraulic fracturing of shale for gas production in Pennsylvania generates large quantities of wastewater, the composition of which has been inadequately characterized. We compiled a unique data set from state-required wastewater generator reports filed in 2009-2011. The resulting data set, comprising 160 samples of flowback, produced water, and drilling wastes, analyzed for 84 different chemicals, is the most comprehensive available to date for Marcellus Shale wastewater. We analyzed the data set using the Kaplan-Meier method to deal with the high prevalence of nondetects for some analytes, and compared wastewater characteristics with permitted effluent limits and ambient monitoring limits and capacity. Major-ion concentrations suggested that most wastewater samples originated from dilution of brines, although some of our samples were more concentrated than any Marcellus brines previously reported. One problematic aspect of this wastewater was the very high concentrations of soluble constituents such as chloride, which are poorly removed by wastewater treatment plants; the vast majority of samples exceeded relevant water quality thresholds, generally by 2-3 orders of magnitude. We also examine the capacity of regional regulatory monitoring to assess and control these risks.

Recognition, correlation, and hierarchical stacking patterns of cycles in the Ferry Lake - Uppe Glen Rose, East Texas Basin: Implications for grainstone reservoir distribution

DOE Office of Scientific and Technical Information (OSTI.GOV)

Fitchen, W.M.; Bebout, D.G.; Hoffman, C.L.

1994-12-31

Core descriptions and regional log correlation/interpretation of Ferry Lake-Upper Glen Rose strata in the East Texas Basin exhibit the uniformity of cyclicity in these shelf units. The cyclicity is defined by an upward decrease in shale content within each cycle accompanied by an upward increase in anhydrite (Ferry Lake) or carbonate (Upper Glen Rose). Core-to-log calibration of facies indicates that formation resistivity is inversely proportional to shale content and thus is a potential proxy for facies identification beyond core control. Cycles (delineated by resistivity log patterns) were correlated for 90 mi across the shelf; they show little change in logmore » signature despite significant updip thinning due to the regional subsidence gradient. The Ferry-Lake-Upper Glen Rose intervals is interpreted as a composite sequence composed of 13 high-frequency sequences (4 in the Ferry Lake and 9 in the Upper Glen Rose). High-frequency sequences contain approximately 20 ({+-}5) cycles; in the Upper Glen Rose, successive cycles exhibit decreasing proportions of shale and increasing proportions of grain-rich carbonate. High-frequency sequences were terminated by terrigenous inundation, possibly preceded by subaerial exposure. Cycle and high-frequency sequence composition is interpreted to reflect composite, periodic(?) fluctuations is terrigeneous dilution from nearby source areas. Grainstones typically occur (stratigraphically) within the upper cycles of high-frequency sequences, where terrigeneous dilution and turbidity were least and potential for carbonate production and shoaling was greatest. Published mid-Cretaceous geographic reconstructions and climate models suggest that precipitation and runoff in the area were controlled by the seasonal amplitude in solar insolation. In this model, orbital variations, combined with subsidence, hydrography, and bathymetry, were in primary controls on Ferry Lake-Upper Glen Rose facies architecture and stratigraphic development.« less

Use of Digital Volume Correlation to Measure Deformation of Shale Using Natural Markers

NASA Astrophysics Data System (ADS)

Dewers, T. A.; Quintana, E.; Ingraham, M. D.; Jacques, C. L.

2016-12-01

We apply digital volume correlation (DVC) to interpreting deformation as influenced by shale heterogeneity. An extension of digital image correlation, DVC uses 3D images (CT Scans) of a sample before, during and after loading to determine deformation in terms of a 3D strain map. The technology tracks the deformation of high and low density regions within the sample to determine full field 3D strains within the sample. High pyrite shales (Woodford and Marcellus in this study) are being used as the high density pyrite serves as an excellent point to track in the volume correlation. Preliminary results indicate that this technology is promising for measuring true volume strains, strain localization, and strain portioning by microlithofacies within specimens during testing. Sandia National Laboratories is a multi-program laboratory managed and operated by Sandia Corporation, a wholly owned subsidiary of Lockheed Martin Corporation, for the U.S. Department of Energy's National Nuclear Security Administration under contract DE-AC04-94AL85000.

Advances in coalbed methane reservoirs using integrated reservoir characterization and hydraulic fracturing in Karaganda coal basin, Kazakhstan

NASA Astrophysics Data System (ADS)

Ivakhnenko, Aleksandr; Aimukhan, Adina; Kenshimova, Aida; Mullagaliyev, Fandus; Akbarov, Erlan; Mullagaliyeva, Lylia; Kabirova, Svetlana; Almukhametov, Azamat

2017-04-01

Coalbed methane from Karaganda coal basin is considered to be an unconventional source of energy for the Central and Eastern parts of Kazakhstan. These regions are situated far away from the main traditional sources of oil and gas related to Precaspian petroleum basin. Coalbed methane fields in Karaganda coal basin are characterized by geological and structural complexity. Majority of production zones were characterized by high methane content and extremely low coal permeability. The coal reservoirs also contained a considerable natural system of primary, secondary, and tertiary fractures that were usually capable to accommodate passing fluid during hydraulic fracturing process. However, after closing was often observed coal formation damage including the loss of fluids, migration of fines and higher pressures required to treat formation than were expected. Unusual or less expected reservoir characteristics and values of properties of the coal reservoir might be the cause of the unusual occurred patterns in obtained fracturing, such as lithological peculiarities, rock mechanical properties and previous natural fracture systems in the coals. Based on these properties we found that during the drilling and fracturing of the coal-induced fractures have great sensitivity to complex reservoir lithology and stress profiles, as well as changes of those stresses. In order to have a successful program of hydraulic fracturing and avoid unnecessary fracturing anomalies we applied integrated reservoir characterization to monitor key parameters. In addition to logging data, core sample analysis was applied for coalbed methane reservoirs to observe dependence tiny lithological variations through the magnetic susceptibility values and their relation to permeability together with expected principal stress. The values of magnetic susceptibility were measured by the core logging sensor, which is equipped with the probe that provides volume magnetic susceptibility parameters. Permeability was measured by air permeameter. Results confirmed that there is a correspondence between the high permeability and the low magnetic susceptibility values of production zones. Importantly also were found relation of the coal envelope type between only shales coal framing or only sandstone coal framing that most likely led to different stress profiles. In addition, we briefly describe potential of other types of unconventional resources in Kazakhstan, such as shale oil, tight gas and shale gas, where this integrated approach could be useful to apply in the future.

Geochemical constraints on the origin and volume of gas in the New Albany Shale (Devonian-Mississippian), eastern Illinois Basin

USGS Publications Warehouse

Strapoc, D.; Mastalerz, Maria; Schimmelmann, A.; Drobniak, A.; Hasenmueller, N.R.

2010-01-01

This study involved analyses of kerogen petrography, gas desorption, geochemistry, microporosity, and mesoporosity of the New Albany Shale (Devonian-Mississippian) in the eastern part of the Illinois Basin. Specifically, detailed core analysis from two locations, one in Owen County, Indiana, and one in Pike County, Indiana, has been conducted. The gas content in the locations studied was primarily dependent on total organic carbon content and the micropore volume of the shales. Gas origin was assessed using stable isotope geochemistry. Measured and modeled vitrinite reflectance values were compared. Depth of burial and formation water salinity dictated different dominant origins of the gas in place in the two locations studied in detail. The shallower Owen County location (415-433 m [1362-1421 ft] deep) contained significant additions of microbial methane, whereas the Pike County location (832-860 m [2730-2822 ft] deep) was characterized exclusively by thermogenic gas. Despite differences in the gas origin, the total gas in both locations was similar, reaching up to 2.1 cm3/g (66 scf/ton). Lower thermogenic gas content in the shallower location (lower maturity and higher loss of gas related to uplift and leakage via relaxed fractures) was compensated for by the additional generation of microbial methane, which was stimulated by an influx of glacial melt water, inducing brine dilution and microbial inoculation. The characteristics of the shale of the Maquoketa Group (Ordovician) in the Pike County location are briefly discussed to provide a comparison to the New Albany Shale. Copyright ??2010. The American Association of Petroleum Geologists. All rights reserved.

Origin of the anomalies in light and middle REE in sediments of an estuary affected by phosphogypsum wastes (south-western Spain).

PubMed

Borrego, J; López-González, N; Carro, B; Lozano-Soria, O

2004-12-01

Sc, Y, Th, Cu and rare earth elements (REE) concentrations have been analyzed in 14 samples of surface sediments and in two gravity cores by means of ICP-MS. Mean concentrations of Sc, Y and Th in surface sediments are 6.23, 4.76 and 16.30 ppm, respectively, lower than those present in the Upper Continental Crust (UCC). Cu concentration in these sediments is very high, 1466 ppm, and is caused by inputs from the Odiel and Tinto rivers, affected by acid mine drainage. SigmaREE mean concentration is 106.8 ppm, lower than that observed in other rivers and estuaries. In the cores, Sc, Y and Th concentrations show a significant increase in the intermediate levels, between 10 and 40 cm depth. The same pattern exists with Cu, where concentrations of 4440 ppm can be reached. Vertical evolution patterns for Sc, Y, Cu and heavy REE (HREE) are similar, and contrary to those shown by Th, light REE (LREE) and middle REE (MREE). Plots of North American Shale Composite (NASC)-normalized REE data of surface sediments show a slight depletion in REE concentrations. Most samples present with middle REE enrichment relative to light REE and heavy REE. Conversely, samples of the intermediate levels of the cores show significant enrichment of REE relative to NASC and high values in the (La/Gd)NASC and (La/Yb)NASC ratios. These anomalies in the fractionation patterns caused by enrichments in LREE and MREE concentrations is related to the presence of high concentrations of Th. They were generated by effluents from fertilizer factories between 1968 and 1998 which used phosphorite as source material.

Molecular characterization and comparison of shale oils generated by different pyrolysis methods

USGS Publications Warehouse

Birdwell, Justin E.; Jin, Jang Mi; Kim, Sunghwan

2012-01-01

Shale oils generated using different laboratory pyrolysis methods have been studied using standard oil characterization methods as well as Fourier transform ion cyclotron resonance mass spectrometry (FT-ICR MS) with electrospray ionization (ESI) and atmospheric photoionization (APPI) to assess differences in molecular composition. The pyrolysis oils were generated from samples of the Mahogany zone oil shale of the Eocene Green River Formation collected from outcrops in the Piceance Basin, Colorado, using three pyrolysis systems under conditions relevant to surface and in situ retorting approaches. Significant variations were observed in the shale oils, particularly the degree of conjugation of the constituent molecules and the distribution of nitrogen-containing compound classes. Comparison of FT-ICR MS results to other oil characteristics, such as specific gravity; saturate, aromatic, resin, asphaltene (SARA) distribution; and carbon number distribution determined by gas chromatography, indicated correspondence between higher average double bond equivalence (DBE) values and increasing asphaltene content. The results show that, based on the shale oil DBE distributions, highly conjugated species are enriched in samples produced under low pressure, high temperature conditions, and under high pressure, moderate temperature conditions in the presence of water. We also report, for the first time in any petroleum-like substance, the presence of N4 class compounds based on FT-ICR MS data. Using double bond equivalence and carbon number distributions, structures for the N4 class and other nitrogen-containing compounds are proposed.

Trace element partitioning during the retorting of Julia Creek oil shale

DOE Office of Scientific and Technical Information (OSTI.GOV)

Patterson, J.H.; Dale, L.S.; Chapman, J.f.

1987-05-01

A bulk sample of oil shale from the Julia Creek deposit in Queensland was retorted under Fischer assay conditions at temperatures ranging from 250 to 550 /sup 0/C. The distributions of the trace elements detected in the shale oil and retort water were determined at each temperature. Oil distillation commenced at 300 /sup 0/C and was essentially complete at 500 /sup 0/C. A number of trace elements were progressively mobilized with increasing retort temperature up to 450 /sup 0/C. The following trace elements partitioned mainly to the oil: vanadium, arsenic, selenium, iron, nickel, titanium, copper, cobalt, and aluminum. Elements thatmore » also partitioned to the retort waters included arsenic, selenium, chlorine, and bromine. Element mobilization is considered to be caused by the volatilization of organometallic compounds, sulfide minerals, and sodium halides present in the oil shale. The results have important implications for shale oil refining and for the disposal of retort waters. 22 references, 5 tables.« less

Marketable transport fuels made from Julia Creek shale oil

DOE Office of Scientific and Technical Information (OSTI.GOV)

Not Available

1987-03-01

CSR Limited and the CSIRO Division of Energy Chemistry have been working on the problem of producing refined products from the Julia Creek deposit in Queensland, Australia. Two samples of shale oil, retorted at different temperatures from Julia Creek oil shale, were found to differ markedly in aromaticity. Using conventional hydrotreating technology, high quality jet and diesel fuels could be made from the less aromatic oil. Naphtha suitable for isomerization and reforming to gasoline could be produced from both oils. This paper discusses oil properties, stabilization of topped crudes, second stage hydrotreatment, and naphtha hydrotreating. 1 figure, 4 tables.

Creep of Posidonia and Bowland shale at elevated pressures and temperatures

NASA Astrophysics Data System (ADS)

Herrmann, Johannes; Rybacki, Erik; Sone, Hiroki; Dresen, Georg

2017-04-01

The fracture-healing rate of artificial cracks generated by hydraulic fracturing is of major interest in the E&P industry since it is important for the long-time productivity of a well. To estimate the stress-induced healing rate of unconventional reservoir rocks, we performed deformation tests on Bowland shale rocks (UK) and on Posidonia shales (Germany). Samples of 1cm diameter and 2cm length were drilled perpendicular to the bedding and deformed in a high pressure, high temperature deformation apparatus. Constant strain rate tests at 5*10-4*s-1, 50 MPa confining pressure and 100˚ C temperature reveal a mainly brittle behaviour with predominantly elastic deformation before failure and high strength of low porosity (˜2%), quartz-rich (˜42 vol%) Bowland shale. In contrast, the low porosity (˜3%), carbonate- (˜43 vol%) and clay-rich (˜33 vol%) Posidonia shale deforms semi-brittle with pronounced inelastic deformation and low peak strength. These results suggest a good fracability of the Bowland formation compared to the Posidonia shale. Constant load (creep) experiments performed on Bowland shale at 100˚ C temperature and 75 MPa pressure show mainly transient (primary) deformation with increasing strain rate at increasing axial stress. The strain rate increases also with increasing temperature, measured in the range of 75 - 150˚ C at fixed stress and confinement. In contrast, increasing confining pressure (from 30 to 115 MPa) at given temperature and stress results in decreasing strain rate. In contrast, Posidonia shale rocks are much more sensitive to changes in stress, temperature and pressure than Bowland shale. Empirical relations between strain and stress that account for the influence of pressure and temperature on creep properties of Posidonia and Bowland shale rocks can be used to estimate the fracture healing rate of these shales under reservoir conditions.

Imaging the Ferron Member of the Mancos Shale formation using reprocessed high-resolution 2-D seismic reflection data: Emery County, Utah

USGS Publications Warehouse

Taylor, D.J.

2003-01-01

Late in 1982 and early in 1983, Arco Exploration contracted with Rocky Mountain Geophysical to acquired four high-resolution 2-D multichannel seismic reflection lines in Emery County, Utah. The primary goal in acquiring this data was an attempt to image the Ferron Member of the Upper Cretaceous Mancos Shale. Design of the high-resolution 2-D seismic reflection data acquisition used both a short geophone group interval and a short sample interval. An explosive energy source was used which provided an input pulse with broad frequency content and higher frequencies than typical non-explosive Vibroseis?? sources. Reflections produced by using this high-frequency energy source when sampled at a short interval are usually able to resolve shallow horizons that are relatively thin compared to those that can be resolved using more typical oil and gas exploration seismic reflection methods.The U.S. Geological Survey-Energy Resources Program, Geophysical Processing Group used the processing sequence originally applied by Arco in 1984 as a guide and experimented with processing steps applied in a different order using slightly different parameters in an effort to improve imaging the Ferron Member horizon. As with the Arco processed data there are sections along all four seismic lines where the data quality cannot be improved upon, and in fact the data quality is so poor that the Ferron horizon cannot be imaged at all.Interpretation of the seismic and core hole data indicates that the Ferron Member in the study area represent a deltaic sequence including delta front, lower delta plain, and upper delta plain environments. Correlating the depositional environments for the Ferron Member as indicated in the core holes with the thickness of Ferron Member suggests the presence of a delta lobe running from the northwest to the southeast through the study area. The presence of a deltaic channel system within the delta lobe complex might prove to be an interesting conventional exploration target along with the coal-bed methane production already proven in the area. ?? 2003 Elsevier B.V. All rights reserved.

Water Saturation Relations and Their Diffusion-Limited Equilibration in Gas Shale: Implications for Gas Flow in Unconventional Reservoirs

NASA Astrophysics Data System (ADS)

Tokunaga, Tetsu K.; Shen, Weijun; Wan, Jiamin; Kim, Yongman; Cihan, Abdullah; Zhang, Yingqi; Finsterle, Stefan

2017-11-01

Large volumes of water are used for hydraulic fracturing of low permeability shale reservoirs to stimulate gas production, with most of the water remaining unrecovered and distributed in a poorly understood manner within stimulated regions. Because water partitioning into shale pores controls gas release, we measured the water saturation dependence on relative humidity (rh) and capillary pressure (Pc) for imbibition (adsorption) as well as drainage (desorption) on samples of Woodford Shale. Experiments and modeling of water vapor adsorption into shale laminae at rh = 0.31 demonstrated that long times are needed to characterize equilibrium in larger (5 mm thick) pieces of shales, and yielded effective diffusion coefficients from 9 × 10-9 to 3 × 10-8 m2 s-1, similar in magnitude to the literature values for typical low porosity and low permeability rocks. Most of the experiments, conducted at 50°C on crushed shale grains in order to facilitate rapid equilibration, showed significant saturation hysteresis, and that very large Pc (˜1 MPa) are required to drain the shales. These results quantify the severity of the water blocking problem, and suggest that gas production from unconventional reservoirs is largely associated with stimulated regions that have had little or no exposure to injected water. Gravity drainage of water from fractures residing above horizontal wells reconciles gas production in the presence of largely unrecovered injected water, and is discussed in the broader context of unsaturated flow in fractures.

Understanding Hydraulic Fracturing: A Multi-Scale Problem

DOE PAGES

Hyman, Jeffrey De'Haven; Gimenez Martinez, Joaquin; Viswanathan, Hari S.; ...

2016-09-05

Despite the impact that hydraulic fracturing has had on the energy sector, the physical mechanisms that control its efficiency and environmental impacts remain poorly understood in part because the length scales involved range from nano-meters to kilo-meters. We characterize flow and transport in shale formations across and between these scales using integrated computational, theoretical, and experimental efforts. At the field scale, we use discrete fracture network modeling to simulate production at a well site whose fracture network is based on a site characterization of a shale formation. At the core scale, we use triaxial fracture experiments and a finite-element discrete-elementmore » fracture propagation model with a coupled fluid solver to study dynamic crack propagation in low permeability shale. We use lattice Boltzmann pore-scale simulations and microfluidic experiments in both synthetic and real micromodels to study pore-scale flow phenomenon such as multiphase flow and mixing. A mechanistic description and integration of these multiple scales is required for accurate predictions of production and the eventual optimization of hydrocarbon extraction from unconventional reservoirs.« less

Shale Fracture Analysis using the Combined Finite-Discrete Element Method

NASA Astrophysics Data System (ADS)

Carey, J. W.; Lei, Z.; Rougier, E.; Knight, E. E.; Viswanathan, H.

2014-12-01

Hydraulic fracturing (hydrofrac) is a successful method used to extract oil and gas from highly carbonate rocks like shale. However, challenges exist for industry experts estimate that for a single $10 million dollar lateral wellbore fracking operation, only 10% of the hydrocarbons contained in the rock are extracted. To better understand how to improve hydrofrac recovery efficiencies and to lower its costs, LANL recently funded the Laboratory Directed Research and Development (LDRD) project: "Discovery Science of Hydraulic Fracturing: Innovative Working Fluids and Their Interactions with Rocks, Fractures, and Hydrocarbons". Under the support of this project, the LDRD modeling team is working with the experimental team to understand fracture initiation and propagation in shale rocks. LANL's hybrid hydro-mechanical (HM) tool, the Hybrid Optimization Software Suite (HOSS), is being used to simulate the complex fracture and fragment processes under a variety of different boundary conditions. HOSS is based on the combined finite-discrete element method (FDEM) and has been proven to be a superior computational tool for multi-fracturing problems. In this work, the comparison of HOSS simulation results to triaxial core flooding experiments will be presented.

A multi-scale micromechanics framework for shale using the nano-tools

NASA Astrophysics Data System (ADS)

Ortega, J.; Ulm, F.; Abousleiman, Y.

2009-12-01

The successful prediction of poroelastic properties of fine-grained rocks such as shale continues to be a formidable challenge for the geophysics community. The highly heterogeneous nature of shale in terms of its compositional and microstructural features translates into a complex anisotropic behavior observed at macroscopic length scales. The recent application of instrumented indentation for the mechanical characterization of shale has revealed the granular response and intrinsic anisotropy of its porous clay phase at nanometer length scales [1-2]. This discovered mechanical behavior at the grain scale has been incorporated into the development of a multi-scale, micromechanics model for shale poroelasticity [3]. The only inputs to the model are two volumetric parameters synthesizing the mineralogy and porosity information of a shale sample. The model is meticulously calibrated and validated, as displayed in Fig. 1, with independent data sets of anisotropic elasticity obtained from nanoindentation experiments and standard laboratory acoustic measurements for shale specimens with and without organic content. The treatment of the elastic anisotropy corresponding to the porous clay fabric, as sensed by nanoindentation, delineates the contribution of the intrinsic anisotropy in shale to its overall anisotropy observed at macroscales. Furthermore, the proposed poroelastic formulation provides access to intrinsic rock parameters such as Biot pore pressure coefficients that are of importance for problems of flow in porous media. In addition, the model becomes a useful tool in geophysics applications for the prediction of shale acoustic properties from material-specific information such as porosity, mineralogy, and density measurements. References: [1] Ulm, F.-J., Abousleiman, Y. (2006) ‘The nanogranular nature of shale.’ Acta Geot. 1(2), 77-88. [2] Bobko, C., Ulm, F.-J. (2008) ‘The nano-mechanical morphology of shale.’ Mech. Mat. 40(4-5), 318-337. [3] Ortega, J. A., Ulm, F.-J., Abousleiman, Y. (2009) ‘The nanogranular acoustic signature of shale.’ Geophysics 74(3), D65-D84. Fig. 1. Comparisons between predicted and experimental elasticity obtained from nanoindentation experiments (left) and acoustic measurements (right) for shale with and without organic content (hollow and solid data points). Nanoindentation elasticity of the porous clay in shale is presented as a function of the clay packing density (one minus the nanoporosity). The x-1, x-3 directions correspond to parallel and normal-to-bedding plane properties, respectively. All nanoindentation data and acoustic measurements for organic-rich shale from [2-3]. Acoustic measurements for organic-free shale were gathered from literature sources compiled in [3].

Application of uniaxial confining-core clamp with hydrous pyrolysis in petrophysical and geochemical studies of source rocks at various thermal maturities

USGS Publications Warehouse

Lewan, Michael D.; Birdwell, Justin E.; Baez, Luis; Beeney, Ken; Sonnenberg, Steve

2013-01-01

Understanding changes in petrophysical and geochemical parameters during source rock thermal maturation is a critical component in evaluating source-rock petroleum accumulations. Natural core data are preferred, but obtaining cores that represent the same facies of a source rock at different thermal maturities is seldom possible. An alternative approach is to induce thermal maturity changes by laboratory pyrolysis on aliquots of a source-rock sample of a given facies of interest. Hydrous pyrolysis is an effective way to induce thermal maturity on source-rock cores and provide expelled oils that are similar in composition to natural crude oils. However, net-volume increases during bitumen and oil generation result in expanded cores due to opening of bedding-plane partings. Although meaningful geochemical measurements on expanded, recovered cores are possible, the utility of the core for measuring petrophysical properties relevant to natural subsurface cores is not suitable. This problem created during hydrous pyrolysis is alleviated by using a stainless steel uniaxial confinement clamp on rock cores cut perpendicular to bedding fabric. The clamp prevents expansion just as overburden does during natural petroleum formation in the subsurface. As a result, intact cores can be recovered at various thermal maturities for the measurement of petrophysical properties as well as for geochemical analyses. This approach has been applied to 1.7-inch diameter cores taken perpendicular to the bedding fabric of a 2.3- to 2.4-inch thick slab of Mahogany oil shale from the Eocene Green River Formation. Cores were subjected to hydrous pyrolysis at 360 °C for 72 h, which represents near maximum oil generation. One core was heated unconfined and the other was heated in the uniaxial confinement clamp. The unconfined core developed open tensile fractures parallel to the bedding fabric that result in a 38 % vertical expansion of the core. These open fractures did not occur in the confined core, but short, discontinuous vertical fractures on the core periphery occurred as a result of lateral expansion.

Conventional oil and gas development alters forest songbird communities

Treesearch

Emily H. Thomas; Margaret C. Brittingham; Scott H. Stoleson

2014-01-01

Energy extraction within forest habitat is increasing at a rapid rate throughout eastern North America from the combined presence of conventional oil and gas, shale gas, and wind energy. We examined the effects of conventional oil and gas development on forest habitat including amounts of core and edge forest, the abundance of songbird species and guilds, species...

Petrophysical Rock Typing of Unconventional Shale Plays: A Case Study for the Niobrara Formation of the Denver-Julesburg (DJ) Basin

NASA Astrophysics Data System (ADS)

Kamruzzaman, A.; Prasad, M.

2015-12-01

The hydrocarbon-rich mudstone rock layers of the Niobrara Formation were deposited in the shallow marine environment and have evolved as overmature oil- or gas-prone source and reservoir rocks. The hydrocarbon production from its low-porosity, nano-darcy permeability and interbedded chalk-marl reservoir intervals is very challenging. The post-diagenetic processes have altered the mineralogy and pore structure of its sourcing and producing rock units. A rock typing analysis in this play can help understand the reservoir heterogeneity significantly. In this study, a petrophysical rock typing workflow is presented for the Niobrara Formation by integrating experimental rock properties with geologic lithofacies classification, well log data and core study.Various Niobrara lithofacies are classified by evaluating geologic depositional history, sequence stratigraphy, mineralogy, pore structure, organic content, core texture, acoustic properties, and well log data. The experimental rock measurements are conducted on the core samples recovered from a vertical well from the Wattenberg Field of the Denver-Julesburg (DJ) Basin. Selected lithofacies are used to identify distinct petrofacies through the empirical analysis of the experimental data-set. The grouped petrofacies are observed to have unique mineralogical properties, pore characteristics, and organic contents and are labelled as discrete Niobrara rock types in the study area.Micro-textural image analysis (FESEM) is performed to qualitatively examine the pore size distribution, pore types and mineral composition in the matrix to confirm the classified rock units. The principal component analysis and the cluster analysis are carried out to establish the certainty of the selected rock types. Finally, the net-to-pay thicknesses of these rock units are compared with the cumulative production data from the field to further validate the chosen rock types.For unconventional shale plays, the rock typing information can be used to locate hydrocarbon sweetspots, facilitate the placement of the horizontal section of the wells along the sweetspots, and can augment engineers' abilities on suitable well placement considerations. It can also help enhancing the effectiveness of the hydraulic fracture stimulation and completion operation.

Use of arsenic and REE in black shales as potential environmental tracers in hydraulic fracturing operations

NASA Astrophysics Data System (ADS)

Yang, J.; Torres, M. E.; Haley, B. A.; McKay, J. L.; Algeo, T. J.; Hakala, A.; Joseph, C.; Edenborn, H. M.

2013-12-01

Black shales commonly targeted for shale gas development were deposited under low oxygen concentrations, and typically contain high As levels. The depositional environment governs its solid-phase association in the sediment, which in turn will influence degree of remobilization during hydraulic fracturing. Organic carbon (OC), trace element (TE) and REE distributions have been used as tracers for assessing deep water redox conditions at the time of deposition in the Midcontinent Sea of North America (Algeo and Heckel, 2008), during large-scale oceanic anoxic events (e.g., Bunte, 2009) and in modern OC-rich sediments underlying coastal upwelling areas (e.g., Brumsack, 2006). We will present REE and As data from a collection of six different locations in the continental US (Kansas, Iowa, Oklahoma, Kentucky, North Dakota and Pennsylvania), ranging in age from Devonian to Upper Pennsylvanian, and from a Cretaceous black shale drilled on the Demerara Rise during ODP Leg 207. We interpret our data in light of the depositional framework previously developed for these locations based on OC and TE patterns, to document the mechanisms leading to REE and As accumulation, and explore their potential use as environmental proxies and their diagenetic remobilization during burial, as part of our future goal to develop a predictive evaluation of arsenic release from shales and transport with flowback waters. Total REE abundance (ΣREE) ranged from 35 to 420 ppm in an organic rich sample from Stark shale, KS. PAAS-normalized REE concentrations ranged from 0.5 to 7, with the highest enrichments observed in the MREE (Sm to Ho). Neither the ΣREE nor the MREE enrichments correlated with OC concentrations or postulated depositional redox conditions, suggesting a principal association with aluminosilicates and selective REE fractionation during diagenesis. In the anoxic reducing environments in which black shales were deposited, sulfide minerals such as FeS2 trap aqueous arsenic in the crystal lattice, but As is also known to bind to the charged surfaces of clay minerals. Our arsenic concentration data show that the highest abundances (up to 70 ppm) are found in sediments with the highest total sulfur concentration (to 2.6 ppm), but there was no clear correlation with organic carbon or aluminosilicate content. We compare our results with preliminary data from a series of flowback waters sampled from ten producing wells in Pennsylvania and from high-pressure high-temperature experimental leaching of Marcellus shale samples.

On the changing petroleum generation properties of Alum Shale over geological time caused by uranium irradiation

NASA Astrophysics Data System (ADS)

Yang, Shengyu; Schulz, Hans-Martin; Horsfield, Brian; Schovsbo, Niels H.; Noah, Mareike; Panova, Elena; Rothe, Heike; Hahne, Knut

2018-05-01

An interdisciplinary study was carried out to unravel organic-inorganic interactions caused by the radiogenic decay of uranium in the immature organic-rich Alum Shale (Middle Cambrian-Lower Ordovician). Based on pyrolysis experiments, uranium content is positively correlated with the gas-oil ratios and the aromaticities of both the free hydrocarbons residing in the rock and the pyrolysis products from its kerogen, indicating that irradiation has had a strong influence on organic matter composition overall and hence on petroleum potential. The Fourier Transform Ion Cyclotron Resonance mass spectrometry data reveal that macro-molecules in the uranium-rich Alum Shale samples are less alkylated than less irradiated counterparts, providing further evidence for structural alteration by α-particle bombardment. In addition, oxygen containing-compounds are enriched in the uranium-rich samples but are not easily degradable into low-molecular-weight products due to irradiation-induced crosslinking. Irradiation has induced changes in organic matter composition throughout the shale's entire ca. 500 Ma history, irrespective of thermal history. This factor has to be taken into account when reconstructing petroleum generation history. The Alum Shale's kerogen underwent catagenesis in the main petroleum kitchen area 420-340 Ma bp. Our calculations suggest the kerogen was much more aliphatic and oil-prone after deposition than that after extensive exposure to radiation. In addition, the gas sorption capacity of the organic matter in the Alum Shale can be assumed to have been less developed during Palaeozoic times, in contrast to results gained by sorption experiments performed at the present day, for the same reason. The kerogen reconstruction method developed here precludes overestimations of gas generation and gas retention in the Alum Shale by taking irradiation exposure into account and can thus significantly mitigate charge risk when applied in the explorations for both conventional and unconventional hydrocarbons.

Methane baseline concentrations and sources in shallow aquifers from the shale gas-prone region of the St. Lawrence lowlands (Quebec, Canada).

PubMed

Moritz, Anja; Hélie, Jean-Francois; Pinti, Daniele L; Larocque, Marie; Barnetche, Diogo; Retailleau, Sophie; Lefebvre, René; Gélinas, Yves

2015-04-07

Hydraulic fracturing is becoming an important technique worldwide to recover hydrocarbons from unconventional sources such as shale gas. In Quebec (Canada), the Utica Shale has been identified as having unconventional gas production potential. However, there has been a moratorium on shale gas exploration since 2010. The work reported here was aimed at defining baseline concentrations of methane in shallow aquifers of the St. Lawrence Lowlands and its sources using δ(13)C methane signatures. Since this study was performed prior to large-scale fracturing activities, it provides background data prior to the eventual exploitation of shale gas through hydraulic fracturing. Groundwater was sampled from private (n = 81), municipal (n = 34), and observation (n = 15) wells between August 2012 and May 2013. Methane was detected in 80% of the wells with an average concentration of 3.8 ± 8.8 mg/L, and a range of <0.0006 to 45.9 mg/L. Methane concentrations were linked to groundwater chemistry and distance to the major faults in the studied area. The methane δ(1)(3)C signature of 19 samples was > -50‰, indicating a potential thermogenic source. Localized areas of high methane concentrations from predominantly biogenic sources were found throughout the study area. In several samples, mixing, migration, and oxidation processes likely affected the chemical and isotopic composition of the gases, making it difficult to pinpoint their origin. Energy companies should respect a safe distance from major natural faults in the bedrock when planning the localization of hydraulic fracturation activities to minimize the risk of contaminating the surrounding groundwater since natural faults are likely to be a preferential migration pathway for methane.

Four dimensional X-ray imaging of deformation modes in organic-rich Green River Shale retorted under uniaxial compression

NASA Astrophysics Data System (ADS)

Kobchenko, M.; Pluymakers, A.; Cordonnier, B.; Tairova, A.; Renard, F.

2017-12-01

Time-lapse imaging of fracture network development in organic-rich shales at elevated temperatures while kerogen is retorted allows characterizing the development of microfractures and the onset of primary migration. When the solid organic matter is transformed to hydrocarbons with lower molecular weight, the local pore-pressure increases and drives the propagation of hydro-fractures sub-parallel to the shale lamination. On the scale of samples of several mm size, these fractures can be described as mode I opening, where fracture walls dilate in the direction of minimal compression. However, so far experiments coupled to microtomography in situ imaging have been performed on samples where no load was imposed. Here, an external load was applied perpendicular to the sample laminations and we show that this stress state slows down, but does not stop, the propagation of fracture along bedding. Conversely, microfractures also propagate sub-perpendicular to the shale lamination, creating a percolating network in three dimensions. To monitor this process we have used a uniaxial compaction rig combined with in-situ heating from 50 to 500 deg C, while capturing three-dimensional X-ray microtomography scans at a voxel resolution of 2.2 μm; Data were acquired at beamline ID19 at the European Synchrotron Radiation Facility. In total ten time-resolved experiments were performed at different vertical loading conditions, with and without lateral passive confinement and different heating rates. At high external load the sample fails by symmetric bulging, while at lower external load the reaction-induced fracture network develops with the presence of microfractures both sub-parallel and sub-perpendicular to the bedding direction. In addition, the variation of experimental conditions allows the decoupling of the effects of the hydrocarbon decomposition reaction on the deformation process from the influence of thermal stress heating on the weakening and failure mode of immature shale.

Unconventional Tools for an Unconventional Resource: Community and Landscape Planning for Shale in the Marcellus Region

NASA Astrophysics Data System (ADS)

Murtha, T., Jr.; Orland, B.; Goldberg, L.; Hammond, R.

2014-12-01

Deep shale natural gas deposits made accessible by new technologies are quickly becoming a considerable share of North America's energy portfolio. Unlike traditional deposits and extraction footprints, shale gas offers dispersed and complex landscape and community challenges. These challenges are both cultural and environmental. This paper describes the development and application of creative geospatial tools as a means to engage communities along the northern tier counties of Pennsylvania, experiencing Marcellus shale drilling in design and planning. Uniquely combining physical landscape models with predictive models of exploration activities, including drilling, pipeline construction and road reconstruction, the tools quantify the potential impacts of drilling activities for communities and landscapes in the commonwealth of Pennsylvania. Dividing the state into 9836 watershed sub-basins, we first describe the current state of Marcellus related activities through 2014. We then describe and report the results of three scaled predictive models designed to investigate probable sub-basins where future activities will be focused. Finally, the core of the paper reports on the second level of tools we have now developed to engage communities in planning for unconventional gas extraction in Pennsylvania. Using a geodesign approach we are working with communities to transfer information for comprehensive landscape planning and informed decision making. These tools not only quantify physical landscape impacts, but also quantify potential visual, aesthetic and cultural resource implications.

A framework to predict the impacts of shale gas infrastructures on the forest fragmentation of an agroforest region.

PubMed

Racicot, Alexandre; Babin-Roussel, Véronique; Dauphinais, Jean-François; Joly, Jean-Sébastien; Noël, Pascal; Lavoie, Claude

2014-05-01

We propose a framework to facilitate the evaluation of the impacts of shale gas infrastructures (well pads, roads, and pipelines) on land cover features, especially with regards to forest fragmentation. We used a geographic information system and realistic development scenarios largely inspired by the PA (United States) experience, but adapted to a region of QC (Canada) with an already fragmented forest cover and a high gas potential. The scenario with the greatest impact results from development limited by regulatory constraints only, with no access to private roads for connecting well pads to the public road network. The scenario with the lowest impact additionally integrates ecological constraints (deer yards, maple woodlots, and wetlands). Overall the differences between these two scenarios are relatively minor, with <1 % of the forest cover lost in each case. However, large areas of core forests would be lost in both scenarios and the number of forest patches would increase by 13-21 % due to fragmentation. The pipeline network would have a much greater footprint on the land cover than access roads. Using data acquired since the beginning of the shale gas industry, we show that it is possible, within a reasonable time frame, to produce a robust assessment of the impacts of shale gas extraction. The framework we propose could easily be applied to other contexts or jurisdictions.

Controls on Methane Occurrences in Aquifers Overlying the Eagle Ford Shale Play, South Texas.

PubMed

Nicot, Jean-Philippe; Larson, Toti; Darvari, Roxana; Mickler, Patrick; Uhlman, Kristine; Costley, Ruth

2017-07-01

Assessing natural vs. anthropogenic sources of methane in drinking water aquifers is a critical issue in areas of shale oil and gas production. The objective of this study was to determine controls on methane occurrences in aquifers in the Eagle Ford Shale play footprint. A total of 110 water wells were tested for dissolved light alkanes, isotopes of methane, and major ions, mostly in the eastern section of the play. Multiple aquifers were sampled with approximately 47 samples from the Carrizo-Wilcox Aquifer (250-1200 m depth range) and Queen City-Sparta Aquifer (150-900 m depth range) and 63 samples from other shallow aquifers but mostly from the Catahoula Formation (depth <150 m). Besides three shallow wells with unambiguously microbial methane, only deeper wells show significant dissolved methane (22 samples >1 mg/L, 10 samples >10 mg/L). No dissolved methane samples exhibit thermogenic characteristics that would link them unequivocally to oil and gas sourced from the Eagle Ford Shale. In particular, the well water samples contain very little or no ethane and propane (C1/C2+C3 molar ratio >453), unlike what would be expected in an oil province, but they also display relatively heavier δ 13 C methane (>-55‰) and δD methane (>-180‰). Samples from the deeper Carrizo and Queen City aquifers are consistent with microbial methane sourced from syndepositional organic matter mixed with thermogenic methane input, most likely originating from deeper oil reservoirs and migrating through fault zones. Active oxidation of methane pushes δ 13 C methane and δD methane toward heavier values, whereas the thermogenic gas component is enriched with methane owing to a long migration path resulting in a higher C1/C2+C3 ratio than in the local reservoirs. © 2017, National Ground Water Association.

Controls on Methane Occurrences in Shallow Aquifers Overlying the Haynesville Shale Gas Field, East Texas.

PubMed

Nicot, Jean-Philippe; Larson, Toti; Darvari, Roxana; Mickler, Patrick; Slotten, Michael; Aldridge, Jordan; Uhlman, Kristine; Costley, Ruth

2017-07-01

Understanding the source of dissolved methane in drinking-water aquifers is critical for assessing potential contributions from hydraulic fracturing in shale plays. Shallow groundwater in the Texas portion of the Haynesville Shale area (13,000 km 2 ) was sampled (70 samples) for methane and other dissolved light alkanes. Most samples were derived from the fresh water bearing Wilcox formations and show little methane except in a localized cluster of 12 water wells (17% of total) in a approximately 30 × 30 km 2 area in Southern Panola County with dissolved methane concentrations less than 10 mg/L. This zone of elevated methane is spatially associated with the termination of an active fault system affecting the entire sedimentary section, including the Haynesville Shale at a depth more than 3.5 km, and with shallow lignite seams of Lower Wilcox age at a depth of 100 to 230 m. The lignite spatial extension overlaps with the cluster. Gas wetness and methane isotope compositions suggest a mixed microbial and thermogenic origin with contribution from lignite beds and from deep thermogenic reservoirs that produce condensate in most of the cluster area. The pathway for methane from the lignite and deeper reservoirs is then provided by the fault system. © 2017, National Ground Water Association.

Multiscale properties of unconventional reservoir rocks

NASA Astrophysics Data System (ADS)

Woodruff, W. F.

A multidisciplinary study of unconventional reservoir rocks is presented, providing the theory, forward modeling and Bayesian inverse modeling approaches, and laboratory protocols to characterize clay-rich, low porosity and permeability shales and mudstones within an anisotropic framework. Several physical models characterizing oil and gas shales are developed across multiple length scales, ranging from microscale phenomena, e.g. the effect of the cation exchange capacity of reactive clay mineral surfaces on water adsorption isotherms, and the effects of infinitesimal porosity compaction on elastic and electrical properties, to meso-scale phenomena, e.g. the role of mineral foliations, tortuosity of conduction pathways and the effects of organic matter (kerogen and hydrocarbon fractions) on complex conductivity and their connections to intrinsic electrical anisotropy, as well as the macro-scale electrical and elastic properties including formulations for the complex conductivity tensor and undrained stiffness tensor within the context of effective stress and poroelasticity. Detailed laboratory protocols are described for sample preparation and measurement of these properties using spectral induced polarization (SIP) and ultrasonics for the anisotropic characterization of shales for both unjacketed samples under benchtop conditions and jacketed samples under differential loading. An ongoing study of the effects of kerogen maturation through hydrous pyrolysis on the complex conductivity is also provided in review. Experimental results are catalogued and presented for various unconventional formations in North America including the Haynesville, Bakken, and Woodford shales.

Creep Behavior of Posidonia Shale at Elevated Pressure and Temperature

NASA Astrophysics Data System (ADS)

Rybacki, E.; Herrmann, J.; Wirth, R.; Dresen, G.

2017-12-01

Unconventional reservoir rocks are usually stimulated by repeated hydraulic fracturing operations. However, the production rate often decays with time that may arise from creep-induced fracture closure by proppant embedment. To examine experimentally the creep behavior of shales, we deformed immature carbonate-rich Posidonia shale at constant stress conditions and elevated temperatures between 50° and 200°C and confining pressures of 50 to 200 MPa. Samples showed transient creep in the semibrittle regime with high deformation rates at high differential stress, high temperature, and low confinement. Strain was mainly accommodated by deformation of the weak organic matter and phyllosilicates and by pore space reduction. At relatively low stress the samples deformed in the primary creep regime with continuously decelerating strain rate. The relation between strain and time can be described by an empirical power law equation, where the fitted parameters vary with temperature, pressure and stress. Our results suggest that healing of hydraulic fractures at low stresses by creep-induced proppant embedment is unlikely within a creep period of several years. At high differential stress (85-90% of the triaxial strength), as may be expected in situ at contact areas due to stress concentrations, the shale showed secondary creep, followed by tertiary creep until failure. In this regime, stress corrosion may induce microcrack propagation and coalescence. Secondary creep rates were also described by a power law that predicts faster fracture closure rates than for primary creep and likely contributes to production rate decline. Comparison of our data with published primary creep data on other shales suggest that the long-term creep behavior of shales can be correlated to their brittleness estimated from composition. Low creep strain is supported by a high fraction of strong minerals that can build up a load-bearing framework.

Graptolite graveyard: Re-Os dating of macroplankton at the Lower-Middle Ordovician boundary (Floian-Dapingian stage boundary), Tøyen Shale, southern Sweden

NASA Astrophysics Data System (ADS)

Goswami, V.; Stein, H. J.; Hannah, J. L.; Ahlberg, P.; Maletz, J.

2017-12-01

There exist only 16 radiometric ages for the entire 42 m.y. Ordovician Period. Stage boundaries are biostratigraphically defined by the first appearance of agreed on graptolite and conodont species. Cosmopolitan graptolites are common in the Ordovician and their relatively brief stratigraphic durations make them ideal for global correlations. The Floian-Dapingian stage boundary (Lower-Middle Ordovician boundary) is very poorly constrained, with an absence of radiometric dates for several million years below the boundary and poor statistics on ages in the lower Dapingian [1]. Here we use the Ordovician Tøyen Shale, widespread across southern Sweden and Norway with a highly-refined graptolite biostratigraphy, to add a new age constraint [2]. With drill core from Lerhamn, Sweden (samples from 35.75-36.70 m depth), we employ a novel approach to directly date the fauna. We physically extracted a well-preserved 5-cm fossil of macroplankton (graptolite) from organic-rich shales (up to 4% TOC) for Re-Os dating. The graptolite and its hosting shale together define a well-constrained Model 1 isochron of 469.4 ± 1.7 Ma (2s, MSWD = 1.7, n = 9) and an initial 187Os/188Os (Osi) of 0.802 ± 0.002 for seawater. The Osi documents sustained radiogenic Os input to seawater from the Neoproterozoic-Cambrian through the Early Ordovician, in concert with the Sr isotope seawater curve. The analyzed graptolite belongs to the species Pseudophyllograptus augustifolius, a member of the upper Floian fauna [2]. Our nominal age for the dated graptolite and the shale is lower Dapingian according to the 2017 GTS [1]. Therefore, the Re-Os age suggests the Floian-Dapingian stage boundary may be younger than currently accepted. As defined in the GTS, the Dapingian stage is only 2.7 m.y. (470.0 ± 1.4 to 467.3 ± 1.1 Ma); combined uncertainties could give the Dapingian a mere 0.2 m.y. duration (or a maximum of 5 m.y). Although uncertainties overlap, our first dating of the Lower-Middle Ordovician boundary suggests the Floian-Dapingian stage boundary may be somewhat younger, potentially shortening the duration of the Dapingian by 20% or more. Funding - NSF EAR0745946 and The Gyllenstierna Krapperuṕs Foundation [1] Cooper and Sadler, 2012, in The Geologic Time Scale (GTS)[2] Maletz and Ahlberg, 2011, Lethaia, DOI: 10.1111/j.1502-3931.2010.00246.x

Influence of Mineralogy, Pressure, Temperature and Stress on Mechanical roperties of shale Rocks

NASA Astrophysics Data System (ADS)

Herrmann, J.; Rybacki, E.; Sone, H.; Dresen, G. H.

2017-12-01

The production of hydrocarbons from unconventional reservoirs, like tight shale plays increased tremendously over the past decade. Hydraulic fracturing is a common method to increase the productivity of a well drilled in these reservoirs. Unfortunately, the production rate decreases over time presumably due to fracture healing. The healing rate induced by proppant embedment depends on pressure (p), temperature (T), stress (σ) - conditions and on shale composition. To improve understanding of the influence of these parameters on fracture healing, we conducted constant strain rate experiments (p = 50 - 100 MPa, T = 50 - 125 °C, ɛ/t = 5 * 10-4 - 5 * 10-6 s-1) on porous ( 8 %), quartz - rich ( 72 vol %) Bowland shale (UK) and on low porosity ( 3 %), clay - rich ( 33 vol %) Posidonia shale (GER), deformed perpendicular to bedding and with as-is water content. Bowland shale showed mainly brittle behaviour with predominantly elastic deformation before failure and a high strength (280 - 350 MPa). In contrast, Posidonia shale deformed semibrittle with pronounced inelastic deformation and low peak strength (165 - 220 MPa). For both shale rocks, static Young's moduli vary between 12 - 18 GPa. In addition, we performed a series of constant stress tests on both shales at p = 30 - 115 MPa, T = 75 - 150 °C and σ = 160 - 450 MPa. Samples showed transient (primary) creep with increasing strain rates for increasing temperature and stress and decreasing pressure. An empirical power law in the form of ɛ = A*tm is used to describe the observed relation between inelastic strain (ɛ) and time (t), where the constant A is mainly affected by temperature and stress and the exponent m accounts for the influence of pressure. Compared to quartz - rich, strong Bowland shale, the creep behaviour of clay - rich, weak Posidonia shale is much more sensitive to changes in pressure, temperature and stress. Electron microscopy suggests that creep was mainly accommodated by deformation of weak phases (TOC, clay, mica). Our results suggest a low fracture healing rate of Bowland shale, whereas fractures within the Posidonia formation tend to close faster.

Acidization of shales with calcite cemented fractures

NASA Astrophysics Data System (ADS)

Kwiatkowski, Kamil; Szymczak, Piotr; Jarosiński, Marek

2017-04-01

Investigation of cores drilled from shale formations reveals a relatively large number of calcite-cemented fractures. Usually such fractures are reactivated during fracking and can contribute considerably to the permeability of the resulting fracture network. However, calcite coating on their surfaces effectively excludes them from production. Dissolution of the calcite cement by acidic fluids is investigated numerically with focus on the evolution of fracture morphology. Available surface area, breakthrough time, and reactant penetration length are calculated. Natural fractures in cores from Pomeranian shale formation (northern Poland) were analyzed and classified. Representative fractures are relatively thin (0.1 mm), flat and completely sealed with calcite. Next, the morphology evolution of reactivated natural fractures treated with low-pH fluids has been simulated numerically under various operating conditions. Depth-averaged equations for fracture flow and reactant transport has been solved by finite-difference method coupled with sparse-matrix solver. Transport-limited dissolution has been considered, which corresponds to the treatment with strong acids, such as HCl. Calcite coating in reactivated natural fractures dissolves in a highly non-homogeneous manner - a positive feedback between fluid transport and calcite dissolution leads to the spontaneous formation of wormhole-like patterns, in which most of the flow is focused. The wormholes carry reactive fluids deeper inside the system, which dramatically increases the range of the treatment. Non-uniformity of the dissolution patterns provides a way of retaining the fracture permeability even in the absence of the proppant, since the less dissolved regions will act as supports to keep more dissolved regions open. Evolution of fracture morphology is shown to depend strongly on the thickness of calcite layer - the thicker the coating the more pronounced wormholes are observed. However the interaction between wormholes is the strongest when coating thickness is a few times larger than the initial aperture of the fracture. This leads to formation of favorable complex networks of wormholes which provide adequate transport of reactive fluids to fracture surfaces and - at the same time - are capable of supporting fracture surfaces. As a conclusion, acidization of the reactivated fractures with hydrochloric acid seems to be an attractive treatment to apply at fracking stage or later on as EGR. The results contribute to the discussion on the use of acidization to enhance the gas production in the shale reservoirs. This communication stresses the importance of the dissolution of calcite cement in natural fractures in shale formations, which are initially sealed and become reactivated during fracking. While this research is based on the analysis of fractures in the Pomeranian shale basin its results are general enough to be applicable to different formations worldwide.

Adsorption of xenon and krypton on shales

NASA Technical Reports Server (NTRS)

Podosek, F. A.; Bernatowicz, T. J.; Kramer, F. E.

1981-01-01

A method that uses a mass spectrometer as a manometer is employed in the measurement of Xe and Kr adsorption parameters on shales and related samples, where gas partial pressures were lower than 10 to the -11th atm, corresponding adsorption coverages are only small fractions of a monolayer, and Henry's Law behavior is expected and observed. Results show heats of adsorption in the 2-7 kcal/mol range, and Henry constants at 0-25 C of 1 cu cm STP/g per atmosphere are extrapolated. Although the adsorption properties obtained are variable by sample, the range obtained suggests that shales may be capable of an equilibrium adsorption with modern air high enough to account for a significant fraction of the atmospheric inventory of Xe, and perhaps even of Kr. This effect will nevertheless not account for the factor-of-25 defficiency of atmospheric Xe, in comparison with the planetary gas patterns observed in meteorites.

Community-based risk assessment of water contamination from high-volume horizontal hydraulic fracturing.

PubMed

Penningroth, Stephen M; Yarrow, Matthew M; Figueroa, Abner X; Bowen, Rebecca J; Delgado, Soraya

2013-01-01

The risk of contaminating surface and groundwater as a result of shale gas extraction using high-volume horizontal hydraulic fracturing (fracking) has not been assessed using conventional risk assessment methodologies. Baseline (pre-fracking) data on relevant water quality indicators, needed for meaningful risk assessment, are largely lacking. To fill this gap, the nonprofit Community Science Institute (CSI) partners with community volunteers who perform regular sampling of more than 50 streams in the Marcellus and Utica Shale regions of upstate New York; samples are analyzed for parameters associated with HVHHF. Similar baseline data on regional groundwater comes from CSI's testing of private drinking water wells. Analytic results for groundwater (with permission) and surface water are made publicly available in an interactive, searchable database. Baseline concentrations of potential contaminants from shale gas operations are found to be low, suggesting that early community-based monitoring is an effective foundation for assessing later contamination due to fracking.

Anisotropic Failure Strength of Shale with Increasing Confinement: Behaviors, Factors and Mechanism.

PubMed

Cheng, Cheng; Li, Xiao; Qian, Haitao

2017-11-15

Some studies reported that the anisotropic failure strength of shale will be weakened by increasing confinement. In this paper, it is found that there are various types of anisotropic strength behaviors. Four types of anisotropic strength ratio ( S A 1 ) behaviors and three types of anisotropic strength difference ( S A 2 ) behaviors have been classified based on laboratory experiments on nine groups of different shale samples. The cohesion c w and friction angle ϕ w of the weak planes are proven to be two dominant factors according to a series of bonded-particle discrete element modelling analyses. It is observed that shale is more prone to a slight increase of S A 1 and significant increase of S A 2 with increasing confinement for higher cohesion c w and lower to medium friction angle ϕ w . This study also investigated the mechanism of the anisotropic strength behaviors with increasing confinement. Owing to different contributions of c w and ϕ w under different confinements, different combinations of c w and ϕ w may have various types of influences on the minimum failure strength with the increasing confinement; therefore, different types of anisotropic behaviors occur for different shale specimens as the confinement increases. These findings are very important to understand the stability of wellbore and underground tunneling in the shale rock mass, and should be helpful for further studies on hydraulic fracture propagations in the shale reservoir.

Empirically assessing the potential release of rare earth elements from black shale under simulated hydraulic fracturing conditions

DOE PAGES

Yang, Jon; Verba, Circe; Torres, Marta; ...

2018-02-01

Rare earth elements (REEs) are economically important to modern society and the rapid growth of technologies dependent on REEs has placed considerable economic pressure on their sourcing. This study addresses whether REEs could be released as a byproduct of natural gas extraction from a series of experiments that were designed to simulate hydraulic fracturing of black shale under various pressure (25 and 27.5 MPa) and temperature (50, 90, 130 °C) conditions. The dissolved REEs in the reacted fluids displayed no propensity for the REEs to be released from black shale under high pressure and temperature conditions, a result that ismore » consistent across the different types of fluids investigated. Overall, there was a net loss of REEs from the fluid. These changes in dissolved REEs were greatest at the moment the fluids first contacted the shale and before the high temperature and high pressure conditions were imposed, although the magnitude of these changes (10 -4 μg/g) were small compared to the magnitude of the total REE content present in the solid shale samples (10 2 μg/g). These results highlight the variability and complexity of hydraulic fracturing systems and indicate that REE may not serve as robust tracers for fracturing fluid-shale reactions. Additionally, the results suggest that significant quantities of REEs may not be byproducts of hydraulically fractured shales.« less

Empirically assessing the potential release of rare earth elements from black shale under simulated hydraulic fracturing conditions

DOE Office of Scientific and Technical Information (OSTI.GOV)

Yang, Jon; Verba, Circe; Torres, Marta

Rare earth elements (REEs) are economically important to modern society and the rapid growth of technologies dependent on REEs has placed considerable economic pressure on their sourcing. This study addresses whether REEs could be released as a byproduct of natural gas extraction from a series of experiments that were designed to simulate hydraulic fracturing of black shale under various pressure (25 and 27.5 MPa) and temperature (50, 90, 130 °C) conditions. The dissolved REEs in the reacted fluids displayed no propensity for the REEs to be released from black shale under high pressure and temperature conditions, a result that ismore » consistent across the different types of fluids investigated. Overall, there was a net loss of REEs from the fluid. These changes in dissolved REEs were greatest at the moment the fluids first contacted the shale and before the high temperature and high pressure conditions were imposed, although the magnitude of these changes (10 -4 μg/g) were small compared to the magnitude of the total REE content present in the solid shale samples (10 2 μg/g). These results highlight the variability and complexity of hydraulic fracturing systems and indicate that REE may not serve as robust tracers for fracturing fluid-shale reactions. Additionally, the results suggest that significant quantities of REEs may not be byproducts of hydraulically fractured shales.« less

Anisotropic Failure Strength of Shale with Increasing Confinement: Behaviors, Factors and Mechanism

PubMed Central

Cheng, Cheng; Li, Xiao; Qian, Haitao

2017-01-01

Some studies reported that the anisotropic failure strength of shale will be weakened by increasing confinement. In this paper, it is found that there are various types of anisotropic strength behaviors. Four types of anisotropic strength ratio (SA1) behaviors and three types of anisotropic strength difference (SA2) behaviors have been classified based on laboratory experiments on nine groups of different shale samples. The cohesion cw and friction angle ϕw of the weak planes are proven to be two dominant factors according to a series of bonded-particle discrete element modelling analyses. It is observed that shale is more prone to a slight increase of SA1 and significant increase of SA2 with increasing confinement for higher cohesion cw and lower to medium friction angle ϕw. This study also investigated the mechanism of the anisotropic strength behaviors with increasing confinement. Owing to different contributions of cw and ϕw under different confinements, different combinations of cw and ϕw may have various types of influences on the minimum failure strength with the increasing confinement; therefore, different types of anisotropic behaviors occur for different shale specimens as the confinement increases. These findings are very important to understand the stability of wellbore and underground tunneling in the shale rock mass, and should be helpful for further studies on hydraulic fracture propagations in the shale reservoir. PMID:29140292

Core-Log-Seismic Integrative Study of a Subduction Zone Megasplay Fault -An Example from the Nobeoka Thrust, Shimanto Belt, Southwest Japan

NASA Astrophysics Data System (ADS)

Hamahashi, M.; Tsuji, T.; Saito, S.; Tanikawa, W.; Hamada, Y.; Hashimoto, Y.; Kimura, G.

2016-12-01

Investigating the mechanical properties and deformation patterns of megathrusts in subduction zones is important to understand the generation of large earthquakes. The Nobeoka Thrust, a fossilized megasplay fault in Kyushu Shimanto Belt, southwest Japan, exposes foliated fault rocks that were formed under the temperature range of 180-350° (Kondo et al., 2005). During the Nobeoka Thrust Drilling Project (2011), core samples and geophysical logging data were obtained recovering a continuous distribution of multiple fault zones, which provide the opportunity to examine their structure and physical properties in various scales (Hamahashi et al., 2013; 2015). By performing logging data analysis, discrete sample physical property measurements, and synthetic modeling of seismic reflections along the Nobeoka Thrust, we conducted core-log-seismic integrative study to characterize the effects of damage zone architecture and structural anisotropy towards the physical properties of the megasplay. A clear contrast in physical properties across the main fault core and surrounding damage zones were identified, where the fault rocks preserve the porosity of 4.8% in the hanging wall and 7.6% in the footwall, and P-wave velocity of 4.8 km/s and 4.2 km/s, respectively. Multiple sandstone-rich- and shale-rich damage zones were found from the drilled cores, in which velocity decreases significantly in the brecciated zones. The internal structure of these foliated fault rocks consist of heterogeneous lithology and texture, and velocity anisotropy ranges 1-18% (P-wave) and 1.5-80% (S-wave), affected by structural dip angle, foliation density, and sandstone/mudstone ratio. To evaluate the fault properties at the seismogenic depth, we developed velocity/earth models and synthetic modeling of seismic reflection using acoustic logs across the thrust and parameterized lithological and structural elements in the identified multiple damage zones.

Stratigraphic cross section of measured sections and drill holes of the Neslan Formation and adjacent formations, Book Cliffs Area, Colorado and Utah

USGS Publications Warehouse

Kirshbaum, Mark A.; Spear, Brianne D.

2012-01-01

This study updates a stratigraphic cross section published as plate 2 in Kirschbaum and Hettinger (2004) Digital Data Series 69-G (http://pubs.usgs.gov/dds/dds-069/dds-069-g/). The datum is a marine/tidal ravinement surface within the Cozzette Sandstone Member of the Iles Formation and the Thompson Canyon Sandstone and Sulphur Canyon Sandstone Beds of the Neslen Formation. One of the cores shown was included on the original cross section, and new core descriptions have been added to the upper part of the cored interval. A new core description (S178) is included in this report. Cores are stored in the U.S. Geological Survey Core Research Facility at the Denver Federal Center, Colorado. The following information has also been added to help define the stratigraphic framework: 1) At least five claystones interpreted as altered volcanic ashes have been identified and may give future workers a correlation tool within the largely continental section. 2) Thickness and general geometry of the Sego Sandstone, Buck Tongue of the Mancos Shale, and Castlegate Sandstone have been added to provide additional stratigraphic context. 3) The geometry in the Sego Sandstone, Buck Tongue of the Mancos Shale, and Castlegate Sandstone has been added to provide additional stratigraphic context. 4) Ammonite collections are from Gill and Hail. The zone of Didymoceras nebrascense projected into the East Salt Wash area is based on correlation of the flooding surface at the base of the Cozzette Member to this point as shown in Kirschbaum and Hettinger. 5) A leaf locality of the Denver Museum of Nature and Science is shown in its approximate stratigraphic position near Thompson Canyon. 6) A dinosaur locality of the Natural History Museum of Utah is shown in the Horse Canyon area measured section at the stratigraphic position where it was extracted.

PDC-bit performance under simulated borehole conditions

DOE Office of Scientific and Technical Information (OSTI.GOV)

Anderson, E.E.; Azar, J.J.

1993-09-01

Laboratory drilling tests were used to investigate the effects of pressure on polycrystalline-diamond-compact (PDC) drill-bit performance. Catoosa shale core samples were drilled with PDC and roller-cone bits at up to 1,750-psi confining pressure. All tests were conducted in a controlled environment with a full-scale laboratory drilling system. Test results indicate, that under similar operating conditions, increases in confining pressure reduce PDC-bit performance as much as or more than conventional-rock-bit performance. Specific energy calculations indicate that a combination of rock strength, chip hold-down, and bit balling may have reduced performance. Quantifying the degree to which pressure reduces PDC-bit performance will helpmore » researchers interpret test results and improve bit designs and will help drilling engineers run PDC bits more effectively in the field.« less

Geological fieldwork in the Libyan Sahara: A multidisciplinary approach

NASA Astrophysics Data System (ADS)

Meinhold, Guido; Whitham, Andrew; Howard, James P.; Morton, Andrew; Abutarruma, Yousef; Bergig, Khaled; Elgadry, Mohamed; Le Heron, Daniel P.; Paris, Florentin; Thusu, Bindra

2010-05-01

Libya is one of the most hydrocarbon-rich countries in the world. Its large oil and gas reserves make it attractive to international oil and gas companies, which provide the impetus for field-based research in the Libyan Sahara. North Africa is made up of several enormous intracratonic basins, two of which are found in southern Libya: the Murzuq Basin, in the southwest, and the Kufra Basin, in the southeast, separated by the Tibesti Massif. Both basins are filled with Palaeozoic and Mesozoic clastic sedimentary rocks reaching up to 5 km in thickness. These basins developed from the Cambrian onwards following an earlier period of orogenesis (the Panafrican Orogeny) in the Neoproterozoic. Precambrian metasediments and granitoids are unconformably overlain by Cambrian and Ordovician conglomerates and sandstones. They show a transitional environment from continental to shallow marine. Skolithos-bearing sandstone is common in Ordovician strata. By the Late Ordovician, ice masses had developed across West Gondwana. Upon melting of the ice sheets in the latest Hirnantian, large volumes of melt water and sediment were released that were transported to the periphery of Gondwana. In Libya, these sediments are predominantly highly mature sandstones, which, in many places, are excellent hydrocarbon reservoirs. Polished and striated surfaces in these sandstones clearly point to their glaciogenic origin. Following Late Ordovician deglaciation, black shale deposition occurred in the Silurian. Some of the shales are characterised by high values of total organic carbon (TOC). These shales are commonly referred to as ‘hot shales' due to their associated high uranium content, and are the major source rock for Early Palaeozoic-sourced hydrocarbons in North Africa. Late Ordovician glaciogenic sediments and the Early Silurian ‘hot shales' are therefore the main focus of geological research in the Libyan Sahara. Fluvial conglomerates and sandstones of Devonian age unconformably overlie these strata. Marine intervals occur in the Late Devonian, and the Carboniferous is characterised by shallow marine clastic sediments with carbonate horizons. Permian rocks are only known from subsurface drill cores and comprise continental and deltaic facies. The centre of the Murzuq Basin has been relatively well investigated by drilling and seismic profiles. The basin margins, however, lack detailed geological investigation. In comparison, the Kufra Basin is underexplored with few boreholes drilled. Our studies have focused on the eastern and northern margins of the Murzuq Basin and the northern, eastern and western margins of the Kufra Basin. The main objective of fieldwork has been to characterise the Infracambrian-Lower Palaeozoic stratigraphy, deduce the structural evolution of each study area, and to collect samples for follow-up analyses including provenance studies and biostratigraphy. In addition to outcrop-based fieldwork shallow boreholes up to 70 m depth were successfully drilled in the Early Silurian shales. The unweathered samples retrieved from two of the boreholes have been used for biostratigraphical and whole-rock geochemical investigations. The provenance study of the sandstone succession with conventional heavy mineral analysis together with U-Pb zircon dating provides, for the first time, an understanding of the ancient source areas. Because most of the Early Palaeozoic succession in southern Libya is barren of fossils, heavy mineral chemostratigraphy is moreover used as a correlation test on surface outcrops in the Kufra and Murzuq basins.

Quantification of Organic richness through wireline logs: a case study of Roseneath shale formation, Cooper basin, Australia

NASA Astrophysics Data System (ADS)

Ahmad, Maqsood; Iqbal, Omer; Kadir, Askury Abd

2017-10-01

The late Carboniferous-Middle Triassic, intracratonic Cooper basin in northeastern South Australia and southwestern Queensland is Australia's foremost onshore hydrocarbon producing region. The basin compromises Permian carbonaceous shale like lacustrine Roseneath and Murteree shale formation which is acting as source and reservoir rock. The source rock can be distinguished from non-source intervals by lower density, higher transit time, higher gamma ray values, higher porosity and resistivity with increasing organic content. In current dissertation we have attempted to compare the different empirical approaches based on density relation and Δ LogR method through three overlays of sonic/resistivity, neutron/resistivity and density/resistivity to quantify Total organic content (TOC) of Permian lacustrine Roseneath shale formation using open hole wireline log data (DEN, GR, CNL, LLD) of Encounter 1 well. The TOC calculated from fourteen density relations at depth interval between 3174.5-3369 meters is averaged 0.56% while TOC from sonic/resistivity, neutron/resistivity and density/resistivity yielded an average value of 3.84%, 3.68%, 4.40%. The TOC from average of three overlay method is yielded to 3.98%. According to geochemical report in PIRSA the Roseneath shale formation has TOC from 1 - 5 wt %.There is unpromising correlations observed for calculated TOC from fourteen density relations and measured TOC on samples. The TOC from average value of three overlays using Δ LogR method showed good correlation with measured TOC on samples.

A new laboratory approach to shale analysis using NMR relaxometry

USGS Publications Warehouse

Washburn, Kathryn E.; Birdwell, Justin E.; Baez, Luis; Beeney, Ken; Sonnenberg, Steve

2013-01-01

Low-field nuclear magnetic resonance (LF-NMR) relaxometry is a non-invasive technique commonly used to assess hydrogen-bearing fluids in petroleum reservoir rocks. Measurements made using LF-NMR provide information on rock porosity, pore-size distributions, and in some cases, fluid types and saturations (Timur, 1967; Kenyon et al., 1986; Straley et al., 1994; Brown, 2001; Jackson, 2001; Kleinberg, 2001; Hurlimann et al., 2002). Recent improvements in LF-NMR instrument electronics have made it possible to apply methods used to measure pore fluids to assess highly viscous and even solid organic phases within reservoir rocks. T1 and T2 relaxation responses behave very differently in solids and liquids; therefore the relationship between these two modes of relaxation can be used to differentiate organic phases in rock samples or to characterize extracted organic materials. Using T1-T2 correlation data, organic components present in shales, such as kerogen and bitumen, can be examined in laboratory relaxometry measurements. In addition, implementation of a solid-echo pulse sequence to refocus T2 relaxation caused by homonuclear dipolar coupling during correlation measurements allows for improved resolution of solid-phase protons. LF-NMR measurements of T1 and T2 relaxation time distributions were carried out on raw oil shale samples from the Eocene Green River Formation and pyrolyzed samples of these shales processed by hydrous pyrolysis and techniques meant to mimic surface and in-situ retorting. Samples processed using the In Situ Simulator approach ranged from bitumen and early oil generation through to depletion of petroleum generating potential. The standard T1-T2 correlation plots revealed distinct peaks representative of solid- and liquid-like organic phases; results on the pyrolyzed shales reflect changes that occurred during thermal processing. The solid-echo T1 and T2 measurements were used to improve assessment of the solid organic phases, specifically kerogen, thermally degraded kerogen, and char. Integrated peak areas from the LF-NMR results representative of kerogen and bitumen were found to be well correlated with S1 and S2 parameters from Rock-Eval programmed pyrolysis. This study demonstrates that LFNMR relaxometry can provide a wide range of information on shales and other reservoir rocks that goes well beyond porosity and pore-fluid analysis.

Water Saturation Relations and Their Diffusion-Limited Equilibration in Gas Shale: Implications for Gas Flow in Unconventional Reservoirs

DOE Office of Scientific and Technical Information (OSTI.GOV)

Tokunaga, Tetsu K.; Shen, Weijun; Wan, Jiamin

Large volumes of water are used for hydraulic fracturing of low permeability shale reservoirs to stimulate gas production, with most of the water remaining unrecovered and distributed in a poorly understood manner within stimulated regions. Because water partitioning into shale pores controls gas release, we measured the water saturation dependence on relative humidity (rh) and capillary pressure (P c) for imbibition (adsorption) as well as drainage (desorption) on samples of Woodford Shale. Experiments and modeling of water vapor adsorption into shale laminae at rh = 0.31 demonstrated that long times are needed to characterize equilibrium in larger (5 mm thick)more » pieces of shales, and yielded effective diffusion coefficients from 9 × 10 -9 to 3 × 10 -8 m 2 s -1, similar in magnitude to the literature values for typical low porosity and low permeability rocks. Most of the experiments, conducted at 50°C on crushed shale grains in order to facilitate rapid equilibration, showed significant saturation hysteresis, and that very large P c (~1 MPa) are required to drain the shales. These results quantify the severity of the water blocking problem, and suggest that gas production from unconventional reservoirs is largely associated with stimulated regions that have had little or no exposure to injected water. Finally, gravity drainage of water from fractures residing above horizontal wells reconciles gas production in the presence of largely unrecovered injected water, and is discussed in the broader context of unsaturated flow in fractures.« less

Water Saturation Relations and Their Diffusion-Limited Equilibration in Gas Shale: Implications for Gas Flow in Unconventional Reservoirs

DOE PAGES

Tokunaga, Tetsu K.; Shen, Weijun; Wan, Jiamin; ...

2017-11-15

Large volumes of water are used for hydraulic fracturing of low permeability shale reservoirs to stimulate gas production, with most of the water remaining unrecovered and distributed in a poorly understood manner within stimulated regions. Because water partitioning into shale pores controls gas release, we measured the water saturation dependence on relative humidity (rh) and capillary pressure (P c) for imbibition (adsorption) as well as drainage (desorption) on samples of Woodford Shale. Experiments and modeling of water vapor adsorption into shale laminae at rh = 0.31 demonstrated that long times are needed to characterize equilibrium in larger (5 mm thick)more » pieces of shales, and yielded effective diffusion coefficients from 9 × 10 -9 to 3 × 10 -8 m 2 s -1, similar in magnitude to the literature values for typical low porosity and low permeability rocks. Most of the experiments, conducted at 50°C on crushed shale grains in order to facilitate rapid equilibration, showed significant saturation hysteresis, and that very large P c (~1 MPa) are required to drain the shales. These results quantify the severity of the water blocking problem, and suggest that gas production from unconventional reservoirs is largely associated with stimulated regions that have had little or no exposure to injected water. Finally, gravity drainage of water from fractures residing above horizontal wells reconciles gas production in the presence of largely unrecovered injected water, and is discussed in the broader context of unsaturated flow in fractures.« less

The vertical hydraulic conductivity of an aquitard at two spatial scales

USGS Publications Warehouse

Hart, D.J.; Bradbury, K.R.; Feinstein, D.T.

2006-01-01

Aquitards protect underlying aquifers from contaminants and limit recharge to those aquifers. Understanding the mechanisms and quantity of ground water flow across aquitards to underlying aquifers is essential for ground water planning and assessment. We present results of laboratory testing for shale hydraulic conductivities, a methodology for determining the vertical hydraulic conductivity (Kv) of aquitards at regional scales and demonstrate the importance of discrete flow pathways across aquitards. A regional shale aquitard in southeastern Wisconsin, the Maquoketa Formation, was studied to define the role that an aquitard plays in a regional ground water flow system. Calibration of a regional ground water flow model for southeastern Wisconsin using both predevelopment steady-state and transient targets suggested that the regional Kv of the Maquoketa Formation is 1.8 ?? 10 -11 m/s. The core-scale measurements of the Kv of the Maquoketa Formation range from 1.8 ?? 10-14 to 4.1 ?? 10-12 m/s. Flow through some additional pathways in the shale, potential fractures or open boreholes, can explain the apparent increase of the regional-scale Kv. Based on well logs, erosional windows or high-conductivity zones seem unlikely pathways. Fractures cutting through the entire thickness of the shale spaced 5 km apart with an aperture of 50 microns could provide enough flow across the aquitard to match that provided by an equivalent bulk Kv of 1.8 ?? 10-11 m/s. In a similar fashion, only 50 wells of 0.1 m radius open to aquifers above and below the shale and evenly spaced 10 km apart across southeastern Wisconsin can match the model Kv. Copyright ?? 2005 National Ground Water Association.

Methane and benzene in drinking-water wells overlying the Eagle Ford, Fayetteville, and Haynesville Shale hydrocarbon production areas

USGS Publications Warehouse

McMahon, Peter B.; Barlow, Jeannie R.; Engle, Mark A.; Belitz, Kenneth; Ging, Patricia B.; Hunt, Andrew G.; Jurgens, Bryant; Kharaka, Yousif K.; Tollett, Roland W.; Kresse, Timothy M.

2017-01-01

Water wells (n = 116) overlying the Eagle Ford, Fayetteville, and Haynesville Shale hydrocarbon production areas were sampled for chemical, isotopic, and groundwater-age tracers to investigate the occurrence and sources of selected hydrocarbons in groundwater. Methane isotopes and hydrocarbon gas compositions indicate most of the methane in the wells was biogenic and produced by the CO2 reduction pathway, not from thermogenic shale gas. Two samples contained methane from the fermentation pathway that could be associated with hydrocarbon degradation based on their co-occurrence with hydrocarbons such as ethylbenzene and butane. Benzene was detected at low concentrations (<0.15 μg/L), but relatively high frequencies (2.4–13.3% of samples), in the study areas. Eight of nine samples containing benzene had groundwater ages >2500 years, indicating the benzene was from subsurface sources such as natural hydrocarbon migration or leaking hydrocarbon wells. One sample contained benzene that could be from a surface release associated with hydrocarbon production activities based on its age (10 ± 2.4 years) and proximity to hydrocarbon wells. Groundwater travel times inferred from the age-data indicate decades or longer may be needed to fully assess the effects of potential subsurface and surface releases of hydrocarbons on the wells.

Methane and Benzene in Drinking-Water Wells Overlying the Eagle Ford, Fayetteville, and Haynesville Shale Hydrocarbon Production Areas.

PubMed

McMahon, Peter B; Barlow, Jeannie R B; Engle, Mark A; Belitz, Kenneth; Ging, Patricia B; Hunt, Andrew G; Jurgens, Bryant C; Kharaka, Yousif K; Tollett, Roland W; Kresse, Timothy M

2017-06-20

Water wells (n = 116) overlying the Eagle Ford, Fayetteville, and Haynesville Shale hydrocarbon production areas were sampled for chemical, isotopic, and groundwater-age tracers to investigate the occurrence and sources of selected hydrocarbons in groundwater. Methane isotopes and hydrocarbon gas compositions indicate most of the methane in the wells was biogenic and produced by the CO 2 reduction pathway, not from thermogenic shale gas. Two samples contained methane from the fermentation pathway that could be associated with hydrocarbon degradation based on their co-occurrence with hydrocarbons such as ethylbenzene and butane. Benzene was detected at low concentrations (<0.15 μg/L), but relatively high frequencies (2.4-13.3% of samples), in the study areas. Eight of nine samples containing benzene had groundwater ages >2500 years, indicating the benzene was from subsurface sources such as natural hydrocarbon migration or leaking hydrocarbon wells. One sample contained benzene that could be from a surface release associated with hydrocarbon production activities based on its age (10 ± 2.4 years) and proximity to hydrocarbon wells. Groundwater travel times inferred from the age-data indicate decades or longer may be needed to fully assess the effects of potential subsurface and surface releases of hydrocarbons on the wells.

Alkaline modified oil shale fly ash: optimal synthesis conditions and preliminary tests on CO2 adsorption.

PubMed

Reinik, Janek; Heinmaa, Ivo; Kirso, Uuve; Kallaste, Toivo; Ritamäki, Johannes; Boström, Dan; Pongrácz, Eva; Huuhtanen, Mika; Larsson, William; Keiski, Riitta; Kordás, Krisztián; Mikkola, Jyri-Pekka

2011-11-30

Environmentally friendly product, calcium-silica-aluminum hydrate, was synthesized from oil shale fly ash, which is rendered so far partly as an industrial waste. Reaction conditions were: temperature 130 and 160°C, NaOH concentrations 1, 3, 5 and 8M and synthesis time 24h. Optimal conditions were found to be 5M at 130°C at given parameter range. Original and activated ash samples were characterized by XRD, XRF, SEM, EFTEM, (29)Si MAS-NMR, BET and TGA. Semi-quantitative XRD and MAS-NMR showed that mainly tobermorites and katoite are formed during alkaline hydrothermal treatment. Physical adsorption of CO(2) on the surface of the original and activated ash samples was measured with thermo-gravimetric analysis. TGA showed that the physical adsorption of CO(2) on the oil shale fly ash sample increases from 0.06 to 3-4 mass% after alkaline hydrothermal activation with NaOH. The activated product has a potential to be used in industrial processes for physical adsorption of CO(2) emissions. Copyright © 2011 Elsevier B.V. All rights reserved.

CT scanning and flow measurements of shale fractures after multiple shearing events

DOE PAGES

Crandall, Dustin; Moore, Johnathan; Gill, Magdalena; ...

2017-11-05

A shearing apparatus was used in conjunction with a Hassler-style core holder to incrementally shear fractured shale cores while maintaining various confining pressures. Computed tomography scans were performed after each shearing event, and were used to obtain information on evolving fracture geometry. Fracture transmissivity was measured after each shearing event to understand the hydrodynamic response to the evolving fracture structure. The digital fracture volumes were used to perform laminar single phase flow simulations (local cubic law with a tapered plate correction model) to qualitatively examine small scale flow path variations within the altered fractures. Fractures were found to generally increasemore » in aperture after several shear slip events, with corresponding transmissivity increases. Lower confining pressure resulted in a fracture more prone to episodic mechanical failure and sudden changes in transmissivity. Conversely, higher confining pressures resulted in a system where, after an initial setting of the fracture surfaces, changes to the fracture geometry and transmissivity occurred gradually. Flow paths within the fractures are largely controlled by the location and evolution of zero aperture locations. Lastly, a reduction in the number of primary flow pathways through the fracture, and an increase in their width, was observed during all shearing tests.« less

CT scanning and flow measurements of shale fractures after multiple shearing events

DOE Office of Scientific and Technical Information (OSTI.GOV)

Crandall, Dustin; Moore, Johnathan; Gill, Magdalena

A shearing apparatus was used in conjunction with a Hassler-style core holder to incrementally shear fractured shale cores while maintaining various confining pressures. Computed tomography scans were performed after each shearing event, and were used to obtain information on evolving fracture geometry. Fracture transmissivity was measured after each shearing event to understand the hydrodynamic response to the evolving fracture structure. The digital fracture volumes were used to perform laminar single phase flow simulations (local cubic law with a tapered plate correction model) to qualitatively examine small scale flow path variations within the altered fractures. Fractures were found to generally increasemore » in aperture after several shear slip events, with corresponding transmissivity increases. Lower confining pressure resulted in a fracture more prone to episodic mechanical failure and sudden changes in transmissivity. Conversely, higher confining pressures resulted in a system where, after an initial setting of the fracture surfaces, changes to the fracture geometry and transmissivity occurred gradually. Flow paths within the fractures are largely controlled by the location and evolution of zero aperture locations. Lastly, a reduction in the number of primary flow pathways through the fracture, and an increase in their width, was observed during all shearing tests.« less

Liquid-Rich Shale Potential of Utah’s Uinta and Paradox Basins: Reservoir Characterization and Development Optimization

DOE Office of Scientific and Technical Information (OSTI.GOV)

Vanden Berg, Michael; Morgan, Craig; Chidsey, Thomas

The enclosed report is the culmination of a multi-year and multi-faceted research project investigating Utah’s unconventional tight oil potential. From the beginning, the project team focused efforts on two different plays: (1) the basal Green River Formation’s (GRF) Uteland Butte unconventional play in the Uinta Basin and (2) the more established but understudied Cane Creek shale play in the Paradox Basin. The 2009-2014 high price of crude oil, coupled with lower natural gas prices, generated renewed interest in exploration and development of liquid hydrocarbon reserves. Following the success of the mid-2000s shale gas boom and employing many of the samemore » well completion techniques, petroleum companies started exploring for liquid petroleum in shale formations. In fact, many shales targeted for natural gas include areas in which the shale is more prone to liquid production. In Utah, organic-rich shales in the Uinta and Paradox Basins have been the source of significant hydrocarbon generation, with companies traditionally targeting the interbedded sands or carbonates for their conventional resource recovery. Because of the advances in horizontal drilling and hydraulic fracturing techniques, operators in these basins started to explore the petroleum production potential of the shale units themselves. The GRF in the Uinta Basin has been studied for over 50 years, since the first hydrocarbon discoveries. However, those studies focused on the many conventional sandstone reservoirs currently producing oil and gas. In contrast, less information was available about the more unconventional crude oil production potential of thinner carbonate/shale units, most notably the basal Uteland Butte member. The Cane Creek shale of the Paradox Basin has been a target for exploration periodically since the 1960s and produces oil from several small fields. The play generated much interest in the early 1990s with the successful use of horizontal drilling. Recently, the USGS assessed the undiscovered oil resource in the Cane Creek shale of the Paradox Basin at 103 million barrels at a 95 percent confidence level and 198 million barrels at a 50 percent confidence level. Nonetheless, limited research was available or published to further define the play and the reservoir characteristics. The specific objectives of the enclosed research were to (1) characterize geologic, geochemical, and geomechanical rock properties of target zones in the two designated basins by compiling data and by analyzing available cores, cuttings, and well logs; (2) describe outcrop reservoir analogs of GRF plays (Cane Creek shale is not exposed) and compare them to subsurface data; (3) map major regional trends for targeted intervals and identify “sweet spots” that have the greatest oil potential; (4) reduce exploration costs and drilling risks, especially in environmentally sensitive areas; (5) improve drilling and fracturing effectiveness by determining optimal well completion design; and (6) reduce field development costs, maximize oil recovery, and increase reserves. These objectives are all addressed in a series of nine publications that resulted from this extensive research project. Each publication is included in this report as an independent appendix.« less

Using SEM Analysis on Ion-Milled Shale Surface to Determine Shale-Fracturing Fluid Interaction

NASA Astrophysics Data System (ADS)

Lu, J.; Mickler, P. J.; Nicot, J. P.

2014-12-01

It is important to document and assess shale-fluid interaction during hydraulic fracturing (HF) in order to understand its impact on flowback water chemistry and rock property. A series of autoclave experiments were conducted to react shale samples from major oil and gas shales with synthetic HF containing various additives. To better determine mineral dissolution and precipitation at the rock-fluid interface, ion-milling technique was applied to create extremely flat rock surfaces that were examined before and after the autoclave experiments using a scanning electron microscope (SEM) coupled with energy dispersive spectroscopy (EDS) detectors. This method is able to reveal a level of detail not observable on broken surface or mechanically polished surface. It allows direct comparison of the same mineral and organic matter particles before and after the reaction experiments. Minerals undergone dissolution and newly precipitated materials are readily determined by comparing to the exact locations before reaction. The dissolution porosity and the thickness of precipitates can be quantified by tracing and measuring the geometry of the pores and precipitates. Changes in porosity and permeability were confirmed by mercury intrusion capillary tests.

The first data on the porous space structure of the Domanik shales as a potential object for EOR applying

NASA Astrophysics Data System (ADS)

Kadyrov, R.; Statsenko, E.

2018-05-01

The resources of shale oil, contained in the organic matter of the wood deposits, can be considered as a source of profitable production of hydrocarbons, when modern EOR technologies are used. As a result of the primary studies of the pore space structure, it is revealed that two types of porous space are prevailing in the studied samples of the Domanik oil shales. The most prevailing is intrakerogen porosity with pore volumes of 5 × 10-8 1 × 10-6 mm3. The volumetric reconstruction of the structure of this pore space shows that the voids are confined directly to micro lenses of organic matter. The second type of the found void is represented by leaching cracks. It is characteristic of more carbonate varieties of the Dominik oil shale with spotted structure. It is the oil shale intervals with such cracks that are of greatest interest to the EOR, since they consist of a large area with smaller pores and through which pressurization and spread of various agents are possible to occur in order to increase the oil recovery.

Subcritical fracturing of shales under chemically reactive conditions

NASA Astrophysics Data System (ADS)

Chen, X.; Callahan, O. A.; Eichhubl, P.; Olson, J. E.

2016-12-01

Growth of opening-mode fractures under chemically reactive subsurface conditions is potentially relevant for seal integrity in subsurface CO2 storage and hazardous waste disposal. Using double-torsion load relaxation tests we determine mode-I fracture toughness (KIC), subcritical index (SCI), and the stress-intensity factor vs fracture velocity (K-V) behavior of Marcellus, Woodford, and Mancos shales. Samples are tested under ambient air and aqueous conditions with variable NaCl and KCl concentrations, variable pH, and temperatures of up to 70. Under ambient air condition, KIC determined from double torsion tests is 1.3, 0.6, and 1.1 MPam1/2 for Marcellus, Woodford, and Mancos shales, respectively. SCI under ambient air condition is between 55 and 90 for the shales tested. Tests in aqueous solutions show a significant drop of KIC compared to ambient air condition. For tests in deionized water, KIC reduction is 18.5% for Marcellus and 47.0% for Woodford. The presence of aqueous fluids also results in a reduction of the SCI up to 85% compared to ambient condition. K-V curves generally obey a power-law relation throughout the load-relaxation period. However, aqueous-based tests on samples result in K-V curves deviating from the power-law relation, with the SCI values gradually decreasing with time during the relaxation period. This non-power-law behavior is obvious in Woodford and Mancos, but negligible in Marcellus. We find that the shales interact with the aqueous solution both at the fracture tip and within the rock matrix during subcritical fracturing. For Marcellus shale, water mainly interacts with the fracture tip on both tests due to low matrix permeability and less reactive mineral composition. However, Woodford and Mancos react strongly with water causing significant sample degradation. The competition between degradation and fracture growth results in the time-dependent SCI: at lower fracture velocities, the tip interacts longer with the chemically altered area around the tip; at higher fracture velocities, the fracture propagates through the altered area before significant degradation. Our results display strong weakening effects of chemically reactive fluids on subcritical fracture properties with implications on subsurface storage seal performance.

Thermal maturity patterns (conodont color alteration index and vitrinite reflectance) in Upper Ordovician and Devonian rocks of the Appalachian basin: a major revision of USGS Map I-917-E using new subsurface collections: Chapter F.1 in Coal and petroleum resources in the Appalachian basin: distribution, geologic framework, and geochemical character

USGS Publications Warehouse

Repetski, John E.; Ryder, Robert T.; Weary, David J.; Harris, Anita G.; Trippi, Michael H.; Ruppert, Leslie F.; Ryder, Robert T.

2014-01-01

The conodont color alteration index (CAI) introduced by Epstein and others (1977) and Harris and others (1978) is an important criterion for estimating the thermal maturity of Ordovician to Mississippian rocks in the Appalachian basin. Consequently, the CAI isograd maps of Harris and others (1978) are commonly used by geologists to characterize the thermal and burial history of the Appalachian basin and to better understand the origin and distribution of oil and gas resources in the basin. The main objectives of this report are to present revised CAI isograd maps for Ordovician and Devonian rocks in the Appalachian basin and to interpret the geologic and petroleum resource implications of these maps. The CAI isograd maps presented herein complement, and in some areas replace, the CAI-based isograd maps of Harris and others (1978) for the Appalachian basin. The CAI data presented in this report were derived almost entirely from subsurface samples, whereas the CAI data used by Harris and others (1978) were derived almost entirely from outcrop samples. Because of the different sampling methods, there is little geographic overlap of the two data sets. The new data set is mostly from the Allegheny Plateau structural province and most of the data set of Harris and others (1978) is from the Valley and Ridge structural province, east of the Allegheny structural front (fig. 1). Vitrinite reflectance, based on dispersed vitrinite in Devonian black shale, is another important parameter for estimating the thermal maturity in pre-Pennsylvanian-age rocks of the Appalachian basin (Streib, 1981; Cole and others, 1987; Gerlach and Cercone, 1993; Rimmer and others, 1993; Curtis and Faure, 1997). This chapter also presents a revised percent vitrinite reflectance (%R0) isograd map based on dispersed vitrinite recovered from selected Devonian black shales. The Devonian black shales used for the vitrinite studies reported herein also were analyzed by RockEval pyrolysis and total organic carbon (TOC) content in weight percent. Although the RockEval and TOC data are included in this chapter (table 1), they are not shown on the maps. The revised CAI isograd and percent vitrinite reflectance isograd maps cover all or parts of Kentucky, New York, Ohio, Pennsylvania, Virginia, and West Virginia (fig. 1), and the following three stratigraphic intervals: Upper Ordovician carbonate rocks, Lower and Middle Devonian carbonate rocks, and Middle and Upper Devonian black shales. These stratigraphic intervals were chosen for the following reasons: (1) they represent target reservoirs for much of the oil and gas exploration in the Appalachian basin; (2) they are stratigraphically near probable source rocks for most of the oil and gas; (3) they include geologic formations that are nearly continuous across the basin; (4) they contain abundant carbonate grainstone-packstone intervals, which give a reasonable to good probability of recovery of conodont elements from small samples of drill cuttings; and (5) the Middle and Upper Devonian black shale contains large amounts of organic matter for RockEval, TOC, and dispersed vitrinite analyses. Thermal maturity patterns of the Upper Ordovician Trenton Limestone are of particular interest here, because they closely approximate the thermal maturity patterns in the overlying Upper Ordovician Utica Shale, which is the probable source rock for oil and gas in the Upper Cambrian Rose Run Sandstone (sandstone), Upper Cambrian and Lower Ordovician Knox Group (Dolomite), Lower and Middle Ordovician Beekmantown Group (dolomite or Dolomite), Upper Ordovician Trenton and Black River Limestones, and Lower Silurian Clinton/Medina sandstone (Cole and others, 1987; Jenden and others, 1993; Laughrey and Baldassare, 1998; Ryder and others, 1998; Ryder and Zagorski, 2003). The thermal maturity patterns of the Lower Devonian Helderberg Limestone (Group), Middle Devonian Onondaga Limestone, and Middle Devonian Marcellus Shale-Upper Devonian Rhine street Shale Member-Upper Devonian Ohio Shale are of interest, because they closely approximate the thermal maturity patterns in the Marcellus Shale, Upper Devonian Rhinestreet Shale Member, and Upper Devonian Huron Member of the Ohio Shale, which are the most important source rocks for oil and gas in the Appalachian basin (de Witt and Milici, 1989; Klemme and Ulmishek, 1991). The Marcellus, Rhinestreet, and Huron units are black-shale source rocks for oil and (or) gas in the Lower Devonian Oriskany Sandstone, the Upper Devonian sandstones, the Middle and Upper Devonian black shales, and the Upper Devonian-Lower Mississippian(?) Berea Sandstone (Patchen and others, 1992; Roen and Kepferle, 1993; Laughrey and Baldassare, 1998).

Elemental composition of airborne dust in the Shale Shaker House during an offshore drilling operation.

PubMed

Hansen, A B; Larsen, E; Hansen, L V; Lyngsaae, M; Kunze, H

1991-12-01

During 2 days of an offshore drilling operation in the North Sea, 16 airborne dust samples from the atmosphere of the Shale Shaker House were collected onto filters. During this operation, drilling mud composed of a water slurry of barite (BaSO4) together with minor amounts of additives, among them chrome lignosulphonate and chrome lignite, was circulated between the borehole and the Shale Shaker House. The concentration of airborne dust in the atmosphere was determined and the elemental composition of the particles analysed by both PIXE (proton-induced X-ray emission) and ICP-MS (inductively coupled plasma-mass spectrometry). The total amount of dust collected varied from 0.04 to 1.41 mg m-3 with barium (Ba) as the single most abundant element. The open shale shakers turned out to be the major cause of generation of dust from the solid components of the drilling mud.

Permeability Evolution of Slowly Slipping Faults in Shale Reservoirs

NASA Astrophysics Data System (ADS)

Wu, Wei; Reece, Julia S.; Gensterblum, Yves; Zoback, Mark D.

2017-11-01

Slow slip on preexisting faults during hydraulic fracturing is a process that significantly influences shale gas production in extremely low permeability "shale" (unconventional) reservoirs. We experimentally examined the impacts of mineralogy, surface roughness, and effective stress on permeability evolution of slowly slipping faults in Eagle Ford shale samples. Our results show that fault permeability decreases with slip at higher effective stress but increases with slip at lower effective stress. The permeabilities of saw cut faults fully recover after cycling effective stress from 2.5 to 17.5 to 2.5 MPa and increase with slip at constant effective stress due to asperity damage and dilation associated with slip. However, the permeabilities of natural faults only partially recover after cycling effective stress returns to 2.5 MPa and decrease with slip due to produced gouge blocking fluid flow pathways. Our results suggest that slowly slipping faults have the potential to enhance reservoir stimulation in extremely low permeability reservoirs.

Alligator ridge district, East-Central Nevada: Carlin-type gold mineralization at shallow depths

USGS Publications Warehouse

Nutt, C.J.; Hofstra, A.H.

2003-01-01

Carlin-type deposits in the Alligator Ridge mining district are present sporadically for 40 km along the north-striking Mooney Basin fault system but are restricted to a 250-m interval of Devonian to Mississippian strata. Their age is bracketed between silicified ca. 45 Ma sedimentary rocks and unaltered 36.5 to 34 Ma volcanic rocks. The silicification is linked to the deposits by its continuity with ore-grade silicification in Devonian-Mississippian strata and by its similar ??18O values (_e1???17???) and trace element signature (As, Sb, Tl, Hg). Eocene reconstruction indicates that the deposits formed at depths of ???300 to 800 m. In comparison to most Carlin-type gold deposits, they have lower Au/Ag, Au grades, and contained Au, more abundant jasperoid, and textural evidence from deposition of an amorphous silica precursor in jasperoid. These differences most likely result from their shallow depth of formation. The peak fluid temperature (_e1???230??C) and large ??18OH2O value shift from the meteroric water line (_e1???20???) suggest that ore fluids were derived from depths of 8 km or more. A magnetotelluric survey indicates that the Mooney Basin fault system penetrates to mid-crustal depths. Deep circulation of meteoric water along the Mooney Basin fault system may have been in response to initial uplift of the East Humboldt-Ruby Mountains metamorphic core complex; convection also may have been promoted by increased heat flow associated with large magnitude extension in the core complex and regional magmatism. Ore fluids ascended along the fault system until they encountered impermeable Devonian and Mississippian shales, at which point they moved laterally through permeable strata in the Devonian Guilmette Formation, Devonian-Mississippian Pilot Shale, Mississippian Joana Limestone, and Mississippian Chainman Shale toward erosional windows where they ascended into Eocene fluvial conglomerates and lake sediments. Most gold precipitated by sulfidation of host-rock Fe and mixing with local ground water in zones of lateral fluid flow in reactive strata, such as the Lower Devonian-Mississippian Pilot Shale.

Importance of background values in assessing the impact of heavy metals in river ecosystems: case study of Tisza River, Serbia.

PubMed

Štrbac, Snežana; Kašanin Grubin, Milica; Vasić, Nebojša

2017-11-30

The main objective of this paper is to evaluate how a choice of different background values may affect assessing the anthropogenic heavy metal pollution in sediments from Tisza River (Serbia). The second objective of this paper is to underline significance of using geochemical background values when establishing quality criteria for sediment. Enrichment factor (EF), geoaccumulation index (I geo ), pollution load index (PLI), and potential ecological risk index (PERI) were calculated using different background values. Three geochemical (average metal concentrations in continental crust, average metal concentrations in shale, and average metal concentrations in non-contaminated core sediment samples) and two statistical methods (delineation method and principal component analyses) were used for calculating background values. It can be concluded that obtained information of pollution status can be more dependent on the use of background values than the index/factor chosen. The best option to assess the potential river sediment contamination is to compare obtained concentrations of analyzed elements with concentrations of mineralogically and texturally comparable, uncontaminated core sediment samples. Geochemical background values should be taken into account when establishing quality criteria for soils, sediments, and waters. Due to complexity of the local lithology, it is recommended that environmental monitoring and assessment include selection of an appropriate background values to gain understanding of the geochemistry and potential source of pollution in a given environment.

Oil-bearing sediments of Gondwana glaciation in Oman

DOE Office of Scientific and Technical Information (OSTI.GOV)

Levell, B.K.; Braakman, J.H.; Rutten, K.W.

1988-07-01

More than 3.5 billion bbl of oil in place have so far been discovered in reservoirs of the Al Khlata Formation of the Permian-Carboniferous lower Haushi Group in south Oman. Glacially striated pavements and boulders in exposures at Al Khlata in east-central Oman confirmed previous interpretations that the formation is, at least partly, of glacial origin. Core and wireline-log data from some 500 wells that penetrate the formation show that glacial facies are widespread in the subsurface. Shales with varvelike laminations and dropstones are present in two main layers, which extend over the larger part of south Oman and aremore » perhaps the most diagnostic facies. Diamictites are also widespread, and some, which can be correlated as sheets over thousands of square kilometers, are interpreted as true tillites. Other diamictites are interbedded with shales with varvelike laminations or unbedded siltstones and are interpreted as subaqueous glacial deposits. Ten sedimentary facies have been described in cores and outcrops. An important result of this study is a formal scheme to interpret these facies from wireline logs using quantitative analysis of density and neutron logs and qualitative information from other logs. Lateral facies relationships are complicated by syndepositional salt withdrawal and dissolution, paleorelief on the basal unconformity, and intraformational unconformities beneath regionally extensive tillites. At least three glacial phases can be recognized: an early phase, represented only by erosional remnants of diamictites, and two later phases, the last of which extended over the whole of Oman south of the Oman Mountains. Deglaciation is represented by a regional shale bed sharply overlying the diamictite sheet of this last glaciation. 19 figures, 1 table.« less

Effect of organic matter properties, clay mineral type and thermal maturity on gas adsorption in organic-rich shale systems

USGS Publications Warehouse

Zhang, Tongwei; Ellis, Geoffrey S.; Ruppel, Stephen C.; Milliken, Kitty; Lewan, Mike; Sun, Xun; Baez, Luis; Beeney, Ken; Sonnenberg, Steve

2013-01-01

A series of CH4 adsorption experiments on natural organic-rich shales, isolated kerogen, clay-rich rocks, and artificially matured Woodford Shale samples were conducted under dry conditions. Our results indicate that physisorption is a dominant process for CH4 sorption, both on organic-rich shales and clay minerals. The Brunauer–Emmett–Teller (BET) surface area of the investigated samples is linearly correlated with the CH4 sorption capacity in both organic-rich shales and clay-rich rocks. The presence of organic matter is a primary control on gas adsorption in shale-gas systems, and the gas-sorption capacity is determined by total organic carbon (TOC) content, organic-matter type, and thermal maturity. A large number of nanopores, in the 2–50 nm size range, were created during organic-matter thermal decomposition, and they significantly contributed to the surface area. Consequently, methane-sorption capacity increases with increasing thermal maturity due to the presence of nanopores produced during organic-matter decomposition. Furthermore, CH4 sorption on clay minerals is mainly controlled by the type of clay mineral present. In terms of relative CH4 sorption capacity: montmorillonite ≫ illite – smectite mixed layer > kaolinite > chlorite > illite. The effect of rock properties (organic matter content, type, maturity, and clay minerals) on CH4 adsorption can be quantified with the heat of adsorption and the standard entropy, which are determined from adsorption isotherms at different temperatures. For clay-mineral rich rocks, the heat of adsorption (q) ranges from 9.4 to 16.6 kJ/mol. These values are considerably smaller than those for CH4 adsorption on kerogen (21.9–28 kJ/mol) and organic-rich shales (15.1–18.4 kJ/mol). The standard entropy (Δs°) ranges from -64.8 to -79.5 J/mol/K for clay minerals, -68.1 to -111.3 J/mol/K for kerogen, and -76.0 to -84.6 J/mol/K for organic-rich shales. The affinity of CH4 molecules for sorption on organic matter is stronger than for most common clay minerals. Thus, it is expected that CH4 molecules may preferentially occupy surface sites on organic matter. However, active sites on clay mineral surfaces are easily blocked by water. As a consequence, organic-rich shales possess a larger CH4-sorption capacity than clay-rich rocks lacking organic matter. The thermodynamic parameters obtained in this study can be incorporated into model predictions of the maximum Langmuir pressure and CH4- sorption capacity of shales under reservoir temperature and pressure conditions.

Composition, diagenetic transformation and alkalinity potential of oil shale ash sediments.

PubMed

Mõtlep, Riho; Sild, Terje; Puura, Erik; Kirsimäe, Kalle

2010-12-15

Oil shale is a primary fuel in the Estonian energy sector. After combustion 45-48% of the oil shale is left over as ash, producing about 5-7 Mt of ash, which is deposited on ash plateaus annually almost without any reuse. This study focuses on oil shale ash plateau sediment mineralogy, its hydration and diagenetic transformations, a study that has not been addressed. Oil shale ash wastes are considered as the biggest pollution sources in Estonia and thus determining the composition and properties of oil shale ash sediment are important to assess its environmental implications and also its possible reusability. A study of fresh ash and drillcore samples from ash plateau sediment was conducted by X-ray diffractometry and scanning electron microscopy. The oil shale is highly calcareous, and the ash that remains after combustion is derived from the decomposition of carbonate minerals. It is rich in lime and anhydrite that are unstable phases under hydrous conditions. These processes and the diagenetic alteration of other phases determine the composition of the plateau sediment. Dominant phases in the ash are hydration and associated transformation products: calcite, ettringite, portlandite and hydrocalumite. The prevailing mineral phases (portlandite, ettringite) cause highly alkaline leachates, pH 12-13. Neutralization of these leachates under natural conditions, by rainwater leaching/neutralization and slow transformation (e.g. carbonation) of the aforementioned unstable phases into more stable forms, takes, at best, hundreds or even hundreds of thousands of years. Copyright © 2010 Elsevier B.V. All rights reserved.

Anisotropic and heterogeneous mechanical properties of a stratified shale/limestone sequence at Nash Point, South Wales: A case study for hydraulic fracture propagation through a layered medium

NASA Astrophysics Data System (ADS)

Forbes Inskip, Nathaniel; Meredith, Philip; Gudmundsson, Agust

2016-04-01

While considerable effort has been expended on the study of fracture propagation in rocks in recent years, our understanding of how fractures propagate through layered sedimentary rocks with different mechanical and elastic properties remains poorly constrained. Yet this is a key issue controlling the propagation of both natural and anthropogenic hydraulic fractures in layered sequences. Here we report measurements of the contrasting mechanical and elastic properties of the Lower Lias at Nash Point, South Wales, which comprises an interbedded sequence of shale and limestone layers, and how those properties may influence fracture propagation. Elastic properties of both materials have been characterised via ultrasonic wave velocity measurements as a function of azimuth on samples cored both normal and parallel to bedding. The shale is highly anisotropic, with P-wave velocities varying from 2231 to 3890 m s-1, giving an anisotropy of ~55%. By contrast, the limestone is essentially isotropic, with a mean P-wave velocity of 5828 m s-1 and an anisotropy of ~2%. The dynamic Young's modulus of the shale, calculated from P- and S-wave velocity data, is also anisotropic with a value of 36 GPa parallel to bedding and 12 GPa normal to bedding. The modulus of the limestone is again isotropic with a value of 80 GPa. It follows that for a vertical fracture propagating (i.e. normal to bedding) the modulus contrast is 6.6. This is important because the contrast in elastic properties is a key factor in controlling whether fractures arrest, deflect, or propagate across interfaces between layers in a sequence. There are three principal mechanisms by which a fracture may deflect across or along an interface, namely: Cook-Gordon debonding, stress barrier, and elastic mismatch. Preliminary numerical modelling results (using a Finite Element Modelling software) of induced fractures at Nash Point suggest that all three are important. The results demonstrate a rotation of the maximum principal compressive stress across an interface but also a confinement of tensile stress within the host layer. Mechanical properties have been characterised by indirect measurement of the tensile strength using the Brazil-Disk technique. Measurements were made in the three principal orientations relative to bedding, Arrester, Divider, and Short-Transverse, and also at 15° intervals between these planes. Values for the shale again showed a high degree of anisotropy; with similar values in the Arrester and Divider orientations, but with much lower values in the Short-Transverse (bedding parallel) orientation. The tensile strength of the limestone is considerably higher than that of the shale and exhibits no significant anisotropy. Current work is underway to characterise the fracture propagation properties by measuring the fracture toughness and fracture ductility of both rocks using a combination of the Semi-Circular Bend and Short-Rod techniques.

Tectonic setting of Jurassic basins in Central Mongolia: Insights from the geochemistry of Tsagaan-Ovoo oil shale

NASA Astrophysics Data System (ADS)

Erdenetsogt, B. O.; Hong, S. K.; Choi, J.; Odgerel, N.; Lee, I.; Ichinnorov, N.; Tsolmon, G.; Munkhnasan, B.

2017-12-01

Tsagaan-Ovoo syncline hosting Lower-Middle Jurassic oil shale is a part of Saikhan-Ovoo the largest Jurassic sedimentary basin in Central Mongolia. It is generally accepted that early Mesozoic basins are foreland basins. In total, 18 oil shale samples were collected from an open-pit mine. The contents of organic carbon, and total nitrogen and their isotopic compositions as well as major element concentrations were analyzed. The average TOC content is 12.4±1.2 %, indicating excellent source rock potential. C/N ratios show an average of 30.0±1.2, suggesting terrestrial OM. The average value of δ15N is +3.9±0.2‰, while that of δ13Corg is -25.7±0.1‰. The isotopic compositions argue for OM derived dominantly from land plant. Moreover, changes in δ15N values of analyzed samples reflect variations in algal OM concentration of oil shale. The lowest δ15N value (+2.5‰) was obtained from base section, representing the highest amount of terrestrial OM, whereas higher δ15N values (up to +5.2‰) are recorded at top section, reflecting increased amount of algal OM. On the other hand, changes in δ15N value may also represent changes in redox state of water column in paleolake. The oil shale at bottom of section with low δ15N value was accumulated under oxic condition, when the delivery of land plant OM was high. With increase in subsidence rate through time, lake was deepened and water column was depleted in oxygen probably due to extensive phytoplankton growth, which results increase in algae derived OM contents as well as bulk δ15N of oil shale. The average value of CAI for Tsagan-Ovoo oil shale is 81.6±1.3, reflecting intensive weathering in the source area. The plotted data on A-CN-K diagram displays that oil shale was sourced mainly from Early Permian granodiorite and diorite, which are widely distributed around Tsagaan-Ovoo syncline. To infer tectonic setting, two multi-dimensional discrimination diagrams were used. The results suggest that the tectonic setting of Tsagaan-Ovoo syncline, in which the studied oil shale was deposited, was continental rift. This finding contradicts with generally accepted contractile deformation during early Mesozoic in Mongolia and China. Further detailed study is required to decipher the tectonic settings of central Mongolian Jurassic basins.

Double torsion fracture mechanics testing of shales under chemically reactive conditions

NASA Astrophysics Data System (ADS)

Chen, X.; Callahan, O. A.; Holder, J. T.; Olson, J. E.; Eichhubl, P.

2015-12-01

Fracture properties of shales is vital for applications such as shale and tight gas development, and seal performance of carbon storage reservoirs. We analyze the fracture behavior from samples of Marcellus, Woodford, and Mancos shales using double-torsion (DT) load relaxation fracture tests. The DT test allows the determination of mode-I fracture toughness (KIC), subcritical crack growth index (SCI), and the stress-intensity factor vs crack velocity (K-V) curves. Samples are tested at ambient air and aqueous conditions with variable ionic concentrations of NaCl and CaCl2, and temperatures up to 70 to determine the effects of chemical/environmental conditions on fracture. Under ambient air condition, KIC determined from DT tests is 1.51±0.32, 0.85±0.25, 1.08±0.17 MPam1/2 for Marcellus, Woodford, and Mancos shales, respectively. Tests under water showed considerable change of KIC compared to ambient condition, with 10.6% increase for Marcellus, 36.5% decrease for Woodford, and 6.7% decrease for Mancos shales. SCI under ambient air condition is between 56 and 80 for the shales tested. The presence of water results in a significant reduction of the SCI from 70% to 85% compared to air condition. Tests under chemically reactive solutions are currently being performed with temperature control. K-V curves under ambient air conditions are linear with stable SCI throughout the load-relaxation period. However, tests conducted under water result in an initial cracking period with SCI values comparable to ambient air tests, which then gradually transition into stable but significantly lower SCI values of 10-20. The non-linear K-V curves reveal that crack propagation in shales is initially limited by the transport of chemical agents due to their low permeability. Only after the initial cracking do interactions at the crack tip lead to cracking controlled by faster stress corrosion reactions. The decrease of SCI in water indicates higher crack propagation velocity due to faster stress corrosion rate in water than in ambient air. The experimental results are applicable for the prediction of fracture initiation based on KIC, modeling fracture pattern based on SCI, and the estimation of dynamic fracture propagation such as crack growth velocity and crack re-initiation.

Impacts from above-ground activities in the eagle ford shale play on landscapes and hydrologic flows, La Salle County, Texas.

PubMed

Pierre, Jon Paul; Abolt, Charles J; Young, Michael H

2015-06-01

We assess the spatial and geomorphic fragmentation from the recent Eagle Ford Shale play in La Salle County, Texas, USA. Wells and pipelines were overlaid onto base maps of land cover, soil properties, vegetation assemblages, and hydrologic units. Changes to continuity of different ecoregions and supporting landscapes were assessed using the Landscape Fragmentation Tool (a third-party ArcGIS extension) as quantified by land area and continuity of core landscape areas (i.e., those degraded by "edge effects"). Results show decreases in core areas (8.7%; ~33,290 ha) and increases in landscape patches (0.2%; ~640 ha), edges (1.8%; ~6940 ha), and perforated areas (4.2%; ~16230 ha). Pipeline construction dominates landscape disturbance, followed by drilling and injection pads (85, 15, and 0.03% of disturbed area, respectively). An increased potential for soil loss is indicated, with 51% (~5790 ha) of all disturbance regimes occurring on soils with low water-transmission rates (depth to impermeable layer less than 50 cm) and a high surface runoff potential (hydrologic soil group D). Additionally, 88% (~10,020 ha) of all disturbances occurred on soils with a wind erodibility index of approximately 19 kt/km(2)/year (0.19 kt/ha/year) or higher, resulting in an estimated potential of 2 million tons of soil loss per year. Results demonstrate that infrastructure placement is occurring on soils susceptible to erosion while reducing and splitting core areas potentially vital to ecosystem services.

A magmatic-hydrothermal lacustrine exhalite from the Permian Lucaogou Formation, Santanghu Basin, NW China - The volcanogenic origin of fine-grained clastic sedimentary rocks

NASA Astrophysics Data System (ADS)

Jiao, Xin; Liu, Yiqun; Yang, Wan; Zhou, Dingwu; Li, Hong; Nan, Yun; Jin, Mengqi

2018-05-01

Shales in the middle Permian Lucaogou Formation in the intracontinental Santanghu rift basin have been considered as "typical" organic-rich profundal shales for decades. Our study of well cores using petrographic microscope and scanning electron microscopy suggests an otherwise complex hydrovolcanic and hydrothermal origin. This paper describes characteristics of a particular type of the shales, composed of fine-grained detrital minerals and lithic grains. Some of them are orthopyroxene, calcite, peralkaline feldspars, and analcime that are interpreted as derived from peralkaline-alkaline carbonatite, pyroxenite, analcime phonolite, and andesite, whereas others are quartz, dolomite, ankerite, serpentine, and calcite that were precipitated from syndepositional or penecontemporary hydrothermal fluids. Grain size ranges from 0.001 to 2 mm, mostly 0.01-0.1 mm. Well-developed laminae are mostly 0.5-3 mm thick and alternate with tuffaceous dolomicrite. The rocks are interpreted as sublacustrine hydrovolcanic deposits, which had been altered by syndepositional hydrothermal fluids. The interpretation is substantiated by abundant cone-shaped stratigraphic buildups on seismic sections in the basin. This study shows an ancient example of volcanic-hydrothermal deposits in a rift basin.

Integrating SANS and fluid-invasion methods to characterize pore structure of typical American shale oil reservoirs.

PubMed

Zhao, Jianhua; Jin, Zhijun; Hu, Qinhong; Jin, Zhenkui; Barber, Troy J; Zhang, Yuxiang; Bleuel, Markus

2017-11-13

An integration of small-angle neutron scattering (SANS), low-pressure N 2 physisorption (LPNP), and mercury injection capillary pressure (MICP) methods was employed to study the pore structure of four oil shale samples from leading Niobrara, Wolfcamp, Bakken, and Utica Formations in USA. Porosity values obtained from SANS are higher than those from two fluid-invasion methods, due to the ability of neutrons to probe pore spaces inaccessible to N 2 and mercury. However, SANS and LPNP methods exhibit a similar pore-size distribution, and both methods (in measuring total pore volume) show different results of porosity and pore-size distribution obtained from the MICP method (quantifying pore throats). Multi-scale (five pore-diameter intervals) inaccessible porosity to N 2 was determined using SANS and LPNP data. Overall, a large value of inaccessible porosity occurs at pore diameters <10 nm, which we attribute to low connectivity of organic matter-hosted and clay-associated pores in these shales. While each method probes a unique aspect of complex pore structure of shale, the discrepancy between pore structure results from different methods is explained with respect to their difference in measurable ranges of pore diameter, pore space, pore type, sample size and associated pore connectivity, as well as theoretical base and interpretation.

Prediction of total organic carbon content in shale reservoir based on a new integrated hybrid neural network and conventional well logging curves

NASA Astrophysics Data System (ADS)

Zhu, Linqi; Zhang, Chong; Zhang, Chaomo; Wei, Yang; Zhou, Xueqing; Cheng, Yuan; Huang, Yuyang; Zhang, Le

2018-06-01

There is increasing interest in shale gas reservoirs due to their abundant reserves. As a key evaluation criterion, the total organic carbon content (TOC) of the reservoirs can reflect its hydrocarbon generation potential. The existing TOC calculation model is not very accurate and there is still the possibility for improvement. In this paper, an integrated hybrid neural network (IHNN) model is proposed for predicting the TOC. This is based on the fact that the TOC information on the low TOC reservoir, where the TOC is easy to evaluate, comes from a prediction problem, which is the inherent problem of the existing algorithm. By comparing the prediction models established in 132 rock samples in the shale gas reservoir within the Jiaoshiba area, it can be seen that the accuracy of the proposed IHNN model is much higher than that of the other prediction models. The mean square error of the samples, which were not joined to the established models, was reduced from 0.586 to 0.442. The results show that TOC prediction is easier after logging prediction has been improved. Furthermore, this paper puts forward the next research direction of the prediction model. The IHNN algorithm can help evaluate the TOC of a shale gas reservoir.

Mapping thermal maturity in the Chainman shale, near Eureka, Nevada, with Landsat Thematic Mapper images

USGS Publications Warehouse

Rowan, L.C.; Pawlewicz, M.J.; Jones, O.D.

1992-01-01

The purpose of this study was to determine if there is a correlation between measurements of organic matter (OM) maturity and laboratory measurements of visible and near-infrared spectral reflectance, and if Landsat Thematic Mapper (TM) images could be used to map maturity. The maturity of Mississippian Chainman Shale samples collected in east-central Nevada and west-central Utah was determined by using vitrinite reflectance and Rock-Eval pyrolysis. TM 4/TM 5 values correspond well to vitrinite reflectance and hydrogen index variations, and therefore this ratio was used to evaluate a TM image of the Eureka, Nevada, area for mapping thermal maturity differences in the Chainman Shale. -from Authors

The Search for Biosignatures on Mars: Using Predictive Geology to Optimize Exploration Targets

NASA Technical Reports Server (NTRS)

Oehler, Dorothy Z.; Allen, Carlton C.

2011-01-01

Predicting geologic context from satellite data is a method used on Earth for exploration in areas with limited ground truth. The method can be used to predict facies likely to contain organic-rich shales. Such shales concentrate and preserve organics and are major repositories of organic biosignatures on Earth [1]. Since current surface conditions on Mars are unfavorable for development of abundant life or for preservation of organic remains of past life, the chances are low of encountering organics in surface samples. Thus, focusing martian exploration on sites predicted to contain organic-rich shales would optimize the chances of discovering evidence of life, if it ever existed on that planet.

Carbonate concretions as a significant component of ancient marine carbon cycles: Insights from paired organic and inorganic carbon isotope analyses of a Cretaceous shale

NASA Astrophysics Data System (ADS)

Loyd, S. J.

2014-12-01

Carbonate concretions often occur within fine-grained, organic-rich sedimentary rocks. This association reflects the common production of diagenetic minerals through biologic cycling of organic matter. Chemical analysis of carbonate concretions provides the rare opportunity to explore ancient shallow diagenetic environments, which are inherently transient due to progressive burial but are an integral component of the marine carbon cycle. The late Cretaceous Holz Shale (~80 Ma) contains abundant calcite concretions that exhibit textural and geochemical characteristics indicative of relatively shallow formation (i.e., near the sediment-water interface). Sampled concretions contain between 5.4 and 9.8 wt.% total inorganic carbon (TIC), or ~45 and 82 wt.% CaCO3, compared to host shale values which average ~1.5 wt.% TIC. Organic carbon isotope compositions (δ13Corg) are relatively constant in host and concretion samples ranging from ­-26.3 to -24.0‰ (VPDB). Carbonate carbon isotope compositions (δ13Ccarb) range from -22.5 to -3.4‰, indicating a significant but not entirely organic source of carbon. Concretions of the lower Holz Shale exhibit considerably elevated δ13Ccarb values averaging -4.8‰, whereas upper Holz Shale concretions express an average δ13Ccarb value of -17.0‰. If the remaining carbonate for lower Holz Shale concretions is sourced from marine fluids and/or dissolved marine carbonate minerals (e.g., shells), a simple mass balance indicates that ~28% of concretion carbon was sourced from organic matter and ~72% from late Cretaceous marine inorganic carbon (with δ13C ~ +2.5‰). Upper Holz Shale calculations indicate a ~73% contribution from organic matter and a ~27% contribution from inorganic carbon. When normalized for carbonate, organic contents within the concretions are ~2-13 wt.% enriched compared to host contents. This potentially reflects the protective nature of cementation that acts to limit permeability and chemical destruction of organic material. These data imply that concretion growth in shallow sediments can act as a significant and long-term sink for both marine inorganic and organic carbon.

Novel Experimental Techniques to Investigate Wellbore Damage Mechanisms

NASA Astrophysics Data System (ADS)

Choens, R. C., II; Ingraham, M. D.; Lee, M.; Dewers, T. A.

2017-12-01

A new experimental technique with unique geometry is presented investigating deformation of simulated boreholes using standard axisymmetric triaxial deformation equipment. The Sandia WEllbore SImulation, SWESI, geometry, uses right cylinders of rock 50mm in diameter and 75mm in length. A 11.3mm hole is drilled perpendicular to the axis of the cylinder in the center of the sample to simulate a borehole. The hole is covered with a solid metal cover, and sealed with polyurethane. The metal cover can be machined with a high-pressure port to introduce different fluid chemistries into the borehole at controlled pressures. Samples are deformed in a standard load frame under confinement, allowing for a broad range of possible stresses, load paths, and temperatures. Experiments in this study are loaded to the desired confining pressure, then deformed at a constant axial strain rate or 10-5 sec-1. Two different suites of experiments are conducted in this study on sedimentary and crystalline rock types. The first series of experiments are conducted on Mancos Shale, a finely laminated transversely isotropic rock. Samples are cored at three different orientations to the laminations. A second series of experiments is conducted on Sierra White granite with different fluid chemistries inside the borehole. Numerical modelling and experimental observations including CT-microtomography demonstrate that stresses are concentrated around the simulated wellbore and recreate wellbore deformation mechanisms. Borehole strength and damage development is dependent on anisotropy orientation and fluid chemistry. Observed failure geometries, particularly for Mancos shale, can be highly asymmetric. These results demonstrate uncertainties in in situ stresses measurements using commonly-applied borehole breakout techniques in complicated borehole physico-chemical environments. Sandia National Laboratories is a multimission laboratory managed and operated by National Technology and Engineering Solutions of Sandia LLC, a wholly owned subsidiary of Honeywell International Inc. for the U.S. Department of Energy's National Nuclear Security Administration under contract DE-NA0003525. SAND2017-8259 A

Experimental and natural constraints on the generation of calc-alkaline volcanic rocks in the Western Aleutian arc

NASA Astrophysics Data System (ADS)

Cottrell, E.; Kelley, K. A.; Grant, E.; Coombs, M. L.; Pistone, M.

2016-12-01

A new experimental technique with unique geometry is presented investigating deformation of simulated boreholes using standard axisymmetric triaxial deformation equipment. The Sandia WEllbore SImulation, SWESI, geometry, uses right cylinders of rock 50mm in diameter and 75mm in length. A 11.3mm hole is drilled perpendicular to the axis of the cylinder in the center of the sample to simulate a borehole. The hole is covered with a solid metal cover, and sealed with polyurethane. The metal cover can be machined with a high-pressure port to introduce different fluid chemistries into the borehole at controlled pressures. Samples are deformed in a standard load frame under confinement, allowing for a broad range of possible stresses, load paths, and temperatures. Experiments in this study are loaded to the desired confining pressure, then deformed at a constant axial strain rate or 10-5 sec-1. Two different suites of experiments are conducted in this study on sedimentary and crystalline rock types. The first series of experiments are conducted on Mancos Shale, a finely laminated transversely isotropic rock. Samples are cored at three different orientations to the laminations. A second series of experiments is conducted on Sierra White granite with different fluid chemistries inside the borehole. Numerical modelling and experimental observations including CT-microtomography demonstrate that stresses are concentrated around the simulated wellbore and recreate wellbore deformation mechanisms. Borehole strength and damage development is dependent on anisotropy orientation and fluid chemistry. Observed failure geometries, particularly for Mancos shale, can be highly asymmetric. These results demonstrate uncertainties in in situ stresses measurements using commonly-applied borehole breakout techniques in complicated borehole physico-chemical environments. Sandia National Laboratories is a multimission laboratory managed and operated by National Technology and Engineering Solutions of Sandia LLC, a wholly owned subsidiary of Honeywell International Inc. for the U.S. Department of Energy's National Nuclear Security Administration under contract DE-NA0003525. SAND2017-8259 A

Shale gas impacts on groundwater resources: insights from monitoring a fracking site in Poland

NASA Astrophysics Data System (ADS)

Montcoudiol, Nelly; Isherwood, Catherine; Gunning, Andrew; Kelly, Thomas; Younger, Paul

2017-04-01

Exploitation of shale gas by hydraulic fracturing (fracking) is highly controversial and concerns have been raised regarding induced risks from this technique. The SHEER project, an EU Horizon 2020-funded project, is looking into developing best practice to understand, prevent and mitigate the potential short- and long-term environmental impacts and risks from shale gas exploration and exploitation. Three major potential impacts were identified: groundwater contamination, air pollution and induced seismicity. This presentation will deal with the hydrogeological aspect. As part of the SHEER project, four monitoring wells were installed at a shale gas exploration site in Northern Poland. They intercept the main drinking water aquifer located in Quaternary sediments. Baseline monitoring was carried out from mid-December 2015 to beginning of June 2016. Fracking operations occurred in two horizontal wells, in two stages, in June and July 2016. The monitoring has continued after fracking was completed, with site visits every 4-6 weeks. Collected data include measurements of groundwater level, conductivity and temperature at 15-minute intervals, frequent sampling for laboratory analyses and field measurements of groundwater physico-chemical parameters. Groundwater samples are analysed for a range of constituents including dissolved gases and isotopes. The presentation will focus on the interpretation of baseline monitoring data. The insights gained into the behaviour of the Quaternary aquifer will allow a greater perspective to be place on the initial project understanding draw from previous studies. Short-term impacts will also be discussed in comparison with the baseline monitoring results. The presentation will conclude with discussion of challenges regarding monitoring of shale gas fracking sites.

Relationship between inferred redox potential of the depositional environment and geochemistry of the Upper Pennsylvanian (Missourian) Stark Shale Member of the Dennis Limestone, Wabaunsee County, Kansas, U.S.A.

USGS Publications Warehouse

Hatch, J.R.; Leventhal, J.S.

1992-01-01

Analyses of 21 samples collected from a core of the 52.8-cm-thick Stark Shale Member of the Dennis Limestone in Wabaunsee County, Kansas, demonstrate four cycles with two-orders-of-magnitude variations in contents of Cd, Mo, P, V and Zn, and order-of-magnitude variations in contents of organic carbon, Cr, Ni, Se and U. The observed variability in amounts and/or ratios of many metals and amounts and compositions of the organic matter appear related to the cause and degree of water-column stratification and the resulting absence/presence of dissolved O2 or H2S. High Cd, Mo, U, V, Zn and S contents, a high degree of pyritization (DOP) (0.75-0.88), and high high V (V + Ni) (0.84-0.89) indicate the presence of H2S in a strongly stratified water column. Intermediate contents of metals and S, intermediate DOP (0.67-0.75) and intermediate V (V + Ni) (054-0.82) indicate a less strongly stratified anoxic water column. Whereas, low metal contents and low V (V + Ni) (0.46-0.60) indicate a weakly stratified, dysoxic water column. High P contents at the top of the organic-matter-rich intervals within the Stark Shale Member indicate that phosphate precipitation was enhanced near the boundary between anoxic and dysoxic water compositions. Relatively abundant terrestrial organic matter in intervals deposited from the more strongly stratified H2S-bearing water column indicates a combined halocline-thermocline with the fresher near-surface water the transport mode for the terrestrial organic matter. The predominance of algal organic matter in intervals deposited from a less strongly stratified water column indicates the absence of the halocline and the presence of the more generally established thermocline. Relatively low amounts of degraded, hydrogen-poor organic matter characterize intervals deposited in a weakly stratified, dysoxic water column. The inferred variability in chemistry of the depositional environments may be related to climate variations and/or minor changes in sea level during the general phase of deeper water deposition responsible for this widespread shale member. ?? 1992.

Synchrotron X-ray Applications Toward an Understanding of Elastic Anisotropy

NASA Astrophysics Data System (ADS)

Kanitpanyacharoen, Waruntorn

The contribution of this dissertation is to expand the current knowledge of factors and mechanisms that influence the development of preferred orientation of minerlas and pores in different materials, ranging from rocks in Earth's crust to minerals in the deep Earth. Preferred orientation--a main contributing component to elastic anisotropy--is however very challenging to quantify. The overall focus of this thesis thus aims to (1) apply the capabilities of synchrotron X-ray techniques to determine preferred orientations of hexagonal metals and shales under different conditions and (2) enhance our understanding of their relationships to the elastic properties. Lattice preferred orientation (LPO) or 'texture' of hexagonal close-packed iron (hcp- Fe) crystals during deformation has been suggested as the cause of the elastic anisotropy observed in Earth's inner core. However, relatively little is known about LPO of other hcp metals. An investigation of a wide range of hcp metals (Cd, Zn, Os, and Hf) as analogs to hcp-Fe was thus undertaken to better understand deformation mechanisms at high pressure and temperature in Chapter 2. Results show that all hcp metals preferentially align their c-axes near the compression axis during deformation but with considerable differences. The gradual texture evolution in Cd and Zn is mainly controlled by basal slip systems while a rapid texture development in Os and Hf at ambient temperature is due to a dominant role of tensile twinning, with some degree of basal slip. At elevated temperature, tensile twinning is suppressed and texturing is governed by combined basal and prismatic slip. Under all conditions, basal slip appears to be the main deformation mechanism in hcp metals at high pressure and temperature. These findings are similar to those of hcp-Fe and useful to better understand the deformation mechanisms of hcp metals and their implications for elastic anisotropy. In Chapter 3, a high-energy synchrotron X-ray diffraction technique was applied to characterize LPO and phase proportions of Posidonia Shale collected in the Hils Syncline from Germany, in order to examine the influence of clay content, burial depth, and thermal history. The samples used in this study had experienced different local temperatures during burial and uplifting, as established by the maturity of kerogen (0.68-1.45% vitrinite reflectance, Ro), but their constituent clay minerals, including kaolinite, illite-mica, and illite-smectite, show similar degrees of LPO in all samples, ranging between 3.7 and 6.3 multiple of random distribution (m.r.d.). These observations imply that the difference in local thermal history, which significantly affects the maturity of kerogen, at most marginally influences LPO of clays, as the alignment of clays was established early in the history. In Chapter 4, the SPO of constituents phases in Kimmeridge Shale (North Sea, UK) and Barnett Shale (Gulf of Mexico, USA) was quantified to a resolution of ˜1 mum by using synchrotron X-ray microtomography (SXMT) technique. Measurements were done at different facilities (ALS, APS, and SLS) to characterize 3D microstructures, explore resolution limitations, and develop satisfactory procedures for data quantification. Segmentation images show that the SPO of low density features, including pores, fractures, and kerogen, is mostly anisotropic and oriented parallel to the bedding plane. Small pores are generally dispersed, whereas some large fractures and kerogen have irregular shapes and remain aligned horizontally. In contrast, pyrite exhibits no SPO. The volume fractions and aspect ratios of low density features extracted from three synchrotron sources show excellent agreement with 6.3(6)% for Kimmeridge Shale and 4.5(4)% for Barnett Shale. A small variation is mainly due to differences of optical instruments and technical setups. The SXMT is proven to be a crucial technique to investigate 3D internal structures of fine-grained materials at high-resolution. A relationship between LPO, SPO, and elastic anisotropy of the Qusaiba Shale from the Rub'al-Khali basin in Saudi Arabia is established in Chapter 5. The Qusaiba samples exhibit strong LPO of clay minerals (2.4-6.8 m.r.d.) due to their high total clay content and high degree of compaction. The SPO of pores, fractures, and kerogen here are also anisotropic and organized mainly parallel to bedding, with little connectivity of the flat pores normal to the bedding. The microscopic information (LPO) extracted from different synchrotron X-ray techniques is then applied in different averaging approaches (Voigt, Reuss, Hill, and Geometric mean) to calculate macroscopic properties of shales. (Abstract shortened by UMI.)

Microfractures in bed-parallel veins (beef) as predictors of vertical macrofractures in shale: Vaca Muerta Formation, Agrio Fold-and-Thrust Belt, Argentina

NASA Astrophysics Data System (ADS)

Ukar, Estibalitz; Lopez, Ramiro G.; Laubach, Stephen E.; Gale, Julia F. W.; Manceda, René; Marrett, Randall

2017-11-01

Shales of the Upper Jurassic-Lower Cretaceous Vaca Muerta Formation are the main source rock for petroleum in the Neuquén Basin, Argentina and an important unconventional exploration target. Folded Vaca Muerta Formation is well exposed in the Agrio Fold-and-Thrust belt where an arid climate and rapid erosion reveal relatively unweathered shale strata accessible along creek beds at Arroyo Mulichinco and in 10+ m-tall cliffs at Puesto. Widespread within these organic-rich shales are several cm-thick, prominent bed-parallel veins (BPVs) of fibrous calcite (beef) that are cut by multiple sets of vertical calcite lined or filled fractures having apertures unaffected by near-surface stress release. Similar, and probably contemporaneous fractures are present within horizons of interbedded dolomitic rock. Evidence that vertical fractures in BPVs and dolomitic horizons continue into shale beds suggests that in-depth analysis of vertical fractures within BPVs and dolomitic horizons allows fracture set and orientation identification and size population measurements-primarily aperture distributions-that circumvent some of the limitations of shale outcrops. At Arroyo Mulichinco, four main fracture sets are present separable by orientation and crosscutting relations. An E-W set is oldest, followed by successively younger NE-SW, NW-SE, and N-S sets. At Puesto, the E-W and N-S sets are the most prominent and show opposite cross-cutting relationships (E-W set is youngest) indicating a possible episode of younger E-W fractures. The E-W set shows the highest micro-and macrofracture intensity at both localities. The intensity of N-S micro- and macrofractures is similar at both outcrops away from faults, but macrofracture intensity increases closer to faults. While macrofracture abundance is similar in BPVs and in shale, microfractures having apertures smaller than ∼0.1 mm are mostly absent in shale and dolomitic layers but are abundant cutting BPVs. Thus, microfractures are BPV-bounded and only fractures wider than ∼0.05 mm are tall enough to cut into shale. Nevertheless, using size distributions of microfractures in BPVs that are absent in shale accurately predicts the abundance of macrofractures in nearby shale, either because microfractures in organic shale have annealed, or because of only small differences in fracture strain for fractures of different sizes across different rocks types. Microfractures in readily sampled BPVs may be a practical way to diagnose or predict attributes of macrofractures in adjacent shale.

Towards Characterization, Modeling, and Uncertainty Quantification in Multi-scale Mechanics of Oragnic-rich Shales

NASA Astrophysics Data System (ADS)

Abedi, S.; Mashhadian, M.; Noshadravan, A.

2015-12-01

Increasing the efficiency and sustainability in operation of hydrocarbon recovery from organic-rich shales requires a fundamental understanding of chemomechanical properties of organic-rich shales. This understanding is manifested in form of physics-bases predictive models capable of capturing highly heterogeneous and multi-scale structure of organic-rich shale materials. In this work we present a framework of experimental characterization, micromechanical modeling, and uncertainty quantification that spans from nanoscale to macroscale. Application of experiments such as coupled grid nano-indentation and energy dispersive x-ray spectroscopy and micromechanical modeling attributing the role of organic maturity to the texture of the material, allow us to identify unique clay mechanical properties among different samples that are independent of maturity of shale formations and total organic content. The results can then be used to inform the physically-based multiscale model for organic rich shales consisting of three levels that spans from the scale of elementary building blocks (e.g. clay minerals in clay-dominated formations) of organic rich shales to the scale of the macroscopic inorganic/organic hard/soft inclusion composite. Although this approach is powerful in capturing the effective properties of organic-rich shale in an average sense, it does not account for the uncertainty in compositional and mechanical model parameters. Thus, we take this model one step forward by systematically incorporating the main sources of uncertainty in modeling multiscale behavior of organic-rich shales. In particular we account for the uncertainty in main model parameters at different scales such as porosity, elastic properties and mineralogy mass percent. To that end, we use Maximum Entropy Principle and random matrix theory to construct probabilistic descriptions of model inputs based on available information. The Monte Carlo simulation is then carried out to propagate the uncertainty and consequently construct probabilistic descriptions of properties at multiple length-scales. The combination of experimental characterization and stochastic multi-scale modeling presented in this work improves the robustness in the prediction of essential subsurface parameters in engineering scale.

Hydrogen (H) Isotope Composition of Type II Kerogen Extracted by Pyrolysis-GC-MS-IRMS: Terrestrial Shale Deposits as Martian Analogs

NASA Technical Reports Server (NTRS)

Socki, Richard A.; Pernia, Denet; Evans, Michael; Fu, Qi; Bissada, Kadry K.; Curiale, Joseph A.; Niles, Paul B.

2014-01-01

Described here is a technique for H isotope analysis of organic compounds pyrolyzed from kerogens isolated from gas- and liquids-rich shales. Application of this technique will progress the understanding of the use of H isotopes not only in potential kerogen occurrences on Mars, but also in terrestrial oil and gas resource plays. H isotope extraction and analyses were carried out utilizing a CDS 5000 Pyroprobe connected to a Thermo Trace GC interfaced with a Thermo MAT 253 IRMS. Also, a split of GC-separated products was sent to a DSQ II quadrupole MS to make qualitative and semi-quantitative compositional measurements of these products. Kerogen samples from five different basins (type II and II-S) were dehydrated (heated to 80 C overnight under vacuum) and analyzed for their H isotope compositions by Pyrolysis-GC-MS-TC-IRMS. This technique takes pyrolysis products separated via GC and reacts them in a high temperature conversion furnace (1450 C), which quantitatively forms H2. Samples ranging from 0.5 to 1.0mg in size, were pyrolyzed at 800 C for 30s. and separated on a Poraplot Q GC column. H isotope data from all kerogen samples typically show enrichment in D from low to high molecular weight. H2O average delta D = -215.2 per mille (V-SMOW), ranging from - 271.8 per mille for the Marcellus Shale to -51.9 per mille for a Polish shale. Higher molecular weight compounds like toluene (C7H8) have an average delta D of -89.7 per mille, ranging from -156.0 per mille for the Barnett Shale to -50.0 per mille for the Monterey Shale. We interpret these data as representative of potential H isotope exchange between hydrocarbons and sediment pore water during basin formation. Since hydrocarbon H isotopes readily exchange with water, these data may provide some useful information on gas-water or oil-water interaction in resource plays, and further as a possible indicator of paleoenvironmental conditions. Alternatively, our data may be an indication of H isotope exchange with water and/or acid during the kerogen isolation process. Either of these interpretations will prove useful when deciphering H isotope data derived from kerogen analyses. Understanding the role that these H-bearing compounds play in terrestrial shale paleo-environmental reconstruction may also prove useful as analogs for understanding the interactions of water and potential kerogen/organic compounds on the planet Mars.

Evaluation of PAH contamination in soil treated with solid by-products from shale pyrolysis.

PubMed

Nicolini, Jaqueline; Khan, Muhammad Y; Matsui, M; Côcco, Lílian C; Yamamoto, Carlos I; Lopes, Wilson A; de Andrade, Jailson B; Pillon, Clenio N; Arizaga, Gregorio G Carbajal; Mangrich, Antonio S

2015-01-01

The aim of this work was to evaluate the concentrations of polycyclic aromatic hydrocarbons (PAHs) in soils to which solid shale materials (SSMs) were added as soil conditioners. The SSMs were derived from the Petrosix pyrolysis process developed by Petrobras (Brazil). An improved ultrasonic agitation method was used to extract the PAHs from the solid samples (soils amended with SSMs), and the concentrations of the compounds were determined by gas chromatography coupled to mass spectrometry (GC-MS). The procedure provided satisfactory recoveries, detection limits, and quantification limits. The two-, three-, and four-ring PAHs were most prevalent, and the highest concentration was obtained for phenanthrene (978 ± 19 μg kg(-1) in a pyrolyzed shale sample). The use of phenanthrene/anthracene and fluoranthene/pyrene ratios revealed that the PAHs were derived from petrogenic rather than pyrogenic sources. The measured PAH concentrations did not exceed national or international limit values, suggesting that the use of SSMs as soil conditioners should not cause environmental damage.

A novel method for the determination of adsorption partition coefficients of minor gases in a shale sample by headspace gas chromatography.

PubMed

Zhang, Chun-Yun; Hu, Hui-Chao; Chai, Xin-Sheng; Pan, Lei; Xiao, Xian-Ming

2013-10-04

A novel method has been developed for the determination of adsorption partition coefficient (Kd) of minor gases in shale. The method uses samples of two different sizes (masses) of the same material, from which the partition coefficient of the gas can be determined from two independent headspace gas chromatographic (HS-GC) measurements. The equilibrium for the model gas (ethane) was achieved in 5h at 120°C. The method also involves establishing an equation based on the Kd at higher equilibrium temperature, from which the Kd at lower temperature can be calculated. Although the HS-GC method requires some time and effort, it is simpler and quicker than the isothermal adsorption method that is in widespread use today. As a result, the method is simple and practical and can be a valuable tool for shale gas-related research and applications. Copyright © 2013 Elsevier B.V. All rights reserved.

Geophysical Logs of Selected Test Wells at the Diaz Chemical Superfund Site in Holley, New York

USGS Publications Warehouse

Eckhardt, David A.V.; Anderson, J. Alton

2007-01-01

In June and July 2006, geophysical logs were collected and analyzed along with rock-core samples to define the bedrock stratigraphy and flow zones penetrated by four test wells at the Diaz Chemical Superfund site at Holley in eastern Orleans County, New York. The work was completed as a preliminary part of the investigation of contamination by organic compounds in the shale, mudstone, and sandstone bedrock. The geophysical logs included natural-gamma, caliper, borehole image, fluid properties, and flowmeter data. The orientation of fractures in the boreholes was inferred from the log data and summarized in stereo and tadpole plots; the transmissivity and hydraulic head was also determined for fracture zones that were observed to be hydraulically active through the flowmeter logs. The data are intended in part for use in the remediation of the site.

Black shale deposition during Toarcian super-greenhouse driven by sea level

NASA Astrophysics Data System (ADS)

Hermoso, M.; Minoletti, F.; Pellenard, P.

2013-12-01

One of the most elusive aspects of the Toarcian oceanic anoxic event (T-OAE) is the paradox between carbon isotopes that indicate intense global primary productivity and organic carbon burial at a global scale, and the delayed expression of anoxia in Europe. During the earliest Toarcian, no black shales were deposited in the European epicontinental seaways, and most organic carbon enrichment of the sediments postdated the end of the overarching positive trend in the carbon isotopes that characterises the T-OAE. In the present study, we have attempted to establish a sequence stratigraphic framework for Early Toarcian deposits recovered from a core drilled in the Paris Basin using a combination of mineralogical (quartz and clay relative abundance) and geochemical (Si, Zr, Ti and Al) measurements. Combined with the evolution in redox sensitive elements (Fe, V and Mo), the data suggest that expression of anoxia was hampered in European epicontinental seas during most of the T-OAE (defined by the positive carbon isotope trend) due to insufficient water depth that prevented stratification of the water column. Only the first stratigraphic occurrence of black shales in Europe corresponds to the "global" event. This interval is characterised by >10% Total Organic Carbon (TOC) content that contains relatively low concentration of molybdenum compared to subsequent black shale horizons. Additionally, this first black shale occurrence is coeval with the record of the major negative Carbon Isotope Excursion (CIE), likely corresponding to a period of transient greenhouse intensification likely due to massive injection of carbon into the atmosphere-ocean system. As a response to enhanced weathering and riverine run-off, increased fresh water supply to the basin may have promoted the development of full anoxic conditions through haline stratification of the water column. In contrast, post T-OAE black shales during the serpentinum and bifrons Zones were restricted to epicontinental seas (higher Mo to TOC ratios) during a period of relative high sea level, and carbon isotopes returning to pre-T-OAE values. Comparing palaeoredox proxies with the inferred sequence stratigraphy for Sancerre suggests that episodes of short-term organic carbon enrichment were primarily driven by third-order sea level changes. These black shales exhibit remarkably well-expressed higher-frequency cyclicities in the oxygen availability in the water column whose nature has still to be determined through cyclostratigraphic analysis.

Black shale deposition during Toarcian super-greenhouse driven by sea level

NASA Astrophysics Data System (ADS)

Hermoso, M.; Minoletti, F.; Pellenard, P.

2013-07-01

One of the most elusive aspects of the Toarcian Oceanic Anoxic Event (T-OAE) is the paradox between carbon isotopes that indicate intense global primary productivity and organic carbon burial at a global scale, and the delayed expression of anoxia in Europe. During the earliest Toarcian, no black shales were deposited in the European epicontinental seaways, and most organic carbon enrichment of the sediments postdated the T-OAE (defined by the overarching positive trend in the carbon isotopes). In the present studied, we have attempted to establish a sequence stratigraphy framework for Early Toarcian deposits recovered from a core drilled in the Paris Basin using a combination of mineralogical (quartz and clay relative abundance) and geochemical (Si, Zr, Ti and Al) measurements. Combined with the evolution in redox sensitive elements (Fe, V and Mo), the data suggest that expression of anoxia was hampered in European epicontinental seas during most of the T-OAE due to insufficient water depth that prevented stratification of the water column. Only the first stratigraphic occurrence of black shales in Europe corresponds to the "global" event. This interval is characterised by > 10% Total Organic Carbon (TOC) content that contains relatively low concentration of molybdenum compared to subsequent black shale horizons. Additionally, this first black shale occurrence is coeval with the record of the major negative Carbon Isotope Excursion (CIE), likely corresponding to a period of transient greenhouse intensification likely due to massive injection of carbon into the Atmosphere-Ocean system. As a response to enhanced weathering and riverine run-off, increased fresh water supply to the basin may have promoted the development of full anoxic conditions through haline stratification of the water column. In contrast, post T-OAE black shales were restricted to epicontinental seas (higher Mo to TOC ratios) during a period of relative high sea level, and carbon isotopes returning to pre-T-OAE values. Comparing palaeoredox proxies with the inferred sequence stratigraphy for Sancerre suggests that episodes of short-term organic carbon enrichment were primarily driven by third-order sea level changes. These black shales exhibit remarkably well-expressed higher-frequency cyclicities in the concentration of redox-sensitive elements such as iron or vanadium whose nature has still to be determined through cyclostratigraphic analysis.

Recovery and fractionation of phosphorus retained by lightweight expanded shale and masonry sand used as media in subsurface flow treatment wetlands.

PubMed

Forbes, Margaret G; Dickson, Kenneth L; Saleh, Farida; Waller, William T; Doyle, Robert D; Hudak, Paul

2005-06-15

Most subsurface flow treatment wetlands, also known as reed bed or root zone systems, use sand or gravel substrates to reduce organics, solids, and nutrients in septic tank effluents. Phosphorus (P) retention in these systems is highly variable and few studies have identified the fate of retained P. In this study, two substrates, expanded shale and masonry sand, were used as filter media in five subsurface flow pilot-scale wetlands (2.7 m3). After 1 year of operation, we estimated the annual rate of P sorption by taking the difference between total P (TP) of substrate in the pilot cells and TP of substrate not exposed to wastewater (control). Means and standard deviations of TP retained by expanded shale were 349 +/- 171 mg kg(-1), respectively. For a substrate depth of 0.9 m, aerial P retention by shale was 201 +/- 98.6 g of P m(-2) year(-1), respectively. Masonry sand retained an insignificant quantity of wastewater P (11.9 +/- 21.8 mg kg(-1)) and on occasion exported P. Substrate samples were also sequentially fractionated into labile P, microbial P, (Fe + Al) P, humic P, (Ca + Mg) P, and residual P. In expanded shale samples, the greatest increase in P was in the relatively permanent form of (Fe + Al) P (108 mg kg(-1)), followed by labile P (46.7 mg kg(-1)) and humic P (39.8 mg kg(-1)). In masonry sand, there was an increase in labile P (9.71 mg kg(-1)). Results suggest that sand is a poor candidate for long-term P storage, but its efficiency is similar to that reported for many sand, gravel, and rock systems. By contrast, expanded shale and similar products with high hydraulic conductivity and P sorption capacity could greatly improve performance of P retention in constructed wetlands.

Halogenation of Hydraulic Fracturing Additives in the Shale Well Parameter Space

NASA Astrophysics Data System (ADS)

Sumner, A. J.; Plata, D.

2017-12-01

Horizontal Drilling and Hydraulic fracturing (HDHF) involves the deep-well injection of a `fracking fluid' composed of diverse and numerous chemical additives designed to facilitate the release and collection of natural gas from shale plays. The potential impacts of HDHF operations on water resources and ecosystems are numerous, and analyses of flowback samples revealed organic compounds from both geogenic and anthropogenic sources. Furthermore, halogenated chemicals were also detected, and these compounds are rarely disclosed, suggesting the in situ halogenation of reactive additives. To test this transformation hypothesis, we designed and operated a novel high pressure and temperature reactor system to simulate the shale well parameter space and investigate the chemical reactivity of twelve commonly disclosed and functionally diverse HDHF additives. Early results revealed an unanticipated halogenation pathway of α-β unsaturated aldehyde, Cinnamaldehyde, in the presence of oxidant and concentrated brine. Ongoing experiments over a range of parameters informed a proposed mechanism, demonstrating the role of various shale-well specific parameters in enabling the demonstrated halogenation pathway. Ultimately, these results will inform a host of potentially unintended interactions of HDHF additives during the extreme conditions down-bore of a shale well during HDHF activities.

Identification of crude oil source facies in Railroad Valley, Nevada, using multivariate analysis of crude oil and hydrous pyrolysis data from the Meridian Spencer Federal 32-29 well

DOE Office of Scientific and Technical Information (OSTI.GOV)

Conlan, L.M.; Francis, R.D.

Comparison of biological markers of a hydrous pyrolyzate of Mississippian-Chainman Shale from the Meridian Spencer Federal 32-29 well with two crude oils produced from the same well and crude oils produced from Trap Springs, Grant Canyon, Bacon Flats, and Eagle Springs fields indicate the possibility of three distinct crude oil source facies within Railroad Valley, Nevada. The two crude oil samples produced in the Meridian Spencer Federal 32-29 well are from the Eocene Sheep Pass Formation (MSF-SP) at 10,570 ft and the Joana Limestone (MSF-J) at 13,943 ft; the pyrolyzate is from the Chainman Shale at 10,700 ft. The Chainmanmore » Shale pyrolyzate has a similar composition to oils produced in Trap Springs and Grant Canyon fields. Applying multivariate statistical analysis to biological marker data shows that the Chainman Shale is a possible source for oil produced at Trap Springs because of the similarities between Trap Springs oils and the Chainman Shale pyrolyzate. It is also apparent that MSF-SP and oils produced in the Eagle Springs field have been generated from a different source (probably the Sheep Pass Formation) because of the presence of gammacerane (C{sub 30}). MSF-J and Bacon Flats appear to be either sourced from a pre-Mississippian unit or from a different facies within the Chainman Shale because of the apparent differences between MSF-J and Chainman Shale pyrolyzate.« less

Carbon-13 and proton nuclear magnetic resonance analysis of shale-derived refinery products and jet fuels and of experimental referee broadened-specification jet fuels

NASA Technical Reports Server (NTRS)

Dalling, D. K.; Bailey, B. K.; Pugmire, R. J.

1984-01-01

A proton and carbon-13 nuclear magnetic resonance (NMR) study was conducted of Ashland shale oil refinery products, experimental referee broadened-specification jet fuels, and of related isoprenoid model compounds. Supercritical fluid chromatography techniques using carbon dioxide were developed on a preparative scale, so that samples could be quantitatively separated into saturates and aromatic fractions for study by NMR. An optimized average parameter treatment was developed, and the NMR results were analyzed in terms of the resulting average parameters; formulation of model mixtures was demonstrated. Application of novel spectroscopic techniques to fuel samples was investigated.

Geohydrologic and water-quality characterization of a fractured-bedrock test hole in an area of Marcellus shale gas development, Bradford County, Pennsylvania

USGS Publications Warehouse

Risser, Dennis W.; Williams, John H.; Hand, Kristen L.; Behr, Rose-Anna; Markowski, Antonette K.

2013-01-01

Open-File Miscellaneous Investigation 13–01.1 presents the results of geohydrologic investigations on a 1,664-foot-deep core hole drilled in the Bradford County part of the Gleason 7.5-minute quadrangle in north-central Pennsylvania. In the text, the authors discuss their methods of investigation, summarize physical and analytical results, and place those results in context. Four appendices include (1) a full description of the core in an Excel worksheet; (2) water-quality and core-isotope analytical results in Excel workbooks; (3) geophysical logs in LAS and PDF files, and an Excel workbook containing attitudes of bedding and fractures calculated from televiewer logs; and (4) MP4 clips from the downhole video at selected horizons.

The geochemistry of naturally occurring methane and saline groundwater in an area of unconventional shale gas development

NASA Astrophysics Data System (ADS)

Harkness, Jennifer S.; Darrah, Thomas H.; Warner, Nathaniel R.; Whyte, Colin J.; Moore, Myles T.; Millot, Romain; Kloppmann, Wolfram; Jackson, Robert B.; Vengosh, Avner

2017-07-01

Since naturally occurring methane and saline groundwater are nearly ubiquitous in many sedimentary basins, delineating the effects of anthropogenic contamination sources is a major challenge for evaluating the impact of unconventional shale gas development on water quality. This study investigates the geochemical variations of groundwater and surface water before, during, and after hydraulic fracturing and in relation to various geospatial parameters in an area of shale gas development in northwestern West Virginia, United States. To our knowledge, we are the first to report a broadly integrated study of various geochemical techniques designed to distinguish natural from anthropogenic sources of natural gas and salt contaminants both before and after drilling. These measurements include inorganic geochemistry (major cations and anions), stable isotopes of select inorganic constituents including strontium (87Sr/86Sr), boron (δ11B), lithium (δ7Li), and carbon (δ13C-DIC), select hydrocarbon molecular (methane, ethane, propane, butane, and pentane) and isotopic tracers (δ13C-CH4, δ13C-C2H6), tritium (3H), and noble gas elemental and isotopic composition (helium, neon, argon) in 105 drinking-water wells, with repeat testing in 33 of the wells (total samples = 145). In a subset of wells (n = 20), we investigated the variations in water quality before and after the installation of nearby (<1 km) shale-gas wells. Methane occurred above 1 ccSTP/L in 37% of the groundwater samples and in 79% of the samples with elevated salinity (chloride > 50 mg/L). The integrated geochemical data indicate that the saline groundwater originated via naturally occurring processes, presumably from the migration of deeper methane-rich brines that have interacted extensively with coal lithologies. These observations were consistent with the lack of changes in water quality observed in drinking-water wells following the installation of nearby shale-gas wells. In contrast to groundwater samples that showed no evidence of anthropogenic contamination, the chemistry and isotope ratios of surface waters (n = 8) near known spills or leaks occurring at disposal sites mimicked the composition of Marcellus flowback fluids, and show direct evidence for impact on surface water by fluids accidentally released from nearby shale-gas well pads and oil and gas wastewater disposal sites. Overall this study presents a comprehensive geochemical framework that can be used as a template for assessing the sources of elevated hydrocarbons and salts to water resources in areas potentially impacted by oil and gas development.

The Shublik Formation and adjacent strata in northeastern Alaska description, minor elements, depositional environments and diagenesis

USGS Publications Warehouse

Tourtelot, Harry Allison; Tailleur, Irvin L.

1971-01-01

The Shublik Formation (Middle and Late Triassic) is widespread in the surface and subsurface of northern Alaska. Four stratigraphic sections along about 70 miles of the front of the northeastern Brooks Range east of the Canning giver were examined and sampled in detail in 1968. These sections and six-step spectrographic and carbon analyses of the samples combined with other data to provide a preliminary local description of the highly organic unit and of the paleoenvironments. Thicknesses measured between the overlying Kingak Shale of Jurassic age and the underlying Sadlerochit Formation of Permian and Triassic age range from 400 to more than 800 feet but the 400 feet, obtained from the most completely exposed section, may be closer to the real thickness across the region. The sections consist of organic-rich, phosphatic, and fossiliferous muddy, silty, or carbonate rocks. The general sequence consists, from the bottom up, of a lower unit of phosphatic siltstone, a middle unit of phosphatic carbonate rocks, and an upper unit of shale and carbonate rocks near the Canning River and shale, carbonate rocks, and sandstone to the east. Although previously designated a basal member of the Kingak Shale (Jurassic), the upper unit is here included with the Shublik on the basis of its regional lithologic relation. The minor element compositions of the samples of the Shublik Formation are consistent with their carbonaceous and phosphatic natures in that relatively large amounts of copper, molybdenum, nickel, vanadium and rare earths are present. The predominantly sandy rocks of the underlying Sadlerochit Formation (Permian and Triassic) have low contents of most minor elements. The compositions of samples of Kingak Shale have a wide range not readily explicable by the nature of the rock: an efflorescent sulfate salt contains 1,500 ppm nickel and 1,500 ppm zinc and large amounts of other metals derived from weathering of pyrite and leaching of local shale. The only recorded occurrence of silver and 300 ppm lead in gouge along a shear plane may be the result of metals introduced from an extraneous source. The deposits reflect a marine environment that deepened somewhat following deposition of the Sadlerochit Formation and then shoaled during deposition of the upper limestone-siltstone unit. This apparently resulted from a moderate transgression and regression of the sea with respect to a northwest-trending line between Barrow and the Brooks Range at the International Boundary. Nearer shore facies appear eastward. The phosphate in nodules, fossil molds and oolites, appears to have formed diagenetically within the uncompacted sediment.

A New Oceanic Anoxic Event 2 record from the Central North Atlantic at South East Newfoundland Ridge, IODP Expedition 342, Newfoundland Drifts

NASA Astrophysics Data System (ADS)

Junium, C. K.; Bornemann, A.; Bown, P. R.; Friedrich, O.; Moriya, K.; Kirtland Turner, S.; Whiteside, J. H.

2013-12-01

The recovery of Cretaceous, Cenomanian-Turonian black shales deposited during Oceanic Anoxic Event 2 (OAE 2) at Site U1407, South East Newfoundland Ridge (SENR), was an unexpected but fortuitous discovery that fills a gap in the pelagic Tethyan and North Atlantic geologic records. Drilling operations recovered the OAE sequence in all three holes drilled at Site U1407 defined initially on the basis of lithology and calcareous nannofossil biostratigraphy and confirmed by carbon isotope stratigraphy post-expedition. The SENR OAE 2 sequence is a classic chalk sequence punctuated by a prominent black band. Prior to OAE 2, greenish white pelagic carbonate is interrupted by thin, 2 to 5 cm thick organic-rich, gray calcareous clays. A sharp transition from greenish-white chalk to carbonate-poor sediments marks the occurrence of the organic carbon-rich black band. Within the black band are finely laminated to massive, pyritic black shales and laminated gray clays that are relatively organic carbon-lean, free of preserved benthic foraminifera and rich in radiolarians. Finely laminated greenish-gray marls overlay the black band and grade into approximately 1 meter of greenish white chalks with common 1cm chert layers and nodules. The remainder of the Turonian sequence is characterized by a notable transition to pink chalks. The thickness of the black band ranges from 15-40 cm between Holes A through C. The differences in the thickness of beds between Holes is due in part to drilling disturbances and mass wasting indicated by slump features in the overlying Turonian strata. Core scanning XRF and carbon isotopes can help resolve the nature of these differences and inform future sampling and study. Carbonate and organic carbon isotopes reveal that the δ13C excursion marking the initiation of OAE 2 is below the base of the black band. At U1407A the δ13C rise is immediately below (3 cm) the black shale, with δ13C maxima in the black band. At U1407C the initial δ13C rise is below the black shale by 60 cm, in the underlying chalk. The temporal transience of TOC-enrichment is typical of OAE 2 sequences, particularly in the Tethyan realm (Gubbio, Italy; Ferriby, UK; Tarfaya, Morocco; Wunsorf, Germany), but the mechanism is unknown. In many ways, Site U1407 bears the distinct characteristics of the Tethyan region. Prior to the OAE, there are several black and dark gray bands interbedded with carbonate-rich (>80 wt. %), greenish white chalks. The color progression of white to black to pink through the OAE at U1407 is similar to C-T boundary sequences from the Umbria-Marche basin of Italy. The greenish white to pink nannofossil chalks are reminiscent of the Scaglia Bianca/Rossa limestones that bound the Bonarelli horizon. Associated lithologies include the presence of radiolarian sands interbedded with the black shales and cherts. This stratigraphic progression is similar to the Italian sequences, but the δ13C stratigraphy indicates that the excursion leads black shale deposition and in this sense is more similar to shallow continental records from the UK, USA and mainland Europe. This new δ13C record can be used to correlate SENR with other OAE 2 sections, allowing us to better understand possible mechanisms for the temporal transience of the black shales and paleoceanographic change during OAE2.

Variations in Multiscale (nano to mm) Porosity in the Eagle Ford Shale as a Function of Maturity through the Oil Window

NASA Astrophysics Data System (ADS)

Anovitz, L. M.; Cole, D. R.; Swift, A.; Sheets, J.; Elston, H. W.; Gutierrez, M. A.; Cook, A.; Chipera, S.; Littrell, K. C.; Mildner, D. F.; Wasbrough, M.

2013-12-01

Porosity and permeability are key variables that link the thermal-hydrologic, geomechanical and geochemical behavior in rock systems and are thus important input parameters for transport models. Recent neutron scattering studies have indicated that the scales of pore sizes in rocks extend over many orders of magnitude from nanometer pores with huge amounts of total surface area to large open fracture systems (multiscale porosity, cf. Anovitz et al., 2009, 2011, 2013a,b). However, despite a considerable amount of effort combining conventional rock petrophysics with more sophisticated neutron scattering and electron microscopy studies, the quantitative nature of this porosity in tight gas shales, especially at smaller scales and over larger rock volumes, remains largely unknown (Clarkson, 2011). We lack a quantitative understanding of the multiscale porosity regime (i.e., pore size, shape, and volume, pore size distribution, pore connectivity, pore wall roughness) in rocks. Nor is it understood how porosity is affected by regional variation, thermal changes across the oil window, and, most critically, hydraulic fracturing operations. In order to begin to provide a quantitative understanding of porosity at nanometer to core scales in these shale formations and how it relates to gas storage and recovery we have used a combination of small and ultrasmall angle neutron scattering measurments made on the GP-SANS instrument at ORNL/HFIR, and the NG3-SANS and BT5-USANS instruments and NIST/NCNR, with SEM/BSE and X-ray Computed Tomographic imaging to analyze the pore structure of both clay and carbonate-rich samples of the Eagle Ford Shale. The Eagle Ford Shale is a late Cretaceous unit underlying much of southeast Texas and probably adjacent sections of Mexico. It outcrops in an arc from north of Austin, through San Antonio and then west towards Kinney County. It is hydrocarbon rich, and buried portions straddle the oil window. The Eagle Ford is currently one of the most actively drilled oil and gas targets in the US. The first successful horizontal well was drilled in 2008, and 2522 permits were recorded (Texas railroad commission) by Sept 1, 2011. While the oil and gas reserves in the Eagle Ford have been known since the 1970's, prior to the invention of horizontal drilling/hydraulic fracturing it was not considered economic. Several important trends in the rock pore structure have been identified using our approach. Pore distributions are clearly fractal but, as was observed for the St. Peter sandstone (Anovitz et al., 2013a), are composed of several size distributions. Initial porosity is strongly anisotropic, as expected for shales. However, this decreases for shales, and disappears for carbonates with maturity. In both cases significant reduction occurs in total porosity, with most of the change coming at the finest scales (< ~ 10 nm), and an observable decrease at intermediate scales (near 100 nm) Research sponsored by the Division of Chemical Sciences, Geosciences, and Biosciences, Office of Basic Energy Sciences, U.S. Department of Energy, and as part of the Center for Nanoscale Control of Geologic CO2, an Energy Frontier Research Center funded by the U.S. Department of Energy, Office of Science under U.S. Dept. of Energy (DOE) contract DE-AC02-05CH11231.

In Situ Carbon and Sulfur Isotope Analysis of Archean Organic Matter and Pyrite

NASA Technical Reports Server (NTRS)

Williford, K. H.; Ushikubo, T.; LePot, K.; Kitajima, K.; Spicuzza, M. J.; Valley, J. W.; Hallman, C.; Summons, R.; Eigenbrode, J. L.

2012-01-01

Stable isotopic compositions of biologically important elements (e.g., C and S) in sedimentary rocks are valuable biosignatures to the extent that they indicate the presence and variable expression of microbial metabolisms in space and time. Strong interactions between the carbon and sulfur cycles (e.g., via organic matter remineralization during microbial sulfate reduction) make coordinated, in situ C and S isotope analysis by secondary ion mass spectrometry (SIMS) a particularly powerful tool. In rocks ranging in age from 2.7-2.5 Ga, expansions in the ranges of delta C-13 of organic matter and delta S-34 of pyrite likely reflect the increasing influence of oxygenic photosynthesis in the surface ocean (as well as methane and sulfur metabolisms in deeper waters), whereas the large range of mass independent sulfur isotope fractionation (Delta S-33) suggests that the atmosphere remained anoxic until approx 2.4 Gyr ago. We report in situ delta C-13 measurements of organic matter in the approx 2.7-2.6 Ga Carawine Dolomite, Marra Mamba Iron Formation, and Jeerinah, Wittenoom, and Tumbiana Formations, as well as the approx 2.5 Ga Mount McRae Shale. We also report in situ delta S-24 and Delta S-33 measurements of pyrite associated with organic matter in a subset of these samples. In a single square cm sample of the Tumbiana Formation with bulk delta C-13(sub org) of -49.7% (VPDB), two distinct kerogen types have delta C-13 values, measured in situ, consistent with oxygenic photosynthesis (-33%) and methane metabolism (-52%). In a sample from the ABDP-9 core, radiobitumen associated with a uraniferous mineral grain is C-13-enriched by 8% (-26.8%0) relative to average in situ kerogen (-34.9%0) and similar in delta C-13 to solvent extractable hydrocarbons from the Mount McRae Shale (avg delta C-13 = -27.1 %). Average reproducibility for delta C-13 was 0.4% (2 SD) using a 6 micron spot and 0.8% using a 3 micron spot. In situ sulfur isotope analyses of 33 authigenic pyrite grains in 3 samples of the ABDP-9 core using a 10 micron spot (2 SD reproducibility = 0.4% for delta S-34 and -0.1% for Delta S-33) show a range of 28.1 % in delta S-34 (-10.3 to 17.8%) and 13.3%0 in Delta S-33 (-3.8 to 9.5%), whereas the range from 132 bulk analyses across 84 m of core is 19.4% for delta S-34 and 11.5% for Delta S-33. Coordinated, in situ carbon and sulfur isotope analyses in one ABDP-9 sample are shown. In situ values from this kerogen-pyrite association are within 0.1% of the bulk value in the case of delta C-13 and higher by several permil in the case of delta S-34 and Delta S-33. Coordinated in situ carbon and sulfur isotope analyses in rocks deposited during key intervals of environmental change (e.g., the Great Oxidation Event) can refine our understanding of the mode and tempo of change. In Earth's oldest sedimentary rocks, and in extraterrestrial samples, these coordinated in situ analyses may reveal biosignatures in the form of isotopic correlations at the scale of individual microorganisms and their microhabitats.

The controls on the major and trace element variation of shales, siltstones, and sandstones of Pennsylvanian-Permian age from uplifted continental blocks in Colorado to platform sediment in Kansas, USA

NASA Astrophysics Data System (ADS)

Cullers, Robert L.

1994-11-01

Shales, siltstones, and sandstones of Pennsylvanian-Permian age from near the source in Colorado to those in the platform in eastern Colorado and Kansas have been analyzed for major elements and a number of trace elements, including the REEs. The near-source sandstones are significantly more enriched (Student t-test at better than the 99% confidence level) in SiO 2 and Na 2O concentrations and more depleted in Al 2O 3, Fe 2O 3 (total), TiO 2, Th, Hf, Sc, Cr, Cs, REEs, Y, and Ni concentrations and La/Co and La/Ni ratios than the near-source shales and siltstones, most likely due to more plagioclase and quartz and less clay minerals in the sandstones than in the shales and siltstones. There are no significant differences in K 2O and Sr concentrations and Eu/Eu∗, La/Lu, La/Se, Th/Sc, Th/Co, and Cr/Th ratios between the near-source sandstones and the near-source shales and siltstones. Samples of the Molas, Hermosa, and Cutler formations near the source that were formed in different environments in the same area contain no significant difference in Eu/Eu∗, La/Lu, La/Sc, Th/Sc, Th/Co, and Cr/Th ratios, so a generally silicic source and not the environment of deposition was most important in producing these elemental ratios. For example, Cr/Th ratios of near-source shales, siltstones, and sandstones range from 2.5 to 17.5 and Eu/Eu∗ range from 0.48 to 0.78, which are in the range of sources of sediments derived from mainly silicic and not basic sources. Near-source shales and siltstones contain significantly higher (Student t-test) and more varied concentrations of most elements (Al 2O 3, Fe 2O 3, MnO, TiO 2, Ba, Th, Hf, Ta, Co, Sc, REEs, Nb, Y) but significantly lower concentrations of Na 2O and Eu/Eu∗ than platform shales and siltstones in Kansas (e.g., La = 65.7 ± 40 and Eu/Eu∗ = 0.55 ± 0.07 in near-source shales and siltstones and La = 23.7 ± 8.7 and Eu/Eu∗ = 0.64 ± 0.08 in platform shales and siltstones). The SiO 2 and CaO concentrations are not significantly different in platform shales and siltstones compared to the near-source shales and siltstones, so dilution of other minerals by quartz and calcite is not the main reason for the lower concentration of most elements in the platform relative to the near-source shales and siltstones. Rather the lesser concentrations of most elements in clay minerals of the platform shales and siltstones can account for the lower concentration of most elements compared to corresponding near-source shales and siltstones. The lower concentrations of many elements in clay minerals in the platform shales and siltstones may be a result of having been derived from recycling of clay minerals from older rocks. The greater homogeneity of elemental concentrations of the platform shales and siltstones compared to those in the source is also consistent with homogeneous mixing of such recycled material. Also there is no significant difference in Th/Sc, La/Co, Th/Co, La/Ni, and Cr/Th ratios of the near-source sedimentary rocks in Colorado to the platform shales and siltstones in Kansas, and the latter are also consistent with derivation from mostly silicic source rocks.

Contesting Technologies in the Networked Society: A Case Study of Hydraulic Fracturing and Shale Development

NASA Astrophysics Data System (ADS)

Hopke, Jill E.

In this dissertation, I study the network structure and content of a transnational movement against hydraulic fracturing and shale development, Global Frackdown. I apply a relational perspective to the study of role of digital technologies in transnational political organizing. I examine the structure of the social movement through analysis of hyperlinking patterns and qualitative analysis of the content of the ties in one strand of the movement. I explicate three actor types: coordinator, broker, and hyper-local. This research intervenes in the paradigm that considers international actors as the key nodes to understanding transnational advocacy networks. I argue this focus on the international scale obscures the role of globally minded local groups in mediating global issues back to the hyper-local scale. While international NGOs play a coordinating role, local groups with a global worldview can connect transnational movements to the hyper-local scale by networking with groups that are too small to appear in a transnational network. I also examine the movement's messaging on the social media platform Twitter. Findings show that Global Frackdown tweeters engage in framing practices of: movement convergence and solidarity, declarative and targeted engagement, prefabricated messaging, and multilingual tweeting. The episodic, loosely-coordinated and often personalized, transnational framing practices of Global Frackdown tweeters support core organizers' goal of promoting the globalness of activism to ban fracking. Global Frackdown activists use Twitter as a tool to advance the movement and to bolster its moral authority, as well as to forge linkages between localized groups on a transnational scale. Lastly, I study the relative prominence of negative messaging about shale development in relation to pro-shale messaging on Twitter across five hashtags (#fracking, #globalfrackdown, #natgas, #shale, and #shalegas). I analyze the top actors tweeting using the #fracking hashtag and receiving mentions with the hashtag. Results show statistically significant differences in the sentiment about shale development across the five hashtags. Results also indicate that the discourse on the main contested hashtag #fracking is dominated by activists, both individual activists and organizations.

Elevated levels of diesel range organic compounds in groundwater near Marcellus gas operations are derived from surface activities.

PubMed

Drollette, Brian D; Hoelzer, Kathrin; Warner, Nathaniel R; Darrah, Thomas H; Karatum, Osman; O'Connor, Megan P; Nelson, Robert K; Fernandez, Loretta A; Reddy, Christopher M; Vengosh, Avner; Jackson, Robert B; Elsner, Martin; Plata, Desiree L

2015-10-27

Hundreds of organic chemicals are used during natural gas extraction via high-volume hydraulic fracturing (HVHF). However, it is unclear whether these chemicals, injected into deep shale horizons, reach shallow groundwater aquifers and affect local water quality, either from those deep HVHF injection sites or from the surface or shallow subsurface. Here, we report detectable levels of organic compounds in shallow groundwater samples from private residential wells overlying the Marcellus Shale in northeastern Pennsylvania. Analyses of purgeable and extractable organic compounds from 64 groundwater samples revealed trace levels of volatile organic compounds, well below the Environmental Protection Agency's maximum contaminant levels, and low levels of both gasoline range (0-8 ppb) and diesel range organic compounds (DRO; 0-157 ppb). A compound-specific analysis revealed the presence of bis(2-ethylhexyl) phthalate, which is a disclosed HVHF additive, that was notably absent in a representative geogenic water sample and field blanks. Pairing these analyses with (i) inorganic chemical fingerprinting of deep saline groundwater, (ii) characteristic noble gas isotopes, and (iii) spatial relationships between active shale gas extraction wells and wells with disclosed environmental health and safety violations, we differentiate between a chemical signature associated with naturally occurring saline groundwater and one associated with alternative anthropogenic routes from the surface (e.g., accidental spills or leaks). The data support a transport mechanism of DRO to groundwater via accidental release of fracturing fluid chemicals derived from the surface rather than subsurface flow of these fluids from the underlying shale formation.

Elevated levels of diesel range organic compounds in groundwater near Marcellus gas operations are derived from surface activities

PubMed Central

Drollette, Brian D.; Hoelzer, Kathrin; Warner, Nathaniel R.; Darrah, Thomas H.; Karatum, Osman; O’Connor, Megan P.; Nelson, Robert K.; Fernandez, Loretta A.; Reddy, Christopher M.; Vengosh, Avner; Jackson, Robert B.; Elsner, Martin; Plata, Desiree L.

2015-01-01

Hundreds of organic chemicals are used during natural gas extraction via high-volume hydraulic fracturing (HVHF). However, it is unclear whether these chemicals, injected into deep shale horizons, reach shallow groundwater aquifers and affect local water quality, either from those deep HVHF injection sites or from the surface or shallow subsurface. Here, we report detectable levels of organic compounds in shallow groundwater samples from private residential wells overlying the Marcellus Shale in northeastern Pennsylvania. Analyses of purgeable and extractable organic compounds from 64 groundwater samples revealed trace levels of volatile organic compounds, well below the Environmental Protection Agency’s maximum contaminant levels, and low levels of both gasoline range (0–8 ppb) and diesel range organic compounds (DRO; 0–157 ppb). A compound-specific analysis revealed the presence of bis(2-ethylhexyl) phthalate, which is a disclosed HVHF additive, that was notably absent in a representative geogenic water sample and field blanks. Pairing these analyses with (i) inorganic chemical fingerprinting of deep saline groundwater, (ii) characteristic noble gas isotopes, and (iii) spatial relationships between active shale gas extraction wells and wells with disclosed environmental health and safety violations, we differentiate between a chemical signature associated with naturally occurring saline groundwater and one associated with alternative anthropogenic routes from the surface (e.g., accidental spills or leaks). The data support a transport mechanism of DRO to groundwater via accidental release of fracturing fluid chemicals derived from the surface rather than subsurface flow of these fluids from the underlying shale formation. PMID:26460018

Preliminary report on the clay mineralogy of the Upper Devonian Shales in the southern and middle Appalachian Basin

USGS Publications Warehouse

Hosterman, John W.; Loferski, Patricia J.

1978-01-01

The distribution of kaolinite in parts of the Devonian shale section is the most significant finding of this work. These shales are composed predominately of 2M illite and illitic mixed-layer clay with minor amounts of chlorite and kaolinite. Preliminary data indicate that kaolinite, the only allogenic clay mineral, is present in successively older beds of the Ohio Shale from south to north in the southern and middle parts of the Appalachian basin. This trend in the distribution of kaolinite shows a paleocurrent direction to the southwest. Three well-known methods of preparing the clay fraction for X-ray diffraction analysis were tested and evaluated. Kaolinite was not identified in two of the methods because of layering due to differing settling rates of the clay minerals. It is suggested that if one of the two settling methods of sample preparation is used, the clay film be thin enough for the X-ray beam to penetrate the entire thickness of clay.

Compaction trends of full stiffness tensor and fluid permeability in artificial shales

NASA Astrophysics Data System (ADS)

Beloborodov, Roman; Pervukhina, Marina; Lebedev, Maxim

2018-03-01

We present a methodology and describe a set-up that allows simultaneous acquisition of all five elastic coefficients of a transversely isotropic (TI) medium and its permeability in the direction parallel to the symmetry axis during mechanical compaction experiments. We apply the approach to synthetic shale samples and investigate the role of composition and applied stress on their elastic and transport properties. Compaction trends for the five elastic coefficients that fully characterize TI anisotropy of artificial shales are obtained for a porosity range from 40 per cent to 15 per cent. A linear increase of elastic coefficients with decreasing porosity is observed. The permeability acquired with the pressure-oscillation technique exhibits exponential decrease with decreasing porosity. Strong correlations are observed between an axial fluid permeability and seismic attributes, namely, VP/VS ratio and acoustic impedance, measured in the same direction. These correlations might be used to derive permeability of shales from seismic data given that their mineralogical composition is known.

Stratigraphy of mid-Cretaceous formations at drilling sites in Weston and Johnson counties, northeastern Wyoming

USGS Publications Warehouse

Mereweather, E.A.

1980-01-01

The sedimentary rocks of early Late Cretaceous age in Weston County, Wyo., on the east flank of the Powder River Basin, are assigned, in ascending order, to the Belle Fourche Shale, Greenhorn Formation, and Carlile Shale. In Johnson County, on the west flank of the basin, the lower Upper Cretaceous strata are included in the Frontier Formation and the overlying Cody Shale. The Frontier Formation and some of the laterally equivalent strata in the Rocky Mountain region contain major resources of oil and gas. These rocks also include commercial deposits of bentonite. Outcrop sections, borehole logs, and core studies of the lower Upper Cretaceous rocks near Osage, in Weston County, and Kaycee, in Johnson County, supplement comparative studies of the fossils in the formations. Fossils of Cenomanian, Turonian, and Coniacian Age are abundant at these localities and form sequences of species which can be used for the zonation and correlation of strata throughout the region. The Belle Fourche Shale near Osage is about 115 m (meters) thick and consists mainly of noncalcareous shale, which was deposited in offshore-marine environments during Cenomanian time. These strata are overlain by calcareous shale and limestone of the Greenhorn Formation. In this area, the Greenhorn is about 85 m thick and accumulated in offshore, open-marine environments during the Cenomanian and early Turonian. The Carlile Shale overlies the Greenhorn and is composed of, from oldest to youngest, the Pool Creek Member, Turner Sandy Member, and Sage Breaks Member. In boreholes, the Pool Creek Member is about 23 m thick and consists largely of shale. The member was deposited in offshoremarine environments in Turonian time. These rocks are disconformably overlain by the Turner Sandy Member, a sequence about 50 m thick of interstratified shale, siltstone, and sandstone. The Turner accumulated during the Turonian in several shallow-marine environments. Conformably overlying the Turner is the slightly calcareous shale of the Sage Breaks Member, which is about 91 m thick. The Sage Breaks was deposited mostly during Coniacian time in offshore-marine environments. In Johnson County, the Frontier Formation consists of the Belle Fourche Member and the overlying Wall Creek Member, and is overlain by the Sage Breaks Member of the Cody Shale. Near Kaycee, the Belle Fourche Member is about 225 m thick and is composed mostly of interstratified shale, siltstone, and sandstone. These strata are mainly of Cenomanian age and were deposited largely in shallow-marine environments. In this area, the Belle Fourche Member is disconformably overlain by the Wall Creek Member, which is about 30 m thick and grades from interlaminated shale and siltstone at the base of the member to sandstone at the top. The Wall Creek accumulated during Turonian time in shallowmarine environments. These beds are overlain by the Sage Breaks Member of the Cody. Near Kaycee, the Sage Breaks is about 65 m thick and consists mainly of shale which was deposited in offshoremarine environments during Turonian and Coniacian time. Lower Upper Cretaceous formations on the east side of the Powder River Basin can be compared with strata of the same age on the west side of the basin. The Belle Fourche Shale at Osage is represented near Kaycee by most of the Belle Fourche Member of the Frontier. The Greenhorn at Osage contrasts with beds of similar age in the Belle Fourche at Kaycee. An upper part of the Greenhorn Formation, the Pool Creek Member of the Carlile Shale, and the basal beds of the Turner Sandy Member of the Carlile, in Weston County, are represented by a disconformity at the base of the Wall Creek Member of the Frontier in southern Johnson County. A middle part of the Turner in the vicinity of Osage is the same age as the Wall Creek Member near Kaycee. A sequence of beds in the upper part of the Turner and in the overlying Sage Breaks in Weston County is the same age as most of the Sage Breaks M

Characterization of Radium and Radon Isotopes in Hydraulic Fracturing Flowback Fluid and Gas from the Marcellus Shale

NASA Astrophysics Data System (ADS)

Bardsley, A.

2015-12-01

High volume hydraulic fracturing of unconventional deposits has expanded rapidly over the past decade in the US, with much attention focused on the Marcellus Shale gas reservoir in the northeastern US. We use naturally occurring radium isotopes and 222Rn to explore changes in formation characteristics as a result of hydraulic fracturing. Gas and produced waters were analyzed from time series samples collected soon after hydraulic fracturing at three Marcellus Shale well sites in the Appalachian Basin, USA. Analyses of δ18O, Cl- , and 226Ra in flowback fluid are consistent with two end member mixing between injected slick water and formation brine. All three tracers indicate that the ratio of injected water to formation brine declines with time across both time series. Cl- concentration (max ~1.5-2.2 M) and 226Ra activity (max ~165-250 Bq/Kg) in flowback fluid are comparable at all three sites. There are differences evident in the stable isotopic composition (δ18O & δD) of injected slick water across the three sites, but all appear to mix with formation brine of similar isotopic composition. On a plot of water isotopes, δ18O in formation brine-dominated fluid is enriched by ~3-4 permille relative to the Global Meteoric Water Line, indicating oxygen exchange with shale. The ratio of 223Ra/226Ra and 228Ra/226Ra in produced waters is quite low relative to shale samples analyzed. This indicates that most of the 226Ra in the formation brine must be sourced from shale weathering or dissolution rather than emanation due to alpha recoil from the rock surface. During the first week of flowback, ratios of short lived isotopes 223Ra and 224Ra to longer lived radium isotopes change modestly, suggesting rock surface area per unit of produced water volume did not change substantially. For one well, longer term gas samples were collected. The 222Rn/methane ratio in produced gas from this site declines with time and may represent a decrease in the brine to gas ratio in the reservoir over the course of six months after initial fracturing. Naturally occurring radium and radon isotopes show promise in elucidating sub-surface dynamics following hydraulic fracturing plays.

The 1.1-Ga Midcontinent Rift System, central North America: sedimentology of two deep boreholes, Lake Superior region

NASA Astrophysics Data System (ADS)

Ojakangas, Richard W.; Dickas, Albert B.

2002-03-01

The Midcontinent Rift System (MRS) of central North America is a 1.1-Ga, 2500-km long structural feature that has been interpreted as a triple-junction rift developed over a mantle plume. As much as 20 km of subaerial lava flows, mainly flood basalts, are overlain by as much as 10 km of sedimentary rocks that are mostly continental fluvial red beds. This rock sequence, known as the Keweenawan Supergroup, has been penetrated by a few deep boreholes in the search for petroleum. In this paper, two deep boreholes in the Upper Peninsula of Michigan are described in detail for the first time. Both the Amoco Production #1-29R test, herein referred to as the St. Amour well, and the nearby Hickey Creek well drilled by Cleveland Cliffs Mining Services, were 100% cored. The former is 7238 ft (2410 m) deep and the latter is 5345 ft (1780 m) deep. The entirety of the stratigraphic succession of the Hickey Creek core correlates very well with the upper portion of the St. Amour core, as determined by core description and point-counting of 43 thin sections selected out of 100 studied thin sections. Two Lower Paleozoic units and two Keweenawan red bed units—the Jacobsville Sandstone and the underlying Freda Sandstone—are described. The Jacobsville is largely a feldspatholithic sandstone and the Freda is largely a lithofeldspathic sandstone. Below the Freda, the remaining footage of the St. Amour core consists of a thick quartzose sandstone unit that overlies a heterogenous unit of intercalated red bed units of conglomerate, sandstone, siltstone, and shale; black shale; individual basalt flows; and a basal ignimbritic rhyolite. This lower portion of the St. Amour core presents an enigma, as it correlates very poorly with other key boreholes located to the west and southwest. While a black shale sequence is similar to the petroleum-bearing Nonesuch Formation farther west, there is no conglomerate unit to correlate with the Copper Harbor Conglomerate. Other key boreholes are distributed over a 1300-km distance along the better known southwest arm of the triple-junction MRS, and can be correlated rather well with the units that are exposed in the Lake Superior region. However, a definitive explanation of the anomalous, deeper St. Amour stratigraphy is elusive and any explanation is tenuous. A possible explanation for this anomalous stratigraphy may be the geographic proximity of the St. Amour borehole to the Keweenawan Hot Spot (mantle plume), the suggested thermal force behind the development of the MRS. Similarly, a drastic change in structural architecture may be explained by this geographic relationship. Thus, within the locale of this rifting center, complexities of expansion tectonics may well be responsible for igneous and sedimentary sequences that differ considerably from those found farther west along the rift arm.

Rehabilitation potential and practices of Colorado oil shale lands. Progress report, June 1, 1978--May 31, 1979

DOE Office of Scientific and Technical Information (OSTI.GOV)

Cook, C.W.

The following document is a third-year progress report for the period June 1, 1978 to May 31, 1979. The overall objective of the project is to study the effects of seeding techniques, species mixtures, fertilizer, ecotypes, improved plant materials, mycorrhizal fungi, and soil microorganisms on the initial and final stages of reclamation obtained through seeding and subsequent succession on disturbed oil shale lands. Plant growth medias that are being used in field-established test plots include retorted shale, soil over retorted shale, subsoil materials, and surface disturbed topsoils. Because of the long-term nature of successional and ecologically oriented studies the projectmore » is just beginning to generate significant publications. Several of the studies associated with the project have some phases being conducted principally in the laboratories and greenhouses at Colorado State Univerisity. The majority of the research, however, is being conducted on a 20 hectare Intensive Study Site located near the focal points of oil shale activity in the Piceance Basin. The site is at an elevation of 2,042 m, receives approximately 30 to 55 cm of precipitation annually, and encompasses the plant communities most typical of the Piceance Basin. Most of the information contained in this report originated from the monitoring and sampling of research plots established in either the fall of 1976 or 1977. Therefore, data that have been obtained from the Intensive Study Site represent only first- or second-year results. However, many trends have been identified in thesuccessional process and the soil microorganisms and mycorrhizal studies continue to contribute significant information to the overall results. The phytosociological study has progressed to a point where field sampling is complete and the application and publication of this materials will be forthcoming in 1979.« less

“Multi-temperature” method for high-pressure sorption measurements on moist shales

DOE Office of Scientific and Technical Information (OSTI.GOV)

Gasparik, Matus; Ghanizadeh, Amin; Gensterblum, Yves

2013-08-15

A simple and effective experimental approach has been developed and tested to study the temperature dependence of high-pressure methane sorption in moist organic-rich shales. This method, denoted as “multi-temperature” (short “multi-T”) method, enables measuring multiple isotherms at varying temperatures in a single run. The measurement of individual sorption isotherms at different temperatures takes place in a closed system ensuring that the moisture content remains constant. The multi-T method was successfully tested for methane sorption on an organic-rich shale sample. Excess sorption isotherms for methane were measured at pressures of up to 25 MPa and at temperatures of 318.1 K, 338.1more » K, and 348.1 K on dry and moisture-equilibrated samples. The measured isotherms were parameterized with a 3-parameter Langmuir-based excess sorption function, from which thermodynamic sorption parameters (enthalpy and entropy of adsorption) were obtained. Using these, we show that by taking explicitly into account water vapor as molecular species in the gas phase with temperature-dependent water vapor pressure during the experiment, more meaningful results are obtained with respect to thermodynamical considerations. The proposed method can be applied to any adsorbent system (coals, shales, industrial adsorbents) and any supercritical gas (e.g., CH{sub 4}, CO{sub 2}) and is particularly suitable for sorption measurements using the manometric (volumetric) method.« less

Geochemistry of Archean shales from the Pilbara Supergroup, Western Australia

NASA Astrophysics Data System (ADS)

McLennan, Scott M.; Taylor, S. R.; Eriksson, K. A.

1983-07-01

Archean clastic sedimentary rocks are well exposed in the Pilbara Block of Western Australia. Shales from turbidites in the Gorge Creek Group ( ca. 3.4 Ae) and shales from the Whim Creek Group ( ca. 2.7 Ae) have been examined. The Gorge Creek Group samples, characterized by muscovite-quartzchlorite mineralogy, are enriched in incompatible elements (K, Th, U, LREE) by factors of about two, when compared to younger Archean shales from the Yilgarn Block. Alkali and alkaline earth elements are depleted in a systematic fashion, according to size, when compared with an estimate of Archean upper crust abundances. This depletion is less notable in the Whim Creek Group. Such a pattern indicates the source of these rocks underwent a rather severe episode of weathering. The Gorge Creek Group also has fairly high B content (85 ± 29 ppm) which may indicate normal marine conditions during deposition. Rare earth element (REE) patterns for the Pilbara samples are characterized by light REE enrichment ( La N/Yb N ≥ 7.5 ) and no or very slight Eu depletion ( Eu/Eu ∗ = 0.82 - 0.99 ). A source comprised of about 80% felsic igneous rocks without large negative Eu-anomalies (felsic volcanics, tonalites, trondhjemites) and 20% mafic-ultramafic volcanics is indicated by the trace element data. Very high abundances of Cr and Ni cannot be explained by any reasonable provenance model and a secondary enrichment process is called for.

A non-zircon Hf isotope record in Archean black shales from the Pilbara craton confirms changing crustal dynamics ca. 3 Ga ago.

PubMed

Nebel-Jacobsen, Yona; Nebel, Oliver; Wille, Martin; Cawood, Peter A

2018-01-17

Plate tectonics and associated subduction are unique to the Earth. Studies of Archean rocks show significant changes in composition and structural style around 3.0 to 2.5 Ga that are related to changing tectonic regime, possibly associated with the onset of subduction. Whole rock Hf isotope systematics of black shales from the Australian Pilbara craton, selected to exclude detrital zircon components, are employed to evaluate the evolution of the Archean crust. This approach avoids limitations of Hf-in-zircon analyses, which only provide input from rocks of sufficient Zr-concentration, and therefore usually represent domains that already underwent a degree of differentiation. In this study, we demonstrate the applicability of this method through analysis of shales that range in age from 3.5 to 2.8 Ga, and serve as representatives of their crustal sources through time. Their Hf isotopic compositions show a trend from strongly positive εHf initial values for the oldest samples, to strongly negative values for the younger samples, indicating a shift from juvenile to differentiated material. These results confirm a significant change in the character of the source region of the black shales by 3 Ga, consistent with models invoking a change in global dynamics from crustal growth towards crustal reworking around this time.

Stream measurements locate thermogenic methane fluxes in groundwater discharge in an area of shale-gas development.

PubMed

Heilweil, Victor M; Grieve, Paul L; Hynek, Scott A; Brantley, Susan L; Solomon, D Kip; Risser, Dennis W

2015-04-07

The environmental impacts of shale-gas development on water resources, including methane migration to shallow groundwater, have been difficult to assess. Monitoring around gas wells is generally limited to domestic water-supply wells, which often are not situated along predominant groundwater flow paths. A new concept is tested here: combining stream hydrocarbon and noble-gas measurements with reach mass-balance modeling to estimate thermogenic methane concentrations and fluxes in groundwater discharging to streams and to constrain methane sources. In the Marcellus Formation shale-gas play of northern Pennsylvania (U.S.A.), we sampled methane in 15 streams as a reconnaissance tool to locate methane-laden groundwater discharge: concentrations up to 69 μg L(-1) were observed, with four streams ≥ 5 μg L(-1). Geochemical analyses of water from one stream with high methane (Sugar Run, Lycoming County) were consistent with Middle Devonian gases. After sampling was completed, we learned of a state regulator investigation of stray-gas migration from a nearby Marcellus Formation gas well. Modeling indicates a groundwater thermogenic methane flux of about 0.5 kg d(-1) discharging into Sugar Run, possibly from this fugitive gas source. Since flow paths often coalesce into gaining streams, stream methane monitoring provides the first watershed-scale method to assess groundwater contamination from shale-gas development.

An experimental platform for triaxial high-pressure/high-temperature testing of rocks using computed tomography

NASA Astrophysics Data System (ADS)

Glatz, Guenther; Lapene, Alexandre; Castanier, Louis M.; Kovscek, Anthony R.

2018-04-01

A conventional high-pressure/high-temperature experimental apparatus for combined geomechanical and flow-through testing of rocks is not X-ray compatible. Additionally, current X-ray transparent systems for computed tomography (CT) of cm-sized samples are limited to design temperatures below 180 °C. We describe a novel, high-temperature (>400 °C), high-pressure (>2000 psi/>13.8 MPa confining, >10 000 psi/>68.9 MPa vertical load) triaxial core holder suitable for X-ray CT scanning. The new triaxial system permits time-lapse imaging to capture the role of effective stress on fluid distribution and porous medium mechanics. System capabilities are demonstrated using ultimate compressive strength (UCS) tests of Castlegate sandstone. In this case, flooding the porous medium with a radio-opaque gas such as krypton before and after the UCS test improves the discrimination of rock features such as fractures. The results of high-temperature tests are also presented. A Uintah Basin sample of immature oil shale is heated from room temperature to 459 °C under uniaxial compression. The sample contains kerogen that pyrolyzes as temperature rises, releasing hydrocarbons. Imaging reveals the formation of stress bands as well as the evolution and connectivity of the fracture network within the sample as a function of time.

An experimental platform for triaxial high-pressure/high-temperature testing of rocks using computed tomography.

PubMed

Glatz, Guenther; Lapene, Alexandre; Castanier, Louis M; Kovscek, Anthony R

2018-04-01

A conventional high-pressure/high-temperature experimental apparatus for combined geomechanical and flow-through testing of rocks is not X-ray compatible. Additionally, current X-ray transparent systems for computed tomography (CT) of cm-sized samples are limited to design temperatures below 180 °C. We describe a novel, high-temperature (>400 °C), high-pressure (>2000 psi/>13.8 MPa confining, >10 000 psi/>68.9 MPa vertical load) triaxial core holder suitable for X-ray CT scanning. The new triaxial system permits time-lapse imaging to capture the role of effective stress on fluid distribution and porous medium mechanics. System capabilities are demonstrated using ultimate compressive strength (UCS) tests of Castlegate sandstone. In this case, flooding the porous medium with a radio-opaque gas such as krypton before and after the UCS test improves the discrimination of rock features such as fractures. The results of high-temperature tests are also presented. A Uintah Basin sample of immature oil shale is heated from room temperature to 459 °C under uniaxial compression. The sample contains kerogen that pyrolyzes as temperature rises, releasing hydrocarbons. Imaging reveals the formation of stress bands as well as the evolution and connectivity of the fracture network within the sample as a function of time.

Application of magnetic techniques to lateral hydrocarbon migration - Lower Tertiary reservoir systems, UK North Sea

NASA Astrophysics Data System (ADS)

Badejo, S. A.; Muxworthy, A. R.; Fraser, A.

2017-12-01

Pyrolysis experiments show that magnetic minerals can be produced inorganically during oil formation in the `oil-kitchen'. Here we try to identify a magnetic proxy that can be used to trace hydrocarbon migration pathways by determining the morphology, abundance, mineralogy and size of the magnetic minerals present in reservoirs. We address this by examining the Tay formation in the Western Central Graben in the North Sea. The Tertiary sandstones are undeformed and laterally continuous in the form of an east-west trending channel, facilitating long distance updip migration of oil and gas to the west. We have collected 179 samples from 20 oil-stained wells and 15 samples from three dry wells from the British Geological Survey Core Repository. Samples were selected based on geological observations (water-wet sandstone, oil-stained sandstone, siltstones and shale). The magnetic properties of the samples were determined using room-temperature measurements on a Vibrating Sample Magnetometer (VSM), low-temperature (0-300K) measurements on a Magnetic Property Measurement System (MPMS) and high-temperature (300-973K) measurements on a Kappabridge susceptibility meter. We identified magnetite, pyrrhotite, pyrite and siderite in the samples. An increasing presence of ferrimagnetic iron sulphides is noticed along the known hydrocarbon migration pathway. Our initial results suggest mineralogy coupled with changes in grain size are possible proxies for hydrocarbon migration.

Quantifying alkane emissions in the Eagle Ford Shale using boundary layer enhancement

NASA Astrophysics Data System (ADS)

Roest, Geoffrey; Schade, Gunnar

2017-09-01

The Eagle Ford Shale in southern Texas is home to a booming unconventional oil and gas industry, the climate and air quality impacts of which remain poorly quantified due to uncertain emission estimates. We used the atmospheric enhancement of alkanes from Texas Commission on Environmental Quality volatile organic compound monitors across the shale, in combination with back trajectory and dispersion modeling, to quantify C2-C4 alkane emissions for a region in southern Texas, including the core of the Eagle Ford, for a set of 68 days from July 2013 to December 2015. Emissions were partitioned into raw natural gas and liquid storage tank sources using gas and headspace composition data, respectively, and observed enhancement ratios. We also estimate methane emissions based on typical ethane-to-methane ratios in gaseous emissions. The median emission rate from raw natural gas sources in the shale, calculated as a percentage of the total produced natural gas in the upwind region, was 0.7 % with an interquartile range (IQR) of 0.5-1.3 %, below the US Environmental Protection Agency's (EPA) current estimates. However, storage tanks contributed 17 % of methane emissions, 55 % of ethane, 82 % percent of propane, 90 % of n-butane, and 83 % of isobutane emissions. The inclusion of liquid storage tank emissions results in a median emission rate of 1.0 % (IQR of 0.7-1.6 %) relative to produced natural gas, overlapping the current EPA estimate of roughly 1.6 %. We conclude that emissions from liquid storage tanks are likely a major source for the observed non-methane hydrocarbon enhancements in the Northern Hemisphere.

Lithofacies, age, depositional setting, and geochemistry of the Otuk Formation in the Red Dog District, northwestern Alaska

USGS Publications Warehouse

Dumoulin, Julie A.; Burruss, Robert A.; Blome, Charles D.

2013-01-01

Complete penetration of the Otuk Formation in a continuous drill core (diamond-drill hole, DDH 927) from the Red Dog District illuminates the facies, age, depositional environment, source rock potential, and isotope stratigraphy of this unit in northwestern Alaska. The section, in the Wolverine Creek plate of the Endicott Mountains Allochthon (EMA), is ~82 meters (m) thick and appears structurally uncomplicated. Bedding dips are generally low and thicknesses recorded are close to true thicknesses. Preliminary synthesis of sedimentologic, paleontologic, and isotopic data suggests that the Otuk succession in DDH 927 is a largely complete, albeit condensed, marine Triassic section in conformable contact with marine Permian and Jurassic strata. The Otuk Formation in DDH 927 gradationally overlies gray siliceous mudstone of the Siksikpuk Formation (Permian, based on regional correlations) and underlies black organic-rich mudstone of the Kingak(?) Shale (Jurassic?, based on regional correlations). The informal shale, chert, and limestone members of the Otuk are recognized in DDH 927, but the Jurassic Blankenship Member is absent. The lower (shale) member consists of 28 m of black to light gray, silty shale with as much as 6.9 weight percent total organic carbon (TOC). Thin limy layers near the base of this member contain bivalve fragments (Claraia sp.?) consistent with an Early Triassic (Griesbachian-early Smithian) age. Gray radiolarian chert dominates the middle member (25 m thick) and yields radiolarians of Middle Triassic (Anisian and Ladinian) and Late Triassic (Carnian-late middle Norian) ages. Black to light gray silty shale, like that in the lower member, forms interbeds that range from a few millimeters to 7 centimeters in thickness through much of the middle member. A distinctive, 2.4-m-thick interval of black shale and calcareous radiolarite ~17 m above the base of the member has as much as 9.8 weight percent TOC, and a 1.9-m-thick interval of limy to cherty mudstone immediately above this contains radiolarians, foraminifers, conodonts, and halobiid bivalve fragments. The upper (limestone) member (29 m thick) is lime mudstone with monotid bivalves and late Norian radiolarians, overlain by gray chert that contains Rhaetian (latest Triassic) radiolarians; Rhaetian strata have not previously been documented in the Otuk. Rare gray to black shale interbeds in the upper member have as much as 3.4 weight percent TOC. At least 35 m of black mudstone overlies the limestone member; these strata lack interbeds of oil shale and chert that are characteristic of the Blankenship, and instead they resemble the Kingak Shale. Vitrinite reflectance values (2.45 and 2.47 percent Ro) from two samples of black shale in the chert member indicate that these rocks reached a high level of thermal maturity within the dry gas window. Regional correlations indicate that lithofacies in the Otuk Formation vary with both structural and geographic position. For example, the shale member of the Otuk in the Wolverine Creek plate includes more limy layers and less barite (as blades, nodules, and lenses) than equivalent strata in the structurally higher Red Dog plate of the EMA, but it has fewer limy layers than the shale member in the EMA ~450 kilometers (km) to the east at Tiglukpuk Creek. The limestone member of the Otuk is thicker in the Wolverine Creek plate than in the Red Dog plate and differs from this member in EMA sections to the east in containing an upper cherty interval that lacks monotids; a similar interval is seen at the top of the Otuk Formation ~125 km to the west (Lisburne Peninsula). Our observations are consistent with the interpretations of previous researchers that Otuk facies become more distal in higher structural positions and that within a given structural level more distal facies occur to the west. Recent paleogeographic reconstructions indicate that the Otuk accumulated at a relatively high paleolatitude with a bivalve fauna typical of the Boreal realm. A suite of δ13Corg (carbon isotopic composition of carbon) data (n=38) from the upper Siksikpuk Formation through the Otuk Formation and into the Kingak(?) Shale in DDH 927 shows a pattern of positive and negative excursions similar to those reported elsewhere in Triassic strata. In particular, a distinct negative excursion at the base of the Otuk (from ‒23.8 to ‒31.3‰ (permil, or parts per thousand)) likely correlates with a pronounced excursion that marks the Permian-Triassic boundary at many localities worldwide. Another feature of the Otuk δ13Corg record that may correlate globally is a series of negative and positive excursions in the lower member. At the top of the Otuk in DDH 927, the δ13Corg values are extremely low and may correlate with a negative excursion that is widely observed at the Triassic-Jurassic boundary.

Description and correlation of reservoir heterogenity within the Big Injun sandstone, Granny Creek field, West Virginia

DOE Office of Scientific and Technical Information (OSTI.GOV)

Vargo, A.; McDowell, R.; Matchen, D.

1992-01-01

The Granny Creek field (approximately 6 sq. miles in area), located in Clay and Roane counties, West Virginia, produces oil from the Big Injun sandstone (Lower Mississippian). Analysis of 15 cores, 22 core analyses, and approximately 400 wireline logs (gamma ray and bulk density) show that the Big Injun (approximately 12 to 55 feet thick) can be separated into an upper, coarse-grained sandstone and a lower, fine-grained sandstone. The Big Injun is truncated by an erosional unconformity of Early to Middle Mississippian age which removes the coarse-grain upper unit in the northwest portion of the field. The cores show nodulesmore » and zones (1 inch to 6 feet thick) of calcite and siderite cement. Where the cements occur as zones, porosity and permeability are reduced. Thin shales (1 inch to 1 foot thick) are found in the coarse-grained member of the Big Injun, whereas the bottom of the fine-grained, lower member contains intertongues of dark shale which cause pinchouts in porosity at the bottom of the reservoir. Calcite and siderite cement are recognized on wireline logs as high bulk density zones that form horizontal, inclined, and irregular pods of impermeable sandstone. At a 400 foot well spacing, pods may be confined to a single well or encompass as many as 30 wells creating linear and irregular barriers to flow. These pods increase the length of the fluid flow path and may divide the reservoir into discrete compartments. The combination of sedimentologic and diagenetic features contribute to the heterogeneity observed in the field.« less

Reservoir characteristics of two minter oil sands based on continuous core, E-logs, and geochemical data: Bee Brake field, East-Central Louisiana

DOE Office of Scientific and Technical Information (OSTI.GOV)

Echols, J.B.; Goddard, D.A.; Bouma, A.

The Bee Brake field area, located in township 4N/6E and 4N/7E in Concordia Parish, has been one of the more prolific oil-producing areas in east-central Louisiana. Production decline in various fields, however, has sparked interest in the economic feasibility of locating and producing the remaining bypassed oil in the lower Wilcox. For this purpose, the Angelina BBF No. 1 well was drilled, and a 500-ft conventional core and a complete suite of state-of-the-are wireline logs were recovered. Production tests were run on the Minter interval of interest. The 16-ft Minter interval (6742-6758 ft depth), bounded at its top and basemore » by lignite seams, consists of an upper 4-ft oil sand (Bee Brake) and a lower 3-ft oil sand (Angelina). The oil sands are separated by approximately 5 ft of thinly laminated silty shale and 4 ft of very fine-grained silty sandstone. Detailed sedimentologic and petrographic descriptions of the Minter interval provide accurate facies determinations of this lower delta-plain sequence. Petrophysical evaluation, combining core plug and modern electric-log data show differences between reservoir quality of the Bee Brake and Angelina sands. This data will also be useful for correlating and interpolating old electric logs. Organic geochemistry of the oil, lignites, and shales provides insight as to the source of the Minter oils and the sourcing potential of the lignites.« less

On the origin of a phosphate enriched interval in the Chattanooga Shale (Upper Devonian) of Tennessee-A combined sedimentologic, petrographic, and geochemical study

NASA Astrophysics Data System (ADS)

Li, Yifan; Schieber, Juergen

2015-11-01

The Devonian Chattanooga Shale contains an uppermost black shale interval with dispersed phosphate nodules. This interval extends from Tennessee to correlative strata in Kentucky, Indiana, and Ohio and represents a significant period of marine phosphate fixation during the Late Devonian of North America. It overlies black shales that lack phosphate nodules but otherwise look very similar in outcrop. The purpose of this study is to examine what sets these two shales apart and what this difference tells us about the sedimentary history of the uppermost Chattanooga Shale. In thin section, the lower black shales (PBS) show pyrite enriched laminae and compositional banding. The overlying phosphatic black shales (PhBS) are characterized by phosbioclasts, have a general banded to homogenized texture with reworked layers, and show well defined horizons of phosphate nodules that are reworked and transported. In the PhBS, up to 8000 particles of P-debris per cm2 occur in reworked beds, whereas the background black shale shows between 37-88 particles per cm2. In the PBS, the shale matrix contains between 8-16 phosphatic particles per cm2. The shale matrix in the PhBS contains 5.6% inertinite, whereas just 1% inertinite occurs in the PBS. The shale matrix in both units is characterized by flat REE patterns (shale-normalized), whereas Phosbioclast-rich layers in the PhBS show high concentrations of REEs and enrichment of MREEs. Negative Ce-anomalies are common to all samples, but are best developed in association with Phosbioclasts. Redox-sensitive elements (Co, U, Mo) are more strongly enriched in the PBS when compared to the PhBS. Trace elements associated with organic matter (Cu, Zn, Cd, Ni) show an inverse trend of enrichment. Deposited atop a sequence boundary that separates the two shale units, the PhBS unit represents a transgressive systems tract and probably was deposited in shallower water than the underlying PBS interval. The higher phosphate content in the PhBS is interpreted as the result of a combination of lower sedimentation rates with reworking/winnowing episodes. Three types of phosphatic beds that reflect different degrees of reworking intensity are observed. Strong negative Ce anomalies and abundant secondary marcasite formation in the PhBS suggests improved aeration of the water column, and improved downward diffusion of oxygen into the sediment. The associated oxidation of previously formed pyrite resulted in a lowering of pore water pH and forced dissolution of biogenic phosphate. Phosphate dissolution was followed by formation of secondary marcasite and phosphate. Repeated, episodic reworking caused repetitive cycles of phosphatic dissolution and reprecipitation, enriching MREEs in reprecipitated apatite. A generally "deeper" seated redox boundary favored P-remineralization within the sediment matrix, and multiple repeats of this process in combination with wave and current reworking at the seabed led to the formation of larger phosphatic aggregates and concentration of phosphate nodules in discrete horizons.

Fungal diversity in major oil-shale mines in China.

PubMed

Jiang, Shaoyan; Wang, Wenxing; Xue, Xiangxin; Cao, Chengyou; Zhang, Ying

2016-03-01

As an insufficiently utilized energy resource, oil shale is conducive to the formation of characteristic microbial communities due to its special geological origins. However, little is known about fungal diversity in oil shale. Polymerase chain reaction cloning was used to construct the fungal ribosomal deoxyribonucleic acid internal transcribed spacer (rDNA ITS) clone libraries of Huadian Mine in Jilin Province, Maoming Mine in Guangdong Province, and Fushun Mine in Liaoning Province. Pure culture and molecular identification were applied for the isolation of cultivable fungi in fresh oil shale of each mine. Results of clone libraries indicated that each mine had over 50% Ascomycota (58.4%-98.9%) and 1.1%-13.5% unidentified fungi. Fushun Mine and Huadian Mine had 5.9% and 28.1% Basidiomycota, respectively. Huadian Mine showed the highest fungal diversity, followed by Fushun Mine and Maoming Mine. Jaccard indexes showed that the similarities between any two of three fungal communities at the genus level were very low, indicating that fungi in each mine developed independently during the long geological adaptation and formed a community composition fitting the environment. In the fresh oil-shale samples of the three mines, cultivable fungal phyla were consistent with the results of clone libraries. Fifteen genera and several unidentified fungi were identified as Ascomycota and Basidiomycota using pure culture. Penicillium was the only genus found in all three mines. These findings contributed to gaining a clear understanding of current fungal resources in major oil-shale mines in China and provided useful information for relevant studies on isolation of indigenous fungi carrying functional genes from oil shale. Copyright © 2015. Published by Elsevier B.V.

Measurements of Methane Emissions and Volatile Organic Compounds from Shale Gas Operations in the Marcellus Shale

NASA Astrophysics Data System (ADS)

Omara, M.; Subramanian, R.; Sullivan, M.; Robinson, A. L.; Presto, A. A.

2014-12-01

The Marcellus Shale is the most expansive shale gas reserve in play in the United States, representing an estimated 17 to 29 % of the total domestic shale gas reserves. The rapid and extensive development of this shale gas reserve in the past decade has stimulated significant interest and debate over the climate and environmental impacts associated with fugitive releases of methane and other pollutants, including volatile organic compounds. However, the nature and magnitude of these pollutant emissions remain poorly characterized. This study utilizes the tracer release technique to characterize total fugitive methane release rates from natural gas facilities in southwestern Pennsylvania and West Virginia that are at different stages of development, including well completion flowbacks and active production. Real-time downwind concentrations of methane and two tracer gases (acetylene and nitrous oxide) released onsite at known flow rates were measured using a quantum cascade tunable infrared laser differential absorption spectrometer (QC-TILDAS, Aerodyne, Billerica, MA) and a cavity ring down spectrometer (Model G2203, Picarro, Santa Clara, CA). Evacuated Silonite canisters were used to sample ambient air during downwind transects of methane and tracer plumes to assess volatile organic compounds (VOCs). A gas chromatograph with a flame ionization detector was used to quantify VOCs following the EPA Method TO-14A. A preliminary assessment of fugitive emissions from actively producing sites indicated that methane leak rates ranged from approximately 1.8 to 6.2 SCFM, possibly reflecting differences in facility age and installed emissions control technology. A detailed comparison of methane leak rates and VOCs emissions with recent published literature for other US shale gas plays will also be discussed.

Influence of Composition and Deformation Conditions on the Strength and Brittleness of Shale Rock

NASA Astrophysics Data System (ADS)

Rybacki, E.; Reinicke, A.; Meier, T.; Makasi, M.; Dresen, G. H.

2015-12-01

Stimulation of shale gas reservoirs by hydraulic fracturing operations aims to increase the production rate by increasing the rock surface connected to the borehole. Prospective shales are often believed to display high strength and brittleness to decrease the breakdown pressure required to (re-) initiate a fracture as well as slow healing of natural and hydraulically induced fractures to increase the lifetime of the fracture network. Laboratory deformation tests were performed on several, mainly European black shales with different mineralogical composition, porosity and maturity at ambient and elevated pressures and temperatures. Mechanical properties such as compressive strength and elastic moduli strongly depend on shale composition, porosity, water content, structural anisotropy, and on pressure (P) and temperature (T) conditions, but less on strain rate. We observed a transition from brittle to semibrittle deformation at high P-T conditions, in particular for high porosity shales. At given P-T conditions, the variation of compressive strength and Young's modulus with composition can be roughly estimated from the volumetric proportion of all components including organic matter and pores. We determined also brittleness index values based on pre-failure deformation behavior, Young's modulus and bulk composition. At low P-T conditions, where samples showed pronounced post-failure weakening, brittleness may be empirically estimated from bulk composition or Young's modulus. Similar to strength, at given P-T conditions, brittleness depends on the fraction of all components and not the amount of a specific component, e.g. clays, alone. Beside strength and brittleness, knowledge of the long term creep properties of shales is required to estimate in-situ stress anisotropy and the healing of (propped) hydraulic fractures.

Multi-scale Multi-dimensional Imaging and Characterization of Oil Shale Pyrolysis

NASA Astrophysics Data System (ADS)

Gao, Y.; Saif, T.; Lin, Q.; Al-Khulaifi, Y.; Blunt, M. J.; Bijeljic, B.

2017-12-01

The microstructural evaluation of fine grained rocks is challenging which demands the use of several complementary methods. Oil shale, a fine-grained organic-rich sedimentary rock, represents a large and mostly untapped unconventional hydrocarbon resource with global reserves estimated at 4.8 trillion barrels. The largest known deposit is the Eocene Green River Formation in Western Colorado, Eastern Utah, and Southern Wyoming. An improved insight into the mineralogy, organic matter distribution and pore network structure before, during and after oil shale pyrolysis is critical to understanding hydrocarbon flow behaviour and improving recovery. In this study, we image Mahogany zone oil shale samples in two dimensions (2-D) using scanning electron microscopy (SEM), and in three dimensions (3-D) using focused ion beam scanning electron microscopy (FIB-SEM), laboratory-based X-ray micro-tomography (µCT) and synchrotron X-ray µCT to reveal a complex and variable fine grained microstructure dominated by organic-rich parallel laminations which are tightly bound in a highly calcareous and heterogeneous mineral matrix. We report the results of a detailed µCT study of the Mahogany oil shale with increasing pyrolysis temperature. The physical transformation of the internal microstructure and evolution of pore space during the thermal conversion of kerogen in oil shale to produce hydrocarbon products was characterized. The 3-D volumes of pyrolyzed oil shale were reconstructed and image processed to visualize and quantify the volume and connectivity of the pore space. The results show a significant increase in anisotropic porosity associated with pyrolysis between 300-500°C with the formation of micron-scale connected pore channels developing principally along the kerogen-rich lamellar structures.