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Search indexed NASA NTRS and DOE OSTI research on propulsion, heat transfer, battery materials and energy systems. Follow report and document links to the original sources.

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At least 19 records
All sourcesNASA NTRSDOE OSTI
DOE OSTI2015

CO 2 mineralization in volcanogenic sandstones: geochemical characterization of the Etchegoin formation, San Joaquin Basin

Abstract Volcanogenic sandstones are typically rich in volcanic rock fragments that can provide reactive minerals for CO 2 mineralization in a scenario of CO 2 sequestration. To quantitatively evaluate the extent and time scale of CO 2 mineralization in potential reservoir formations, we characterized example high‐porosity volcanic sand from the San Joaquin Valley of southern Central California. Samples were collected from the volcanic‐rich members of the Etchegoin Formation in the San Joaquin Basin near Coalinga, California. Thin sections made from these samples were examined under petrographic microscope to identify mineral compositions, and then scanning electron microscopy (SEM) and energy dispersive x‐ray spectroscopy (EDX) were used to gather quantitative information on mineral abundances, distribution, and reactive surface areas. Porosity and permeability were also measured using core plugs made from outcrop samples. Results show that the Etchegoin volcanic sandstone has a high percentage (10–15%) of reactive minerals (pyroxenes, Fe‐Ti spinel and clays), and high reactive surface areas at about 1 m 2 /kg. Reactive transport modeling is conducted and shows that these reactive minerals could mineralize 92% of injected and capillary‐trapped CO 2 within 1000 years of injection. Possible effects of heterogeneity on CO 2 injection and mineralization are also studied using the reactive transport code TOUGHREACT. Vertical heterogeneity of mineralogy and hydrology increases both CO 2 injectivity and mineralization. Available volcanogenic sandstones worldwide like the Etchegoin sandstone are summarized from the literature, with formations from the western USA that have CO 2 sequestration potential emphasized.© 2015 Society of Chemical Industry and John Wiley & Sons, Ltd

Zhang, Shuo↗
DOE OSTI2016

Measurements of CO 2 ‐brine relative permeability in Berea sandstone using pressure taps and a long core

Abstract We measured CO 2 ‐brine relative permeability by performing five steady‐state primary drainage experiments in a 116 mD Berea sandstone core at 20°C and 10.34 MPa. We used a long (60.8 cm) core and four pressure taps to study and minimize end effects that can plague CO 2 ‐brine relative permeability measurements, and we obtained in situ saturation profiles using a medical X‐ray Computed Tomography (CT) scanner. We found that entrance and exit effects propagated ∼5 cm into the core, but the center sections of the core had uniform saturation. From the saturations and pressure drops, we obtained both CO 2 and brine relative permeability in the center sections. We also obtained CO 2 relative permeability at the entrance section where the brine saturation was lower and not uniform. The 15‐cm long exit section of the core had non‐uniform saturation and a measured pressure drop that was on the order of the capillary pressure and hence was unreliable for calculating relative permeability. We found that the CO 2 and brine relative permeabilities determined in five experiments were consistent with each other and followed two simple Corey‐type models that are similar to those seen in oil‐brine relative permeability measurements. We discuss why end effects are much greater in the CO 2 ‐brine system than in oil‐brine systems, and how this is a possible explanation of the low CO 2 relative permeabilities recently reported for the CO 2 ‐brine systems. © 2016 Society of Chemical Industry and John Wiley & Sons, Ltd.

Chen, Xiongyu↗
DOE OSTI2020

Vertical effective stress and temperature as controls of quartz cementation in sandstones: Evidence from North Sea Fulmar and Gulf of Mexico Wilcox sandstones

Here we present quantitative petrographic data, high spatial resolution oxygen isotope analyses of quartz cement, basin modelling and a kinetic model for quartz precipitation for two Paleocene-Eocene Wilcox Group sandstones from Texas and two Jurassic Fulmar Formation sandstones from the Central North Sea. At each location, one sandstone has been buried to ca. 145 °C and one to ca. 185 °C. A key difference between the Wilcox and Fulmar burial histories is that the Wilcox sandstones are currently at higher vertical effective stresses and, from basin modelling studies, have been subjected to generally higher vertical effective stresses through their burial history. The amounts of quartz cement in the Wilcox sandstones are between 12 and 18%, and between 2 and 6% in the Fulmar sandstones. High-spatial-resolution oxygen isotope data obtained from the quartz cements suggest temperature ranges for quartz precipitation from 60 to 80 °C to values approaching maximum burial temperature. Factors such as grain coatings or the timing of petroleum emplacement cannot explain the differences in the amounts of quartz cement. Petrographic data show that most of the silica for quartz cement can be derived from intergranular pressure dissolution. Although the sample set is small, we interpret the results to suggest that the differences in quartz cementation in Fulmar and Wilcox sandstones can be explained better by differences in their vertical effective stress history than their temperature history; in this case, the supply of silica rather than the precipitation of quartz becomes an important control on the rate and extent of cementation.

58 GEOSCIENCES↗
DOE OSTI2016

Characterization of the Oriskany and Berea Sandstones: Evaluating Biogeochemical Reactions of Potential Sandstone–Hydraulic Fracturing Fluid Interaction

The Marcellus shale, located in the mid-Atlantic Appalachian Basin, has been identified as a source for natural gas and targeted for hydraulic fracturing recovery methods. Hydraulic fracturing is a technique used by the oil and gas industry to access petroleum reserves in geologic formations that cannot be accessed with conventional drilling techniques (Capo et al., 2014). This unconventional technique fractures rock formations that have low permeability by pumping pressurized hydraulic fracturing fluids into the subsurface. Although the major components of hydraulic fracturing fluid are water and sand, chemicals, such as recalcitrant biocides and polyacrylamide, are also used (Frac Focus, 2015). There is domestic concern that the chemicals could reach groundwater or surface water during transport, storage, or the fracturing process (Chapman et al., 2012). In the event of a surface spill, understanding the natural attenuation of the chemicals in hydraulic fracturing fluid, as well as the physical and chemical properties of the aquifers surrounding the spill site, will help mitigate potential dangers to drinking water. However, reports on the degradation pathways of these chemicals are limited in existing literature. The Appalachian Basin Marcellus shale and its surrounding sandstones host diverse mineralogical suites. During the hydraulic fracturing process, the hydraulic fracturing fluids come into contact with variable mineral compositions. The reactions between the fracturing fluid chemicals and the minerals are very diverse. This report: 1) describes common minerals (e.g. quartz, clay, pyrite, and carbonates) present in the Marcellus shale, as well as the Oriskany and Berea sandstones, which are located stratigraphically below and above the Marcellus shale; 2) summarizes the existing literature of the degradation pathways for common hydraulic fracturing fluid chemicals [polyacrylamide, ethylene glycol, poly(diallyldimethylammonium chloride), glutaraldehyde, guar gum, and isopropanol]; 3) reviews the known research about the interactions between several hydraulic fracturing chemicals [e.g. polyacrylamide, ethylene glycol, poly(diallyldimethylammonium chloride), and glutaraldehyde] with the minerals (quartz, clay, pyrite, and carbonates) common to the lithologies of the Marcellus shale and its surrounding sandstones; and 4) characterizes the Berea sandstone and analyzes the physical and chemical effects of flowing guar gum through a Berea sandstone core.

58 GEOSCIENCES↗
DOE OSTI2021

Characterization of Nanoscale Pores in Tight Gas Sandstones Using Complex Techniques: A Case Study of a Linxing Tight Gas Sandstone Reservoir

Pore structures with rich nanopores and permeability in tight gas reservoirs are poorly understood up to date. Advanced techniques are needed to be employed to accurately characterize pore structures, especially tiny pores which include micron and nanopores. In this study, various experimental techniques such as scanning electron microscopy (SEM), nuclear magnetic resonance (NMR) T 2 , nitrogen adsorption method, and NMR cryoporometry (NMRC) are combined to interrogate the complex pore systems of the tight gas reservoir in the Linxing formation, Ordos Basin, China. Results show that tight gas sandstones are primarily comprised of residual interparticle and clay-dominated pores. Clay and quartz are two dominate minerals while pyrite occupies a nontrivial amount as well. The permeability of tight gas sandstones is very low, exhibiting an extremely poor positive correlation with porosity. While pore types and relative pore contents are more influential factors on the permeability, accurate characterization of pore size distribution is critical for the permeability of tight gas sandstones. Therefore, complementary characterization methods are carried out, indicating that neither small pores with radii < 100 nm (around peak 1 in NMR T 2 distribution) nor large pores with radii > 5 μ m (around peak 3 in NMR T 2 distribution) control the permeability by analyzing the connectivity of the pores in various size ranges, but rather pores averaging approximately 350 ± X nm (around peak 2 in NMR T 2 distribution) have sufficient connectivity to host and transmit hydrocarbons. The pore size of tight gas sandstones is dominated by the clay-rich mineral assemblage. The study shows that the NMRC technique can be a very promising method, especially when referred to as a promising “roadmap” on how to interrogate tight formations such as the tight gas sands or even shale especially for the nanopore characterization.

15 GEOTHERMAL ENERGY↗