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At least 181 records · Page 10
All sourcesNASA NTRSDOE OSTI
DOE OSTI2017

Geomechanical Framework for Secure CO 2 Storage in Fractured Reservoirs and Caprocks for Sedimentary Basins in theMidwest United States

This report presents final technical results for the project Geomechanical Framework for Secure CO 2 Storage in Fractured Reservoirs and Caprocks for Sedimentary Basins in the Midwest United States (DE-FE0023330). The project was a three-year effort consisting of seven technical tasks focused on defining geomechanical factors for CO 2 storage applications in deep saline rock formations in Ohio and the Midwest United States, because geomechancial issues have been identified as a significant risk factor for large-scale CO 2 storage applications. A basin-scale stress-strain analysis was completed to describe the geomechanical setting for rock formations of Ordovician-Cambrian age in Ohio and adjacent areas of the Midwest United States in relation to geologic CO 2 storage applications. The tectonic setting, stress orientation-magnitude, and geomechanical and petrophysical parameters for CO 2 storage zones and caprocks in the region were cataloged. Ten geophysical image logs were analyzed for natural fractures, borehole breakouts, and drilling-induced fractures. The logs indicated mostly less than 10 fractures per 100 vertical feet in the borehole, with mostly N65E principal stress orientation through the section. Geophysical image logs and other logs were obtained for three wells located near the sites where specific models were developed for geomechanical simulations: Arches site in Boone County, Kentucky; Northern Appalachian Basin site in Chautauqua County, New York; and E-Central Appalachian Basin site in Tuscarawas County, Ohio. For these three wells, 9,700 feet of image logs were processed and interpreted to provide a systematic review of the distribution within each well of natural fractures, wellbore breakouts, faults, and drilling induced fractures. There were many borehole breakouts and drilling-induced tensile fractures but few natural fractures. Concentrated fractures were present at the Rome-basal sandstone and basal sandstone-Precambrian contacts at the Arches and East-Central Appalachian Basin sites. Geophysical logs were utilized to develop local-scale geologic models by determining geomechanical and petrophysical parameters within the geologic formations. These data were ported to coupled fluid-flow and reservoir geomechanics multi-phase CO 2 injection simulations. The models were developed to emphasize the geomechanical layers within the CO 2 storage zones and caprocks. A series of simulations were completed for each site to evaluate whether commercial-scale CO 2 could be safely injected into each site, given site-specific geologic and geomechanical controls. This involved analyzing the simulation results for the integrity of the caprock, intermediate, and reservoir zones, as well quantifying the areal uplift at the surface. Simulation results were also examined to ensure that the stress-stress perturbations were isolated within the subsurface, and that there was only limited upward migration of the CO 2 . Simulations showed capacity to inject more than 10 million metric tons of CO 2 in a single well at the Arches and East Central Appalachian Basin sites without excessive geomechanical risks. Low-permeability rock layers at the Northern Appalachian Basin study area well resulted in very low CO 2 injection capacity. Fracture models developed for the sites suggests that the sites have sparse fracture network in the deeper Cambrian rocks. However, there were indicators in image logs of a moderate fracture matrix in the Rose Run Sandstone at the Northern Appalachian Basin site. Dual permeability fracture matrix simulations suggest the much higher injection rates may be feasible in the fractured interval. Guidance was developed for geomechanical site characterization in the areas of geophysical logging, rock core testing, well testing, and site monitoring. The guidance demonstrates that there is a suitable array of options for addressing geomechanical issues at CO 2 storage sites. Finally, a review of Marcellus and Utica-Point Pleasant shale gas wells and CO 2 storage intervals indicates that these items are vertically separated, except for the Oriskany sandstone and Marcellus wells in southwest Pennsylvania and northern West Virginia. Together, project results present a more realistic portrayal of geomechanical risk factors related to CO 2 storage for existing and future coal-fired power plants in Ohio.

58 GEOSCIENCES↗
DOE OSTI2017

Analyzing Solutions High in Total Dissolved Solids for Rare Earth Elements (REEs) Using Cation Exchange and Online Pre-Concentration with the seaFAST2 Unit; NETL-TRS-7-2017; NETL Technical Report Series; U.S. Department of Energy, National Energy Technology Laboratory: Albany, OR, 2017; p 32

The accurate quantification of the rare earth element (REE) dissolved concentrations in natural waters are often inhibited by their low abundances in relation to other dissolved constituents such as alkali, alkaline earth elements, and dissolved solids. The high abundance of these constituents can suppress the overall analytical signal as well as create isobaric interferences on the REEs during analysis. Waters associated with natural gas operations on black shale plays are characterized by high salinities and high total dissolved solids (TDS) contents >150,000 mg/L. Methods used to isolate and quantify dissolved REEs in seawater were adapted in order to develop the capability of analyzing REEs in waters that are high in TDS. First, a synthetic fluid based on geochemical modelling of natural brine formation fluids was created within the Marcellus black shale with a TDS loading of 153,000 mg/L. To this solution, 1,000 ng/mL of REE standards was added based on preliminary analyses of experimental fluids reacted at high pressure and temperature with Marcellus black shale. These synthetic fluids were then run at three different dilution levels of 10, 100, and 1,000–fold dilutions through cation exchange columns using AG50-X8 exchange resin from Eichrom Industries. The eluent from the cation columns were then sent through a seaFAST2 unit directly connected to an inductively coupled plasma mass spectrometer (ICP-MS) to analyze the REEs. Percent recoveries of the REEs ranged from 80–110% and fell within error for the external reference standard used and no signal suppression or isobaric interferences on the REEs were observed. These results demonstrate that a combined use of cation exchange columns and seaFAST2 instrumentation are effective in accurately quantifying the dissolved REEs in fluids that are >150,000 mg/L in TDS and have Ba:Eu ratios in excess of 380,000.

03 NATURAL GAS↗
DOE OSTI2024

Understanding caprock behavior during underground hydrogen storage in depleted gas fields

The poster presents the results of pycnometric analysis of Marcellus and Wolfcamp shales subject to cyclic hydrogen exposure. Results indicate that continued hydrogen exposure results in the increase in matrix permeability and porosity in certain shale types, such as Marcellus. This change is physical in nature, due to the likely creation of microfractures at grain boundaries.

08 HYDROGEN↗
DOE OSTI2026

Innovations Driven by Advanced Characterization to Strategize Critical Mineral Production and Beneficial Reuse from Fossil Energy Waste

Critical minerals (CM), such as rare earth elements (REE), cobalt, nickel, and lithium, have important uses in modern electronics and advanced manufacturing, yet are vulnerable to potential supply chain disruptions. Relatively abundant and readily available fossil energy (FE) wastes, such as coal combustion ash, acid mine drainage (AMD) and treatment solids (AMD solids), and Oil and Gas (O&G) drilling wastes (drill cuttings and produced waters) are under consideration as CM feedstocks. The National Energy Technology Laboratory (NETL) has studied CM resources for various FE wastes as part of the U.S. Department of Energy’s mission of bolstering the domestic CM supply, and makes the data available to the public on EDX at sites such as the NEWTS group. Advanced characterization utilizing synchrotron x-ray techniques coupled with laboratory extractions has been performed to identify CM hosting phases in these FE wastes to inform CM recoverability mechanisms. Novel methods to selectively recover CMs while co-producing other valuable byproducts have been developed. Successful examples discussed here include: (1) The identification of REE/Co/Ni/Sc binding and hosting phases in select FE waste (coal combustion ash and AMD solids), resulting in the development of a patented CM step-extraction process, (2) coupled production of functional sorbents from these extraction wastes and for CM recovery. A pilot-scale testing to evaluate the patent’s technical feasibility for extracting REE from coal ash on a barrel scale has been successfully performed. Additionally, (3) evaluation and measurements of brine geochemistry from U.S. O&G produced waters has informed a high Li recovery potential from Marcellus Shale produced water. NETL researchers have been developing tailored pre-treatment processes, an innovative and highly durable lithium sorbent, and geochemical model guided precipitation to accelerate Li production from the Marcellus Shale produced waters. These innovations driven by characterization are integral for maximizing and advancing the potential for CM recovery while offsetting the cost and environmental footprint for FE waste management.

critical mineral processing↗
DOE OSTI2017

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

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 + nearfracture 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. In conclusion, 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.

03 NATURAL GAS↗
DOE OSTI2021

Role of Mineralogy in Controlling Fracture Formation

The presence of fractures in caprocks can pose increased risks in subsurface energy systems and processes like CO 2 sequestration by introducing high-permeability leakage paths. Fracture apertures and permeability can be altered through mineral dissolution and precipitation reactions, but the reactive evolution of fractures is not well understood. In fractures, minerals that are otherwise inaccessible to reactive fluids can become exposed, resulting in mineral reactions unpredicted by bulk formation data. This work seeks to understand the relationship between mineralogy and fracture formation to enhance our understanding of reactive fracture evolution and CO 2 leakage potential. Here, the mineral compositions of mechanically induced fracture surfaces in samples of the Mancos and Marcellus shales have been quantified and compared to those of the near-fracture matrices using imaging and bulk X-ray diffraction (XRD) data. In the Mancos shale, the concentrations of clay minerals are enhanced along fracture surfaces with respect to the bulk, and the fracture is most likely to form at kaolinite–kaolinite interfaces. Further, evaluation of the mineralogical spatial variability through cross-correlation analysis of the surrounding matrix in images of samples cut perpendicular to the fracture shows that clay is 16.7 times more likely to be present than carbonate minerals near the fracture surface. The high correlation persists roughly 200 μm into the surrounding matrix for the Mancos sample and implies that the fracture formed within a defined clay-rich lithofacies.

37 INORGANIC, ORGANIC, PHYSICAL, AND ANALYTICAL CH↗
DOE OSTI2019

In situ transformation of hydraulic fracturing surfactants from well injection to produced water

Chemical changes to hydraulic fracturing fluids (HFFs) within fractured unconventional reservoirs may affect hydrocarbon recovery and, in turn, the environmental impact of unconventional oil and gas development. Ethoxylated alcohol surfactants, which include alkyl ethoxylates (AEOs) and polyethylene glycols (PEGs), are often present in HFF as solvents, non-emulsifiers, and corrosion inhibitors. We present detailed analysis of polyethoxylates in HFF at the time of injection into three hydraulically fractured Marcellus Shale wells and in the produced water returning to the surface. Despite the addition of AEOs to the injection fluid during almost all stages, they were rarely detected in the produced water. Conversely, while PEGs were nearly absent in the injection fluid, they were the dominant constituents in the produced water. Similar numbers of ethoxylate units support downhole transformation of AEOs to PEGs through central cleavage of the ethoxylate chain from the alkyl group. We also observed a decrease in the average ethoxylate (EO) number of the PEG–EOs in the produced water over time, consistent with biodegradation during production. Our results elucidate an overlooked surfactant transformation pathway that may affect the efficacy of HFF to maximize oil and gas recovery from unconventional shale reservoirs.

54 ENVIRONMENTAL SCIENCES↗
DOE OSTI2018

Dunham Pad A 4H Well

Medical CT scans, raw and processed core logging data (including XRF) and core images of the Dunham Pad A 4H well, obtained by Triana Energy, as supplemental information to the NETL Technical Report Series Crandall, D.; Brown, S.; Moore, J.; Martin, K.; Mackey, P.; Carr, T. CT Scanning and Geophysical Measurements of the Marcellus Formation from the Dunham Pad A 4H Well NETL-TRS-X-2018; NETL Technical Report Series; U.S. Department of Energy, National Energy Technology Laboratory: Morgantown, WV, 2018; p 48.

Core Logs↗
DOE OSTI2018

Tippens 6HS Well

Computed tomography scans and core log data obtained at the National Energy Technology Laboratory. Complimentary to 'CT Scanning and Geophysical Measurements of the Marcellus Formation from the Tippens 6HS Well" Technical Report Series, 2018

CT Scans↗
DOE OSTI2018

Final Report on Update and Enhancement of Shale Gas Outlooks

The study performed by an interdisciplinary team of the Bureau of Economic Geology (Jackson School of Geosciences, The University of Texas at Austin) presents an improved production outlook assessments for the major U.S. shale gas plays, including the Barnett, Fayetteville, Haynesville, and Marcellus. The team of geoscientists, engineers, statisticians, and economists has reviewed and analyzed developments in the understanding of geologic, production-technology, and economic factors and has developed a model to run various scenarios with respect to energy prices, costs, technological advances, changes in geologic attributes, and physical and regulatory constraints.

03 NATURAL GAS↗
DOE OSTI2018

Influence of Microbial Membranes on Biofilm Formation, Scaling Reactions, and Production Chemistry in Engineered Energy Systems (Final Report)

Humans are engineering the deep subsurface for the purposes of energy-capture, energy-storage, and environmental mitigation. Despite the potential for microbial communities to significantly alter the effectiveness of these technologies, we have historically lacked a clear understanding of how microbial cells interact in a fractured shale system. Existing knowledge has been heavily based on genomic information, lacking studies on in situ physiologies, kinetic rates, and attachment mechanisms governing biogeochemical reactions in the system. The overarching goal of this research was to advance understanding of engineered hydrocarbon extraction systems as they evolve from newly developed environments to mature use. Plasma membranes protect microbial cells, mediate many critical functions, and respond to intracellular cues and ecological perturbations through physicochemical modifications. The project objectives were to 1) characterize variables influencing growth and membrane features of shale taxa, 2) characterize the interactions between shale matrices and microorganisms and 3) elucidate engineered and environmental processes driving biogeochemical signatures at the field scale. Objectives were realized through laboratory experiments involving growth of pure cultures and enrichments in continuous culture and biofilms; access to samples from two DOE-NETL funded energy-capture sites: Marcellus Shale Energy and Environmental Laboratory (MSEEL and MSEEL II); and through collaborations with scientists and engineers at the Environmental Molecular Science Laboratory (EMSL) and National Energy Technology Laboratory (NETL). Key findings showed (a) Halanaerobium congolense WG10 makes its membrane more fluid and thicker through increasing its polyunsaturated fatty acid (PUFA) composition under non-optimal salinities (7% and 20%) compared to the optimum (13% NaCl); (b) anionic phospholipids within the plasma membrane are important for high salinity tolerance in H. congolense WG10 while zwitterionic species modulate biofilm physiologies in both isolate and mixed cultures, and (c) tyrosine accumulation with overexpression of Na+/H+ antiporters are essential for osmoprotection in H. congolense WG10 under high salinity while upregulation of aromatic amino acid synthesis and cell envelope maintenance underpin biofilm formation. It is clear from these results that microbial persistence in fractured shale reservoirs under environmental and engineered perturbations requires strategic plasma membrane lipid chemistry adjustments and metabolic restructuring, with implications for improved shale microbiology management and more efficient hydrocarbon extraction approaches targeting microorganisms.

03 NATURAL GAS↗
DOE OSTI2016

Numerical and Experimental Studies of Particle Settling in Real Fracture Geometries

In this study, proppant is a vital component of hydraulic stimulation operations, improving conductivity by maintaining fracture aperture. While correct placement is a necessary part of ensuring that proppant performs efficiently, the transport behavior of proppant in natural rock fractures is poorly understood. In particular, as companies pursue new propping strategies involving new types of proppant, more accurate models of proppant behavior are needed to help guide their deployment. A major difficulty with simulating reservoir-scale proppant behavior is that continuum models traditionally used to represent large-scale slurry behavior loose applicability in fracture geometries. Particle transport models are often based on representative volumes that are at the same scale or larger than fractures found in hydraulic fracturing operations, making them inappropriate for modeling these types of flows. In the absence of a first-principles approach, empirical closure relations are needed. However, even such empirical closure relationships are difficult to derive without an accurate understanding of proppant behavior on the particle level. Thus, there is a need for experiments and simulations capable of probing phenomena at the sub-fracture scale. In this paper, we present results from experimental and numerical studies investigating proppant behavior at the sub-fracture level, in particular, the role of particle dispersion during proppant settling. In the experimental study, three-dimensional printing techniques are used to accurately reproduce the topology of a fractured Marcellus shale sample inside a particle-flow cell.

15 GEOTHERMAL ENERGY↗
DOE OSTI2018

Multiphysics Lattice Discrete Particle Modeling (M-LDPM) for the Simulation of Shale Fracture Permeability

A three-dimensional multiphysics lattice discrete particle model (M-LDPM) framework is formulated to investigate the fracture permeability behavior of shale. The framework features a dual lattice system mimicking the mesostructure of the material and simulates coupled mechanical and flow behavior. The mechanical lattice model simulates the granular internal structure of shale, and describes heterogeneous deformation by means of discrete compatibility and equilibrium equations. The network of flow lattice elements constitutes a dual graph of the mechanical lattice system. A discrete formulation of mass balance for the flow elements is presented to model fluid flow along cracks and intact materials. The overall computational framework is implemented with a mixed explicit–implicit integration scheme and a staggered coupling method that makes use of the dual lattice topology enabling the seamless two-way coupling of the mechanical and flow behaviors. The proposed model is used for the computational analysis of shale fracture permeability behavior by simulating triaxial direct shear tests on Marcellus shale specimens under various confining pressures. The simulated mechanical response is calibrated against the experimental data, and the predicted permeability values are also compared with the experimental measurements. Moreover, the paper presents the scaling analysis of both the mechanical response and permeability measurements based on simulations performed on geometrically similar specimens with increasing size. The simulated stress strain curves reflect a significant size effect in the post-peak due to the presence of localized fractures. The scaling analysis of permeability measurements enables prediction of permeability for large specimens by extrapolating the numerical results of small ones.

58 GEOSCIENCES↗
DOE OSTI2024

Beyond the Surface: Non-Invasive Low-Field NMR Analysis of Microbially-Induced Calcium Carbonate Precipitation in Shale Fractures

Microbially-induced calcium carbonate precipitation (MICP) is a biological process in which microbially-produced urease enzymes convert urea and calcium into solid calcium carbonate (CaCO 3 ) deposits. MICP has been demonstrated to reduce permeability in shale fractures under elevated pressures, raising the possibility of applying this technology to enhance shale reservoir storage safety. For this and other applications to become a reality, non-invasive tools are needed to determine how effectively MICP seals shale fractures at subsurface temperatures. In this study, two different MICP strategies were tested on 2.54 cm diameter and 5.08 cm long shale cores with a single fracture at 60 °C. Flow-through, pulsed-flow MICP-treatment was repeatedly applied to Marcellus shale fractures with and without sand (“proppant”) until reaching approximately four orders of magnitude reduction in apparent permeability, while a single application of polymer-based “immersion” MICP-treatment was applied to an Eagle Ford shale fracture with proppant. Low-field nuclear magnetic resonance (LF-NMR) and X-Ray computed microtomography (micro-CT) techniques were used to assess the degree of biomineralization. With the flow-through approach, these tools revealed that while CaCO 3 precipitation occurred throughout the fracture, there was preferential precipitation around proppant. Without proppant, the same approach led to premature sealing at the inlet side of the core. In contrast, immersion MICP-treatment sealed off the fracture edges and showed less mineral precipitation overall. This study highlights the use of LF-NMR relaxometry in characterizing fracture sealing and can help guide NMR logging tools in subsurface remediation efforts.

MICP↗
DOE OSTI2018

Computational Modeling of Hydraulic Properties of a Sheared Single Rock Fracture

Flow through a single mechanically sheared Marcellus shale fracture was investigated computationally and experimentally. To provide a better understanding of the variation of hydraulic and geometrical characteristics of a fracture subjected to shearing, coupled shear flow tests on the fracture for four shearing displacement steps under constant normal stress were performed. At the end of each shearing step, computed tomography (CT) scans with resolution 26.8 μm were obtained and the corresponding fracture geometries were evaluated. The CT images were used to generate full aperture maps of the fracture configuration. In addition, average aperture maps were also created by averaging the full-resolution data over 10 × 10 pixels, smoothing out fine structural details. Computational modeling of water flow through the fractures at different shearing steps was performed using a modified local cubic law approach and the 3D full Navier–Stokes equations with the use of the ANSYS-Fluent software. Both the average aperture maps and full maps were used in these simulations. The experimental pressure drops of the fracture at shearing step 1, which has very small apertures, poorly matched the numerical results, quite likely because the fracture structure was inadequately captured by the scanning resolution. Shearing typically increased the aperture height of the fracture, whose features were then better captured by the CT scan. Good agreement between the experimental data and the numerical results of the full map for shearing step 2 was observed. The simulations were performed for both full and average aperture maps, and the effects of scan resolution and surface roughness on the accuracy of the results were studied. The modified local cubic law and full Navier–Stokes simulations of the averaged map fracture were found to be in good agreement. It was conjectured that this was because the nonlinear losses were insignificant for the smoothed out averaged map fracture. Similar comparisons with those of the full map showed agreement in trends, but there were some quantitative differences. The averaged fracture map simulations also predicted lower pressure drops compared to the full map, particularly for high flow rates. These differences were due to the fine-scale geometrical complexity (surface roughness) of fracture geometry that affects the fluid flow in the fracture. In conclusion, an improved cubic law model was also proposed, and its accuracy was verified by comparing its predictions with those of the Navier–Stokes simulations.

58 GEOSCIENCES↗
DOE OSTI2021

A new approach to study adsorption on shales and other microporous solids via the thermogravimetric analysis (TGA) technique

Measuring the adsorption of gases in microporous solids like the shales requires accurate knowledge of the solid’s skeletal volume. Helium (He) is commonly used to determine the sample’s skeletal volume based on the assumption that it does not adsorb in these porous media. The validity of such an assumption for microporous solids has been questioned in recent years, and in this study, we show that it is not applicable for the shale sample studied. We present a new method to measure the adsorption of shale-gas components in shales, which does not require the use of He to measure the solid’s skeletal volume. Since the proposed analysis method relies on the use of dynamic adsorption data, we also propose here a new zero-point correction method for the magnetic suspension balance, which is better suited for the analysis of such data. Here, we employ the new technique to the study of Argon adsorption in Marcellus Shales.

37 INORGANIC, ORGANIC, PHYSICAL, AND ANALYTICAL CH↗
DOE OSTI2017

Controls on rare earth element distributions in ancient organic-rich sedimentary sequences: Role of post-depositional diagenesis of phosphorus phases

Here, the processes that dictate the formation and preservation of rare earth element (REE) signatures in ancient marine black shales are incompletely understood, thus potentially limiting the utility of the REEs as geochemical tracers. Here, we report on whole-rock REE analyses of six black shale formations from different ages and depositional settings, which fall within three general groupings: Group 1 is characterized by low whole-rock REE content (ΣREE) (< 250 μg/g) and middle- and heavy-REE-enriched patterns (Gd N /La N < 2, Yb N /La N < 2.5); Group 2 is characterized by low ΣREE (< 250 μg/g) but greater middle-REE-enriched patterns (Gd N /La N > 2, Yb N /La N < 3); and Group 3 is characterized by high ΣREE (> 250 μg/g) and moderately middle-REE-enriched patterns (Gd N /La N ~ 1.5–2.5, Yb N /La N ~ 1). Representative samples from these groups were selected from the Marcellus and Hushpuckney shales and subjected to a multi-step leaching procedure, to isolate four extractable P-phases (reducible, authigenic carbonate-associated, detrital apatite, organic). In Group 1 samples with low carbonate content (< 4% CaCO 3 ), REEs were hosted mainly in the organic (50% of ΣREE) and siliciclastic fractions (37%); whereas in samples with greater carbonate content (> 25% CaCO 3 ), REEs were hosted mainly in carbonate-associated phases (53%). In Group 2, REEs were hosted mainly in the carbonate-associated (64%) and organic fractions (30%), and in Group 3, REEs were hosted mainly in the carbonate-associated (60%), detrital apatite (23%), and siliciclastic fractions (16%). Authigenic phases include minerals such as carbonate fluorapatite and authigenic calcite that, if present, tend to dominate the whole-rock REE inventory. In the absence of carbonate, whole-rock REE content depends on the relative REE contributions of the organic and siliciclastic fractions.

58 GEOSCIENCES↗