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At least 181 records · Page 10
All sourcesNASA NTRSDOE OSTI
DOE OSTI2021

New Fracture Diagnostic Tool for Unconventionals: High-Resolution Distributed Strain Sensing via Rayleigh Frequency Shift during Production in Hydraulic Fracture Test 2

Fiber Optic monitoring in unconventional reservoirs has proven to be an invaluable diagnostic tool for assessing both near-wellbore stimulation effectiveness and to help describe the far-field frac geometries created by hydraulic fracture stimulation. Unfortunately, gaining any detailed qualitative and quantitative understanding of the near-wellbore frac geometry or cluster/stage productivity during production via Fiber Optic (FO) has proven to be more difficult, particularly in wells producing liquids. A new FO diagnostic method, Distributed Strain Sensing based on Rayleigh Frequency Shift (DSS-RFS), first demonstrated for oil and gas applications in the Hydraulic Test Site 2 (HFTS2) provides new insights about the characteristics of near-wellbore-region (NWR) during production. DSS-RFS is different from other FO strain measurements because it relies on accurate measurement of frequency shifts of Rayleigh backscattered spectrum obtained by scanning the fiber with a coherent optical time-domain reflectometer with a range of laser frequencies using a tunable-wavelength laser system. Changes in strain are measured with an extremely high spatial resolution of 20 cm and with high signal-to-noise ratios over long distances. In HFTS2, strain changes for the entire wellbore have been measured twice during scheduled shut-in and reopening operations (February 2020 and September 2020). After removing temperature effects, consistent strain changes have been observed at the location of most perforation clusters. These are caused by near wellbore fracture aperture changes due to pressure increases during shut-in within the near-wellbore fracture network. The strain-change patterns from the DSS-RFS during shut-in correlate very well with the location of clusters and allow for the definition of extending intervals with positive strain signals at each cluster and slightly compressing intervals with negative strain signals between the clusters and in the non stimulated intervals. The locations of the measured positive strain peaks also show good correspondence to DAS acoustic intensity measurements acquired during the stimulation. The geometry and magnitude of the strain changes differ significantly between the two tested completion designs in the same well. During shut in and reopening each cluster exhibit its own strain-change / pressure path. In addition, the September 2020 dataset also revealed the existence of small but measurable strain changes as consequence of pressure decline during production. These strain changes also correlate well with the presence of producing clusters, but the strain-rate signals are opposite to that obtained during shut-in and reopening operations. Although Downloaded from http://onepetro.org/URTECONF/proceedings-pdf/21URTC/2-21URTC/D021S031R002/2477551/urtec-2021-5408-ms.pdf/1 by Carol Worster on 28 February 2022 URTeC 5408 2 we are still in the early stages of exploring the potential of this novel FO technique, we believe that the highly detailed information contained in the measurement of strain changes using DSS-RFS during production can significantly improve our understanding of near-wellbore hydraulic fracture characteristics and the relationships between stimulation and production from unconventional oil and gas wells.

04 OIL SHALES AND TAR SANDS↗
DOE OSTI2023

HFTS-1 (Final Report)

Despite the long history of hydraulic fracturing, the optimal number of fracturing stages during multi-stage fracture stimulation in horizontal wells can be a complex subject. In addition to the increased expense of multistage fracturing in horizontal wells, increasing the number of fracturing stages does not always correlate with a commensurate increase in production. The problem is the application of a uniform fracture stimulation design to all stages with no consideration for geological variations along the wellbore. The result is an inefficient use and costly waste of energy and water. Optimization of the fracturing process requires an understanding of the cause-and-effect relationship between fracturing parameters and local geological properties at a given location along the wellbore. Realizing that the generalized rock mechanics theories and hypotheses are not truly applicable to fractured and laminated shales, quantifiable impacts of a shale’s geomechanical and depositional features are a prerequisite for design and implementation of optimized hydraulic fractures. The overarching goal of this project is to understand and define the relationships of shale geology and fracture dynamics using detailed field data that includes coring of the fracture domain. Finally, resource recovery from shale formations is estimated to be less than fifteen percent. Research proposed in this project will establish the foundations for investigating enhanced recovery techniques for increased resource recovery in existing fracture treated wells. Natural gas as an EOR fluid is in the initial stages of being used broadly in the oil and gas industry and as such, many aspects of the process need to be researched and addressed prior to widespread acceptance. In addition, re-fracturing techniques, particularly using cemented liners also need to be further investigated. This project explores several of these EOR techniques in greater detail, not just at the theoretical level, but through actual field test sites. This report delves into the research program, identified tasks, several studies, observations, results, and conclusions under the Hydraulic Fracturing Test Site (HFTS) project. This test project is subdivided into three distinct phases and each phase is discussed in detail under separate sections. The original test site for Phase 1 as well as the Phase 2 site are in Midland Basin in Texas and operated by Laredo Petroleum. In the first two phases, the program targeted the Wolfcamp formation in Midland Basin. Phase 3 of the study targeted the EagleFord play in South Texas with Devon Energy as the operator. Significant conclusions from this study include: 1) lateral and vertical fracture growth mapping as well as proppant transport behavior, 2) Use of field gas and its applicability for huff n puff EOR injection in the Midland Basin, 3) Development and validation of proppant log, both at core scale as well as in-fill well implementation by analyzing drilling mud return samples, 4) Applicability of liner refracturing including best practices for enhanced unit level productivity. This report will detail all these studies as well as technical results and conclusions from said studies. These include general subsurface characterization work, completion designs as implemented, studies looking at fracture geometry, high resolution microseismic study, advanced crosswell strain mapping studies including drainage characterization, core characterization results, proppant analysis (core and observation wells), geochemistry, etc. to name a few.

02 PETROLEUM↗
DOE OSTI2021

Formulation of low clinker blended cements and concrete with enhanced fresh and hardened properties

Blended cements appear as the most promising way to massively produce cements with reduced environmental footprints. However, considering the generally lower early mechanical performance of highly blended cements, chemical admixtures are increasingly relied upon to increase early strength. However, in many cases this can negatively impact other properties as rheology and durability. This paper proposes an approach to formulate low clinker cements and concrete using moderate alkali activation or gypsum to enhance early and long-term compressive strength, without inducing excessive alkali-silica reaction (ASR) expansion. It examines blended cements containing burnt oil shale along with limestone and fly ash or slag as supplementary cementitious materials. It optimizes the combination of polycarboxylate ether (PCE) superplasticizers with the strength enhancers. Along with the use of Ca(NO{sub 3}){sub 2} to drive PCE adsorption, this provides good rheology control, increased early and long-term compressive strength, as well as acceptable ASR expansion in cements with only 50% clinker.

36 MATERIALS SCIENCE↗
NASA NTRS1993

Petrography and preliminary interpretations of the crystalline breccias from the Manson M-1 core

The M-1 core was drilled on the eastern edge of the central uplift within the Manson Impact Structure in Iowa. The lower 107.9 m of the core consists of crystalline breccias. Twelve intervals of thin sections from this core have been studied for preliminary discussion. The breccias are divided into three units by matrix size and abundance. Unit 1 is characterized by a high volume fraction of matrix, and a decreasing proportion of matrix with depth. This matrix is nearly isotropic and consists of grains less than 0.005 to less than 0.02 mm in length. The matrix between 112 and 146 meters depth consists of a crystalline intergrowth of felsic and opaque minerals with or without chlorite. This was the hottest section of the core after impact, and may have undergone high temperature metamorphic recrystallization. Unit 2 is transitional between units 1 and 3, and is delineated by a rapid increase in grain size to .01-.04 mm and a decrease in matrix abundance to 10 percent. Unit 3 has a coarse, often porous matrix, whose abundance changes from about 10 percent at the top to about 2 percent at the base. Grain sizes range from 0.01-0.1 mm over this interval and coarsen with depth. Changes in the character of the matrix as well as the changes in clast lithology and abundance outlined below suggest that unit 3 is in-situ brecciated basement with injected melt and shale fragments; unit 1 is a crater veneer deposit consisting of transported basement materials and unit 2 is a mixed zone between units 1 and 3.

Bell, M. S.↗
DOE OSTI2021

Mechanical Properties of Nominally Ductile and Brittle Zones within the Caney Shale Formation

We present a case study from the Caney Shale, which is an emerging hydrocarbon-bearing formation in Oklahoma. Open hole logs lead to a nominal distinction of five zones in an exploration well, two of which are designated “ductile” and three of which are designated as less ductile “reservoir” zones. Subsequently, a detailed mechanical characterization was carried out on core plugs taken from each of these zones. Results show nominally “ductile” zones are weaker in terms of UCS, tensile strength, fracture toughness, and confined compressive strength. However, by a variety of brittleness indices, it is found the nominal “ductile” regions do not behave as expected. They are weaker, but not consistently more ductile. Furthermore, some brittleness indices lead to contradictory conclusions. For example, zones which would be considered the most brittle according to the proportion of nonlinear stress-strain behavior prior to failure and/or by indices based on elastic properties would be considered the least brittle according to their internal friction angle.

Benge, Margaret↗
DOE OSTI2024

Assessing Suitable Geologic Carbon Storage Sites Across Utah

Utah has a wealth of potential geological reservoirs for carbon dioxide storage (CS) and a long history of geologic research resulting in an abundance of available subsurface data to evaluate CS potential. Reservoirs may include sandstone, carbonate, and basalt; these rock types are plentiful in Utah’s subsurface and the complex Phanerozoic history throughout the state requires evaluating each geologic region individually for promising reservoir-seal pairs for CO2 storage. Classifying Utah by geologic provinces (or “geo-regions”) allows for customized thinking about suitable CS reservoir and seal distribution, CO2 point sources, land use, and existing infrastructure. Preliminary results from this study highlight the geologic CS potential across 15 geo-regions. Four regions stand out as having high CS potential: the Uinta Basin, San Rafael Swell, Paradox Basin, and the southern Basin and Range Province. The Uinta Basin and San Rafael Swell geo-regions are well suited for CS and have several projects ongoing to evaluate Cretaceous Frontier and Naturita Formations, Jurassic Navajo Sandstone and Entrada Sandstone, and Permian Weber Sandstone reservoir units that lie beneath robust sealing units like the ~5000-ft-thick Mancos Shale and Carmel Formation. Reservoirs such as the Navajo and Weber Sandstones have been demonstrated to be suitable reservoirs through a long history of oil and gas exploration in Utah. New areas of interest include the southern Basin and Range in southwest Utah, where the Jurassic Navajo Sandstone is overlain by the sealing Carmel Formation at suitable depths (>3000 ft), and has good porosities based on outcrop analogue data. Just to the north (e.g., central Basin and Range), legacy wells and 2D seismic data show possible salt and subsurface basalt flows that may provide additional possible CS reservoirs and seals. This geo-region also has the advantage of being coupled with geothermal energy resources that may be used to power burgeoning direct air capture technologies. In the Paradox Basin of southeastern Utah, the Leadville Limestone is a potential storage reservoir beneath the thick (4000–5000 ft), salt-bearing Pennsylvanian Paradox Formation. Although the northern and western parts of Utah offer CS potential, these areas typically contain less infrastructure and subsurface penetrations, creating geologic uncertainty associated with subsurface seals and reservoirs due to a lack of data. Overall, this statewide assessment and ranking is the first step to aid in evaluating CS potential across Utah and provides a foundation for future research in the most favorable locations.

58 GEOSCIENCES↗
DOE OSTI2023

NETL’s Perspective on Storage Efficiency and CO2-SCREEN

Carbon capture and storage (CCS) is a process that captures carbon dioxide (CO2) by separating it from anthropogenic emissions sources before atmospheric release and storing that CO2 in deep geologic reservoirs. CCS is a powerful method for reducing anthropogenic CO2 which can ultimately diminish the effects of climate change. Prospective CO2 storage resource is the amount of carbon dioxide that can be stored in a given geologic formation typically given as a mass (e.g., metric tons). Obtaining accurate estimates of CO2 storage resources is necessary for governments and industries to make energy-related policy decisions. Researchers at the National Energy Technology Laboratory (NETL) under the Department of Energy (DOE) developed a methods and a tool [CO2-SCREEN (Storage prospeCtive Resource Estimation Excel aNalysis) to estimate prospective carbon storage resources for saline formations, unconventional shale formations, and residual oil zones. The methods and tool provide CO2 storage and efficiency outputs in the form of probability estimates (i.e. P10 and P90) as well as partitioning storage and efficiency estimates based on storage mechanism (total, free phase, sorbed phase, and dissolution phase). This presentation will focus on how storage efficiency is calculated based on numerical modeling efforts, how it’s applied in the storage methods and tool, and then highlighting needs for future development.

Hanson, Angela Goodman↗
DOE OSTI2023

From Well Log to Formation Model: A Novel Laboratory Calibrated Methodology with Demonstration

This work demonstrates how the characterization and modeling of both elastic and creep properties are essential to describe zones in layered rock formations as either low-stress targets for stimulation or high-stress barriers to fracture growth. Prediction of fracture height is critical for designing stimulation operations in oil and gas wells. Ideally, fractures are placed in target zones which will produce hydrocarbons and should not propagate into zones expected to be unproductive or to produce unwanted fluids such as water which in turn must be treated and/or disposed. The essential task in designing stimulation plans is predicting which zones have low horizontal stresses and which will be high-stress barriers to fracture growth. Despite this importance, there are gaps in current knowledge and a complete workflow from laboratory characterization to a finite element model which includes time dependent rock deformation is required. While the research and methodology presented here also have application to CO 2or hydrogen storage, wastewater injection, and geothermal applications, the focus will be on hydrocarbon extraction. This thesis presents the results of a characterization-to-prediction workflow for the Caney shale, which is an emerging hydrocarbon resource in Oklahoma, USA. It begins with an investigation to enable critical evaluation of the Caney zonation into nominally “brittle” and “ductile” zones based on properties observed from well logs. It shows none of the zones are consistently “brittle” or “ductile” mechanical behavior based on the variety of definitions of these terms. However, the nominally ductile zones are weaker and more prone to creep. A laboratory investigation of samples including strength, elastic, and creep properties, is then used in a finite element model of stress evolution. The model includes both elastic deformation and viscoplastic creep. Results predict the least creep-prone layers to have the lowest horizontal stresses, therefore comprising hydraulic fracturing targets. The most creep-prone layers attain a horizontal stress similar to the vertical stress and therefore are predicted to be high stress barriers to hydraulic fracture stimulation. In addition to defining stimulation target intervals, the model shows how as tectonic strain rate increases, there is a transition from creep-dominated stresses to stresses dominated by elasticity.

Benge, Margaret↗
DOE OSTI2022

Carbon-efficient conversion of natural gas and natural-gas condensates to chemical products and intermediate feedstocks via catalytic metal–organic framework (MOF) chemistry

The net-zero carbon emission scenario of stopping hydrocarbon use as fuel is unlikely to end the extraction of fossil hydrocarbons. Remaining will be a sizable need for hydrocarbons as feedstocks for commodity chemicals destined for transformation into polymers, manufacturing-relevant intermediates, and value-added chemicals. Historically, the primary feedstock source has been oil. Over the past dozen years, however, fracking-based extraction of shale-trapped natural gas from known enormous reserves, in North America, has resulted in feedstock sourcing instead from wet shale gas. This shift has transformed the catalytic chemistry of commodity chemical manufacturing. In this paper, following a brief discussion of the merits and limitations of crystallographically well-defined metal–organic frameworks (MOFs) as model catalysts and catalyst-supports, we examined their applications for understanding and potentially enabling carbon-economical, catalytic transformation of C 1 , C 2 , C 3 , and C 4 components of natural gas to desirable commodity chemicals, intermediates, or model compounds.

03 NATURAL GAS↗
DOE OSTI2024

Investigating Material Properties of Subsurface Rock Formations Modified by Engineering Mineral Precipitation (Final Scientific and Technical Report)

Montana State University’s (MSU) Energy Research Institute (ERI), in collaboration with the Center for Biofilm Engineering (CBE) and the Department of Civil Engineering (CE), has conducted a long‐term research program aimed at developing a novel cementing agent to address wellbore integrity and reduce the unwanted upward migration of fluids and greenhouse gases from the subsurface. The primary technology developed through this research program is known as ureolysis‐induced calcite precipitation (UICP), which harnesses bio‐chemical processes to precipitate calcium carbonate (CaCO 3 ). The same general process can also be called microbially-induced calcium carbonate precipitation (MICP) when microbes provide the process-catalyzing urease enzyme. Both terms are used in this report. Results have conclusively demonstrated that, if properly controlled, UICP can successfully seal fractures, high permeability zones, and compromised cement in the vicinity of wellbores and in nearby caprock. This technology has been successfully deployed to mitigate annular leakage in two test wells and over sixty commercial wells with a 100% success rate. This success in downhole deployment generates consideration of other subsurface applications where UICP could provide benefit to the energy sector, such as shale property modification for unconventional oil and gas recovery. The focus of this research project was to investigate fundamental material and mechanical properties of select shale cores and analyze how these properties change due to engineered mineral precipitation with the intent to control these properties to achieve a range of engineering objectives. Ultimately, the project aim was to identify valuable new areas where application of UICP might contribute to national energy security and environmental protection. The research workplan coupled UICP treatment of core samples, nuclear magnetic resonance (NMR) characterization, and mechanical strength testing at MSU with advanced X‐Ray micro-computed tomography (μCT) imaging and numerical modeling performed by collaborators at two national laboratories, the National Energy Technology Laboratory (NETL) and Lawrence Berkeley National Laboratory (LBNL). Experimental results are useful to inform geo-mechanical models which could be applied to predict mineralized rock formation behavior at field scale. Our findings suggest that NMR and μCT methods to detect and quantify biomineral formation in shale fractures are complementary and consistent with each other. Either could be used to estimate the volume of new mineral formed by UICP in shale fractures. The use of surfactants and guar gum to enhance biomineral precipitation in shale fractures merits further research. UICP can, under some conditions, increase the tensile strength of sealed shale fractures beyond that of the intact shale. These findings demonstrate that continued research in this area may be valuable to understanding and improving shale resource recovery techniques.

58 GEOSCIENCES↗
DOE OSTI2024

Optimizing Alabama’s CO 2 Storage in Shelby County (Project OASIS) Milestone 6.0: Evaluation of Class VI Readiness

Introduction. Project OASIS is approximately 30 miles southeast of Birmingham, Alabama, and approximately 5 miles north-northwest of Alabama Power Company's Plant Gaston. Geologically, the Project area is in the Alabama fold and thrust belt province. This work builds on the initiatives of the Southeast Regional Carbon Utilization and Storage Acceleration Partnership (SECARB-USA, DE-FE0031830) that identified nearly 500 million metric tonnes of CO 2 emitted on an annual basis that is not collocated with prospective storage geology (the Coastal Plain of the Southeastern US in this context). This observation suggests costly investments in connective infrastructure (e.g., pipelines) or exploratory well drilling campaigns to identify CO 2 storage opportunities in under explored areas. While not traditionally thought of for saline storage, these studies suggest that storage prospects in the Valley and Ridge Province occur in relatively flat lying structural panels between thrust faults. For the Project OASIS region, available geologic studies related to hydrocarbon exploration suggest that Cambro-Ordovician carbonates and Cambrian clastic units offer multiple potential storage intervals, and that regional confining systems are present, such as the tectonically thickened Floyd-Parkwood Shale. The Project OASIS surface property is owned by a timber and land stewardship company, The Westervelt Company, Inc., who worked with the Project Team to select and prepare adequate sites for geologic assessment. The purpose of drilling the Westover Stratigraphic Test Well #2 was to collect geologic data to model the feasibility of commercial scale CO 2 injection and storage in an under explored region. This initiative benefits the regions emitters as the data generated from this study can inform their own internal decision making. The field program included geological and geophysical evaluations, reservoir engineering analyses, and risk assessments. This report evaluates existing data, as well as a variety of modeling scenarios to evaluate project readiness. Importantly, the impact of this study is not limited to Alabama as there are numerous large emitters throughout Appalachia, in similar geologic settings, contemplating their decarbonization options.

20 FOSSIL-FUELED POWER PLANTS↗
DOE OSTI2022

Effect of oxidative breakers on organic matter degradation, contaminant mobility and critical mineral release during shale-fracturing fluid interactions in the Marcellus Shale

Oil and gas production from organic-rich shale formations has become viable through advancements in multistage hydraulic fracturing. However, fluctuations in oil and gas prices, coupled with the sharp decline in gas production after the initial days of fracturing operations, drive operators to devise strategies for enhancing hydrocarbon production. The use of highly reactive fracturing fluids that include strong oxidizing agents, also known as breakers, can potentially increase well productivity. The oxidative breakers are used to reduce the viscosity of gel-based fluids after the proppant is transported into fracture zones of the target formation. These breakers can also degrade the organic matter, enhancing the release of hydrocarbons. However, chemical byproducts generated by the interaction of oxidative breakers with the shale matrix have not been extensively studied. Here, this study investigated the fluid-rock interactions between Marcellus Shale and synthetic hydraulic fracturing fluid (HFF) solutions comprising three different oxidative breakers, i.e., ammonium persulfate, sodium bromate, and sodium hypochlorite, commonly used in the Appalachian Basin, USA. Our results demonstrate that the type of oxidizing breakers used in the HFF controlled the type and amount of volatile organic compounds (VOCs) and semi-volatile organic compounds (SVOCs) produced. In all HFF reacted effluents, we observed the transformation of VOCs and the presence of organic acids in variable amounts. However, effluents from HFF containing sodium bromate and sodium hypochlorite breakers showed the presence of several halogenated organic compounds. Changes in major ions and mineralogy indicate that carbonate dissolution and barite precipitation were ubiquitous in all shale reacted effluents. Our results also demonstrate that the addition of oxidative breakers increased the concentration of several major and trace elements in the effluents. These elements fall under the critical mineral (CM) or critical element category due to their high demand in emerging technologies and susceptibility to supply chain disruption due to variety of factors. However, before oxidative breakers can be used at a larger field scale to enhance the release and recovery of CM and hydrocarbons, a better understanding is required of the potential environmental impacts associated with the generation and transformation of contaminants during breaker-fluid-rock interaction.

54 ENVIRONMENTAL SCIENCES↗
DOE OSTI2022

State 16-2 Well

CT scans, images, and MSCL data to accompany the State 16-2 well

Cane Creek Shale↗
DOE OSTI2023

Investigating the Roughness and Advance Rate of the Weathering Interface (Final Report)

To understand geological systems that are important to our national well-being -- such as nuclear waste repositories or hydraulically fractured rocks -- requires the ability to make quantitative projections of the evolution of rock-water systems forward in time. A fundamental goal of much of our geochemical research was focused on development of numerical models of reactive transport to simulate the evolution of natural water-rock systems. The geochemical community has provided such models and they are rapidly being improved with field-model cross-testing. This project was especially impactful in field-model testing for well-constrained weathering systems to provide new conceptual understanding of how these systems function.

04 OIL SHALES AND TAR SANDS↗
DOE OSTI2020

Bulk and position-specific isotope geochemistry of natural gases from the Late Cretaceous Eagle Ford Shale, south Texas

Here, a dataset of bulk and position-specific isotope compositions of shale gases from the Late Cretaceous Eagle Ford Shale, south Texas is reported. The chemical and bulk isotopic compositions of the seven samples in this study and those available from the literature show that across the play, produced natural gas from the Eagle Ford Shale preserves a wide range of gas compositions (wetness, ~5 to >90%) and δ 13 C values of C 1 –C 3 . The depth profiles of the isotopic compositions suggest that the western region of the Eagle Ford Shale deposit had experienced as much as 700–800 m of uplift-erosion or gas migration. The timing of and lost-gas fractions by gas expulsion events very likely affected their gas compositions and bulk isotope compositions. Some deep (>3000–3500 m), matured (%Ro > 1.5) gases with heavy δ 13 C(C 1 –C 3 ) values indicate significant loss (>50%) of the early-stage gases. For the position-specific isotope deviations of propane, the ΔC 2-1 values of the five samples show small decrease with well depths, while the ΔH 2-1 values have a general increasing trend. Although some samples fall very close to the equilibrium model trajectories with reasonable calculated temperatures (138–148 °C), the position-specific isotope compositions of propane from the Eagle Ford Shale gases are likely results of thermal cracking of various organic molecules within the source rocks, which have different activation energy for cracking and non-statistical distributions of C/H isotope within them.

58 GEOSCIENCES↗
NASA NTRS1988

Microfossils from oolites and pisolites of the Upper Proterozoic Eleonore Bay Group, Central East Greenland

Silicified oolites and pisolites from Bed 18 of the Upper Proterozoic (about 700-800 Ma) Limestone-Dolomite "Series" of the Eleonore Bay Group, central East Greenland, contain a diverse suite of organically preserved microfossils that is, for the most part. [Of the] assemblages previously described from Proterozoic cherts and shales. Three principal assemblages occur in these rocks: 1) a class bound assemblage found in detrital carbonate grains (now silicified) that served as nuclei for ooid and pisoid growth, as well as in uncoated mud and mat clasts that were carried into the zone of ooid and pisoid deposition; 2) an epilithic and interstitial assemblage consisting of microorganisms that occurred on top of and between grains; and 3) a euendolithic assemblage composed of microbes that actively bored into coated grains. The Upper Proterozoic euendolithic assemblage closely resembles a community of euendolithic cyanobacteria found today in shallow marine ooid sands of the Bahama Banks. Thirteen species are described, of which eight are new, five representing new genera: Eohyella dichotoma n. sp., Eohyella endoatracta n. sp., Eohyella rectoclada n. sp., Thylacocausticus globorum n. gen. and sp., Cunicularius halleri n. gen. and sp., Graviglomus incrustus n. gen. and sp., Perulagranum obovatum n. gen. and sp., and Parenchymodiscus endolithicus n. gen. and sp.

NASA Discipline Exobiology↗
DOE OSTI2022

The Cypress Sandstone Seal System

The Cypress Sandstone is the youngest and shallowest unit in the Illinois Basin that was featured in the United States Carbon Utilization and Storage Atlas IV as a target for saline carbon storage with an estimated 0.2 to 2.3 GT of storage potential. Additional research on a residual oil zone (ROZ) developed within the Cypress Sandstone has delineated 27 prospects with approximately 290.8 million m3 (1.8 billion barrels) of oil in place. 21 to 31 million m 3 (144 to 196 million barrels) of oil is estimated to be recoverable using carbon dioxide enhanced oil recovery (CO 2 -EOR). Storage of CO 2 associated with EOR in these ROZ prospects alone, not accounting for associated main pay zones (MPZs), underlying brine formation, or intervals adjacent to or between prospects, is estimated to be up to 10.4 billion tonnes. The Cypress Sandstone is thus well understood to be a CO 2 injection target, both for EOR and associated storage. However, the seal system overlying the Cypress Sandstone is poorly understood. Unlike deeper formations such as the Mt. Simon Sandstone or the St. Peter Sandstone which are either in use as a CO 2 sink or being characterized for prospective storage, respectively, the Cypress is not overlain by hundreds of feet of impermeable shale. Rather, the Cypress is overlain by a lithologically variable interval that is composed generally of shales and limestones with some sandstone in the part of the Basin where the Cypress is deep enough to facilitate CO 2 storage. Also, due to its status as one of the shallowest and most prolific oil reservoirs in the Basin, the seal system overlying the Cypress Sandstone has a relatively high number of legacy well penetrations. The purpose of this report is to characterize the Cypress Sandstone seal system using well logs and available core. Gross thickness, lithology (facies), and mineralogy of seals is described and mapped across the Basin. The column height of CO 2 that can be held is calculated using capillary pressure data from a representative core.

02 PETROLEUM↗