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In this work, we investigated leaching of lanthanide and yttrium (REY) from a Central Appalachian coal and its ashes obtained at 550–950 °C with the main purpose of understanding the impact of ashing temperature on REY leachability in water, ammonium sulfate, and hydrochloric acid. It is found that the coal contains a negligible amount of water-soluble REY, less than 1% ion-exchangeable REY, and about 28% of HCl-soluble REY. Ashing leads to dramatic changes in REY leachability in both ammonium sulfate and hydrochloric acid solutions, which is believed to be related to transformation and redistribution of organically-associated REY in coal during the ashing process. Ashing temperature significantly affects REY leaching from coal ashes; higher ashing temperature results in lower REY leachability in both solutions. Clay minerals may play a significant role in changing the leachability of REY after ashing. In addition, the results also suggest that the organic matter in the coal is relatively enriched in heavy REY.

Giant clams provide and support valuable functions to coral reefs, as well as represent a sustainable resource for traditional fisheries throughout the Indo‐Pacific region. The Ryukyu Archipelago (southern Japan) is known to be the northern latitudinal limits of giant clam distribution, but there is only limited information in the literature regarding species diversity, status, and distribution in this region. In this study, we report findings from a rapid survey in 2016, the first of its kind for the Ryukyu Islands, to determine species distribution and abundance of giant clams (tridacnines) around Okinawa‐jima Island. Results indicate the presence of four species with an overall density of 5.03 per 100 m², from most to least abundant: Tridacna crocea, Tridacna maxima, Tridacna squamosa, and Tridacna noae. The previously reported species Tridacna gigas and Hippopus hippopus were both absent from the surveys. The densities and distributions of tridacnines varied among species and sites, which are likely attributable to efforts in replenishing and protecting stocks of selected species. The most abundant species, T. crocea, is an important fishery species in Okinawa, and has been widely cultured and restocked to augment depleted populations. In comparison, restocking efforts for less popular species, such as T. squamosa, have been limited, and their current sizes and numbers suggest recruitment constraints. Given the importance of the giant clam fishery in this region and the current declines of various species (except T. crocea), further regulations should focus on the protection of larger and mature clams that function as broodstock necessary to maintain spawning and natural recruitment.

The taxonomy and diversity of chromodorid nudibranchs (Mollusca: Gastropoda: Nudibranchia) are relatively well-studied, although molecular analyses have only been applied to test few species-level groups. Within Chomodorididae, the genus Goniobranchus Pease, 1866 contains many different groups based on external colouration, including the red-reticulate group. Previously, most of the red-reticulate group has been considered as either a single variable species, identified as either Goniobranchus reticulatus Pease, 1866 or Goniobranchus tinctorius (Ruppell & Leuckart, 1828), or as a species complex. In this study, red-reticulate nudibranchs were collected from different locations spanning the Indo-Pacific. From these specimens, DNA data were derived, consisting of mitochondrial cytochrome c oxidase subunit I (COI) and 16S ribosomal DNA (16S rDNA) sequences. COI data were analysed using a distance-based species delimitation approach (ABGD), and the combined dataset (COI+16S rDNA) was analysed using maximum likelihood (ML) and Bayesian inference (BI) methods. The analyses identified five species-level clades, but none of the clades’ morphotypes matched exactly with the original descriptions of G. tinctorius or G. reticulatus. The non-reticulate, spotted species Goniobranchus splendidus (Angas, 1864) falls inside this complex. The existence of multiple species-level clades in the Goniobranchus red-reticulate group suggests this is a group of closely related species, comprising at least five undescribed taxa.

Rare earth elements (REE) play a critical role in the global economy. The concern about the REE supply challenge has stimulated global interest in recovering REE from alternative non-conventional REE sources such as coal fly ash. In this paper, sequential extraction, physical separations and hydrothermal alkaline treatment were explored for characterization and enrichment of REE from coal fly ash. Seven-step sequential extraction of coal fly ash has demonstrated that 86.1% of total REE were associated with the glassy phase of the fly ash, with the remaining REE mainly distributed in the organic and sulfides phase (8.3%), the exchangeable phase (3.7%), and the carbonates phase (1.5%). A process combining physical separations, namely, particle size separation and magnetic separation, and hydrothermal alkaline treatment was proposed for enrichment of REE from coal fly ash. The optimal hydrothermal alkaline treatment condition was determined. It was demonstrated that NaOH concentration, solid-to-liquid ratio, temperature, and reaction duration had significant influence on ash dissolution in NaOH solution. Grinding could also enhance ash dissolution during subsequent hydrothermal alkaline treatment. REE were enriched from coal fly ash from 325 mg/kg to 877 mg/kg via the proposed process under optimal hydrothermal alkaline treatment conditions.

Coal is a potential source of some valuable elements. In this work, concentrations of 25 critical elements in U.S. coals were evaluated using the COALQUAL Database Version 3.0 aiming to identify best coal sources for potential recovery of critical element. A method was proposed to calculate the mean concentrations of critical elements in U.S. coals, including Li (11.5 ppm), Be (1.9 ppm), Ti (721 ppm), V (21.6 ppm), Mn (50.8 ppm), Co (4.5 ppm), Ga (5.1 ppm), Ge (7.2p pm), Se (2.4 ppm), Zr (30.4 ppm), Nb (3.3 ppm), Sn (1.8 ppm), Sb (1.0 ppm), Ba (266 ppm), Hf (0.77 ppm), and Ta (0.19 ppm).Based on the calculated mean concentrations, a rough estimate indicates that U.S. coals contain a large amount of critical elements that are enough to meet U.S. demands for many years to come, if these elements can be commercially extracted. By comparing with the suggested cut-off grades, we found that 5.8% of the coal samples have Ga concentrations higher than the suggested cut-off grade. The percentages of promising coal samples (higher than cut-off grades) of other elements are below 3%. Results further indicate that despite some variations among elements, bituminous coals from the Appalachian region are likely to have high concentrations of Li, Ga, Be, Se, and Sb which make them a potential source of these critical elements. Bituminous coals from the Interior Coal Province, both Eastern and Western, were found to have relatively high probabilities of having high Ge concentrations. Very limited coal samples were found from mixed regions to have V and Zr concentrations higher than the corresponding suggested cut-off grades.

Coal is a potential source of valuable elements such as rare earth elements and yttrium (REY). In this work, REY concentrations in U.S. domestic coals were evaluated using data from the USGS COALQUAL Database Version 3.0. The database contains a total of 7657 non-weathered, full-bed coal samples. The number of samples containing REY data points varies among elements. Assessment of data quality indicates that some of the REY data are semi-quantitative and should be used with caution. Different analytical instruments and methods with varying accuracies and precisions are thought to be the main sources of errors. Inclusion of qualified data also accounts for the sawtooth pattern of the UCC-normalized REY distribution. A new set of Q factor values was thus proposed to adjust qualified data. Consequently, mean concentrations of REY in U.S. coals were obtained with a total REY concentration of 65.5 ppm on a moisture-free whole coal basis. Further evaluation of REY in 5378 selected coal samples indicates that about 9–13% of the samples fall into the combined category of promising and highly promising coals for REY, according to the classification of Dai et al. (2017). Taking sampling bias into consideration, we further found that bituminous coal, particularly from the central Appalachian region, has the highest probability of being a source for beneficial recovery of REY. More specifically, bituminous coal from eastern Kentucky is likely to be the best option. Finally, we conclude that U.S. domestic coal is a promising, alternative source for beneficial recovery of REY to meet the U.S. REY demand for economic growth.

A numerical model was developed using CrunchFlow to simulate reactive transport and porosity and permeability changes of sandstone and carbonate rock samples taken from the Lower Tuscaloosa Formation and the Selma Chalk Formation, Jackson County, MS, USA. The model predicted a permeability decrease from 2190 mD to 2038 mD for the Lower Tuscaloosa Sandstone sample in a static batch reactor after 180 days of exposure to CO2-saturated brine, which is consistent with measured permeability results. The model predicted a negligible permeability change from 2.00 mD to 2.08 mD for the Selma Chalk carbonate sample after 180 days of exposure to CO2-saturated brine. Based on model prediction, key mineral dissolution and precipitation reactions in the Lower Tuscaloosa Sandstone sample include dissolution of quartz, chlorite, and feldspar, as well as precipitation of amorphous silica and kaolinite. For the Selma Chalk carbonate sample, key predicted reactions include dissolution of calcite, quartz and chlorite, and precipitation of kaolinite and amorphous silica. Initial porosity, initial feldspar content and the exponent n value (related to pore structure and tortuosity) used in permeability calculations were three important factors affecting permeability evolution of sandstone samples under CO2 sequestration conditions. The small permeability change predicted for both the Lower Tuscaloosa Sandstone and the Selma Chalk caprock after exposure to CO2-saturated brine suggests that poro-permeability changes during CO2 injection into the Lower Tuscaloosa Formation are not likely to significantly affect reservoir and seal quality. © 2017 Society of Chemical Industry and John Wiley & Sons, Ltd.

Rare earth elements (REE) are of strategic importance because they find numerous applications in various sectors of the global economy. The concern about the REE supply challenge has led to increasing interest and research in the recovery of REE from end-of-life products and secondary sources such as coal and coal by-products. The work reported here was focused on examining the technical feasibility of physical separation techniques for the enrichment of REE from coal and coal by-products. Particle size, magnetic and density separations were performed on coal, coal ash, clay and shale samples. It was found that the samples responded to particle size separation differently. For all ash samples, higher REE concentrations were found in the finer fractions. For the clay and shale samples, however, the REE concentrations decrease as the particle size reduces possibly because RE minerals were not effectively released by grinding. Magnetic separation showed that REE are enriched in non-magnetic fractions for all ash samples. All samples responded similarly to density separation. Among the three methods, density separation showed the highest enrichment of REE. A combination of these methods is recommended. Finally, correlations between elements were demonstrated, which leads to the classification of three groups containing mainly Al/Si, Fe and Ca, respectively. REE are strongly associated with the Al/Si group.

Coal contains trace amounts of rare earth elements (REE). They are either in the form of discrete minerals or chemically bound to organic matter. Methods of distinguishing the organic and inorganic associations of REE in coal have been mostly based on the correlations between the REE concentrations and the ash yields. Quantitative characterization of organically associated REE is still very challenging. In this work, we confirm the existence of organically-associated REE in coal and present an approach to quantifying its mass fraction. The coal sample used in this study was a cleaned low-ash coal collected from a coal preparation plant in Kentucky, USA and originally from the central Appalachian basin coal region. The results from particle size and density separations of the coal suggested that the REE are associated with both organic and inorganic matters. It was found that as the ash yield increases, both the total REE concentration on the whole coal basis and the LREE/HREE ratio increase, while the total REE concentration on the ash basis reduces dramatically. The results also suggested that the organic matter is relatively enriched in HREE. Based on these observation and findings, a method was developed to quantitatively determine the distribution of REE in the organic and inorganic phases of the coal. It was found that the total REE concentrations in the organic and inorganic phases are 31 ppm and 1141 ppm, respectively. The results also showed that in the low-ash Appalachian coal sample used in this work, 25% of the REE is associated with the organic matter. The method developed in this work for quantitative evaluation of the organic/inorganic mode of occurrence may be applied to other coal samples and for many other trace elements in coals.

Saline aquifers are the largest potential continental geologic CO2 sequestration resource. Understanding of potential geochemically induced changes to the porosity and permeability of host CO2 storage and sealing formation rock will improve our ability to predict CO2 plume dynamics, storage capacity, and long-term reservoir behavior. Experiments exploring geochemical interactions of CO2/brine/rock on saline formations under CO2 sequestration conditions were conducted in a static system. Chemical interactions in core samples from the Lower Tuscaloosa formation from Jackson County, Mississippi, with exposure to CO2-saturated brine under sequestration conditions were studied through six months of batch exposure. The experimental conditions to which the core samples of Lower Tuscaloosa sandstone and Selma chalk were exposed to a temperature of 85°C, CO2 pressure of 23.8 MPa (3500 psig), while immersed in a model brine representative of Tuscaloosa Basin. Computed tomography (CT), X-Ray diffraction (XRD), Scanning Electron Microscopy (SEM), brine chemistry, and petrography analyses were performed before and after the exposure. Permeability measurements from the sandstone core sample before and after exposure showed a permeability reduction. No significant change of the permeability measurements was noticed for the core sample obtained from Selma chalk after it was exposed to CO2/brine for six months. These results have implications for performance of the storage interval, and the integrity of the seal in a CO2 storage setting. © 2016 Society of Chemical Industry and John Wiley & Sons, Ltd

Various studies on differentiation of the automotive paints have been published in support of the evidential value of automotive paint comparisons [1] , [2] , [3] , [4] , [5] , and were based on the automotive populations in the regions outside of Singapore. However, the frequency information of the automotive paint characteristics in the previous studies may not be directly relevant to the situation in Singapore. To obtain the local frequency information of the automotive paint characteristics, a population study based on the automotive distribution in Singapore was necessary to apprehend the variations in the distribution of vehicle makes and colours, the visual and microscopical features, and the chemical compositions of the paint samples. This was facilitated with the data obtained from the local transport authority, the surveys conducted on random vehicle samples on the road, and the analysis of the existing collection of automotive paint samples taken from the laboratory’s vehicle paint database that closely resembles the vehicle population of Singapore. A discrimination study involving comparative analysis of 256 automotive paint samples from six colour groups was performed to evaluate the discriminating power of the laboratory's standard paint examination protocol: visual and microscopical examinations, Fourier Transform Infrared (FT-IR) Spectroscopy and Scanning Electron Microscopy with Energy Dispersive X-ray (SEM/EDX) Spectroscopy. Visual and microscopical comparisons of the physical characteristics in these paint samples yielded 54 indistinguishable pairs. When further subjected to FT-IR analysis, 51 pairs were distinguished in terms of their chemical compositions. The elemental compositions of the remaining three indistinguishable pairs were compared using SEM/EDX, and one pair remained indistinguishable. A combination of these analytical techniques yielded a discriminating power (DP) of 0.99981. The DP in this study is in support of the DP values reported in the published studies [1] , [2] , [3] , [4] , [5] .

A numerical model was developed to simulate reactive transport with porosity and permeability change of Mount Simon sandstone (samples from Knox County, IN, USA) after 180 days of exposure to CO2-saturated brine under CO2 sequestration conditions. The model predicted formation of a high-porosity zone adjacent to the surface of the sample in contact with bulk brine, and a lower porosity zone just beyond that high-porosity zone along the path from the sample/bulk brine interface to sample core. The formation of the high porosity zone was attributed to the dissolution of quartz and muscovite/illite, while the formation of the lower porosity zone adjacent to the high porosity zone was attributed to precipitation of kaolinite and feldspar. The model predicted a 40% permeability increase for the Knox sandstone sample after 180 days of exposure to CO2-saturated brine, which was consistent with laboratory-measured permeability results. Model-predicted solution chemistry results were also found to be consistent with laboratory-measured solution chemistry data. Initial porosity, initial feldspar content, and the exponent n value (determined by pore structure and tortuosity) used in permeability calculations were three important factors affecting permeability evolution of sandstone samples under CO2 sequestration conditions.

CCS research has been focused on CO2 storage in geologic formations, with many potential risks. An alternative to conventional geologic storage is carbon mineralization, where CO2 is reacted with metal cations to form carbonate minerals. Mineralization methods can be broadly divided into two categories: in situ and ex situ. In situ mineralization, or mineral trapping, is a component of underground geologic sequestration, in which a portion of the injected CO2 reacts with alkaline rock present in the target formation to form solid carbonate species. In ex situ mineralization, the carbonation reaction occurs above ground, within a separate reactor or industrial process. This literature review is meant to provide an update on the current status of research on CO2 mineralization. 2

A numerical model was developed with the use of reactive transport code CrunchFlow to estimate porosity, permeability and mineral composition changes of Mount Simon sandstone under typical geological carbon sequestration conditions (P = 23.8 MPa and T = 85 °C). The model predicted a permeability decrease from 1.60 mD to 1.02 mD for the Mount Simon sandstone sample in a static batch reactor after 180 days of exposure to CO2-saturated brine, which is consistent with measured permeability results. Model-predicted solution chemistry results were also consistent with laboratory-measured solution chemistry data. SiO2 (am) was the primary mineral that causes permeability decrease, followed by kaolinite. Both SiO2 (am) formation and kaolinite formation were attributed to the dissolution of quartz and feldspar. This study shows that the formation of SiO2 (am) and kaolinite in the pore space of host rock is possible under typical CO2 sequestration conditions. SiO2 (am) and kaolinite precipitation at the CO2 plume extent could reduce the permeability of host rock and improve lateral containment of free-phase CO2, contributing to overall security of CO2 storage.

CO2 solubility data in the natural formation brine, synthetic formation brine, and synthetic NaCl+CaCl2 brine were collected at the pressures from 100 to 200 bar, temperatures from 323 to 423 K. Experimental results demonstrate that the CO2 solubility in the synthetic formation brines can be reliably represented by that in the synthetic NaCl+CaCl2 brines. We extended our previously developed model (PSUCO2) to calculate CO2 solubility in aqueous mixed-salt solution by using the additivity rule of the Setschenow coefficients of the individual ions (Na(+), Ca(2+), Mg(2+), K(+), Cl(-), and SO4(2-)). Comparisons with previously published models against the experimental data reveal a clear improvement of the proposed PSUCO2 model. Additionally, the path of the maximum gradient of the CO2 solubility contours divides the P-T diagram into two distinct regions: in Region I, the CO2 solubility in the aqueous phase decreases monotonically in response to increased temperature; in region II, the behavior of the CO2 solubility is the opposite of that in Region I as the temperature increases.

Separating oil from saltwater is a process relevant to some industries and may be aided by bubble and froth generation. Simulating saltwater-air interfaces adsorbed with surfactants and oil molecules can assist in understanding froth stability to improve separation. Combining with surface tension experimental measurements, in this work we employ molecular dynamics with a united-atom force field to linear alkane oil and three surfactant frothers, methyl isobutyl carbinol (MIBC), terpineol, and ethyl glycol butyl ether (EGBE), to investigate their synergistic behaviors for oil separation. The interfacial phenomena were measured for a range of frother surface coverages on saltwater. Density profiles of the hydrophilic and hydrophobic portions of the frothers show an expected orientation of alcohol groups adsorbing to the polar water. A decrease in surface tension with increasing surface coverage of MIBC and terpineol was observed and reflected in experiments where the frother concentration increased. Relations between surface coverage and bulk concentration were observed by comparing the surface tension decreases. Additionally, a range of oil surface coverages was explored when the interface has a thin layer of adsorbed frother molecules. The obtained results indicate that an increase in surface coverage of oil molecules led to an increase in surface tension for all frother types and the pair correlation functions depicted MIBC and terpineol as having higher distributions with water at closer distances than with oil.

For water treatment purposes, the separation processes involving surfactants and crude oil at seawater-air interfaces are of importance for the chemical and energy industries. Little progress has been made in understanding the nanoscale phenomena of surfactants on oily saltwater-air interfaces. This work focuses on using molecular dynamics with a united-atom force field to simulate the interface of linear alkane oil, saltwater, and air with three surfactant frothers: methyl isobutyl carbinol (MIBC), terpineol, and ethyl glycol butyl ether. For each frother, although the calculated diffusivities and viscosities are lower than the expected experimental values, our results show that diffusivity trends between each frother agree with experiments but the method cannot be applied for viscosity. Binary combinations of liquid (frother or saltwater)-air and liquid-liquid interfaces are equilibrated to study the density profiles and interfacial tensions. The calculated surface tensions of the frother-air interfaces are like that of oil-air, but lower than that of saltwater-air. Only the MIBC-air and terpineol-air interfaces agreed with our experimental measurements. For the frother-saltwater interfaces, the calculated results showed that terpineol has interfacial tensions higher than those of MIBC-saltwater. The simulated results indicate that the frother-oil systems underwent mixing such that the density profiles depicted large interfacial thicknesses.

The addition of CO2-soluble, brine-soluble surfactants to the high pressure CO2 can facilitate the in-situ generation of CO2-in-brine foams for conformance and/or mobility control. These non-ionic surfactants dissolve in CO2 to concentrations of roughly 0.02–0.10 wt% at typical CO2 enhanced oil recovery (EOR) conditions and, upon mixing with brine in a closed, agitated, windowed vessel, stabilize CO2-in-brine foams. Branched nonylphenol ethoxylates containing an average of 12 (Huntsman SURFONIC® N-120) or 15 (Huntsman SURFONIC® N-150) ethylene oxide (EO) repeat units, and a branched tridecyl alcohol ethoxylate with 9 EO repeat units (Huntsman SURFONIC® TDA-9) are selected for the mobility and computed tomography (CT) studies detailed in this paper. These foam-stabilizing surfactants are much more brine-soluble than CO2-soluble, in accordance with the Bancroft rule for generating CO2-in-brine foam. Transient mobility measurements are conducted using several mixed wettability SACROC carbonate cores of low permeability (13–16 mD), and a high permeability water-wet Bentheimer sandstone core (1550 mD). The CO2 is injected into a brine-saturated core at a constant rate, yielding superficial velocities of 60.96 cm/day or 304.8 cm/day. Surfactant was either not used, dissolved only in CO2, only in brine, or in both brine and CO2. The surfactant concentration is ~0.07 wt% in the CO2 (the maximum concentration capable of dissolving in CO2) or in the brine. The transient differential pressure drop during the injection of three pore volumes of CO2 into the core indicate that the average total pressure drop across the core during the experiment increases by an average of 25–120% when the surfactant is dissolved in the CO2, 79–300% when the surfactant is dissolved in the brine, and 220–330% if surfactant is present in both the brine and CO2. These results indicate that the greatest mobility reduction is achieved with the surfactant in both brine and CO2, and the foams that are generated with surfactant dissolved in the brine alone tend to provide greater mobility reduction than when the surfactant is dissolved only in CO2. CT scanning of in-situ foam generation is conducted by injecting high pressure CO2 into a 5 wt% KI brine-saturated water-wet Berea sandstone (4–8 mD). Tests are performed with no surfactant, surfactant dissolved in brine at 0.03 wt%, in CO2 at 0.07 wt%, or in both brine and CO2. CT images indicate that in the absence of surfactant, sweep efficiency is very low primarily because CO2 tends to flow through high permeability bedding planes. The use of CO2-soluble surfactants to form CO2-in-brine foam within a sandstone core is verified via CT imaging. At low and high superficial velocity values of 14.33–143.3 cm/day, in-situ foam generation and propagation, as indicated by piston-like flow of the CO2 through the core, is most evident when surfactant was dissolved in the brine. While there is some evidence of foam formation when Huntsman SURFONIC® N-120 or Huntsman SURFONIC® N-150 is present in the CO2, very distinct foam formation and propagation occurs when Huntsman SURFONIC® TDA-9 is dissolved in CO2.

Viscosity data are reported for n-hexadecane (C16), n-octadecane (C18), and n-eicosane (C20) at pressures between (3 and 243) MPa and temperatures between (304 and 534) K. These extreme conditions are representative of those encountered in ultra-deep petroleum formations beneath the deepwaters of the Gulf of Mexico. The measurements are taken with a novel windowed Inconel rolling-ball viscometer designed by our team that is calibrated with n-decane. A comparison of the reported viscosity values with the available literature data that cover limited pressure and temperature ranges, shows that the mean absolute percentage deviation, δ, ranges between 1.1% and 4.8%. The reported data extend the database of viscosity to the high-temperature, high-pressure region where most gaps occur in the literature data for n-hexadecane and n-octadecane. To the best of our knowledge, the results for n-eicosane are the first reported viscosity values at pressures above 2 MPa over the entire temperature range. The viscosity results are modeled with the free volume theory model in conjunction with density values obtained using the Peng–Robinson equation of state (EoS) and the PC-SAFT EoS. The δ values obtained with this model range from 2.0% to 3.5%. The data are also correlated by a non-linear surface fit as a simultaneous function of temperature and pressure that yields δ values of 0.40%, 0.43%, and 0.38% for C16, C18, and C20, respectively.

Deep saline aquifers are reported to have the largest estimated capacity for CO2 sequestration. Knowledge of possible geochemically-induced changes to the porosity and permeability of host CO2 storage sandstone and seal rock will enhance our capability to predict CO2 storage capacity and long-term reservoir behavior.An experimental study of the potential interaction of CO2/brine/rock on saline formations in a static system under CO2 sequestration conditions was conducted. Chemical interactions in the Mount Simon sandstone environment upon exposure to CO2 mixed with brine under sequestration conditions were studied. Samples were exposed to the estimated in-situ reaction conditions for six months. The experimental parameters used were two core samples of Mount Simon sandstone; Illinois Basin model brine; temperature of 85°C, pressure of 23.8 MPa (3,500 psig), and CO2. Micro-CT, CT, XRD, SEM, petrography, and brine, porosity, and permeability analyses were performed before and after the exposure. Preliminary permeability measurements obtained from the sandstone sample showed a significant change after it was exposed to CO2- saturated brine for six months. This observation suggests that mineral dissolution and mineral precipitation could occur in the host deposit altering its characteristics for CO2 storage over time.

SUMMARY Deep saline aquifers are reported to have the largest estimated capacity for CO2 sequestration. Most geochemical studies on CO2 storage in saline formations are focused on the interactions of pure CO2 and do not consider the potential impacts of contaminants such as SO2 found in typical post-composition flue gas streams. This paper reports on results of a combined CO2–co-contaminant–brine–rock experimental and a simple modeling study of the potential impact of flue gas contaminants on saline formations. Chemical reactions of the sandstone from Mount Simon formation exposed to CO2 mixed with other gas species under sequestration conditions were studied (i.e. solid material — representative Mount Simon sandstone; liquid — synthetic Illinois Basin brine; T and P — 50 °C, 110 bar; gas composition — 1% SO2, 4% O2, 95% CO2). The experimental study indicates that the co-injection of 1% SO2 would lead to substantially reduced brine pH due to the formation of sulfuric acid and the formation of bassanite (major) and anhydrites. Preliminary equilibrium computational modeling yielded similar results. Copyright © 2013 John Wiley & Sons, Ltd.

This research focuses on providing the petroleum reservoir engineering community with robust models of hydrocarbon density and viscosity at the extreme temperature and pressure conditions (up to 533 K and 276 MPa, respectively) characteristic of ultra-deep reservoirs, such as those associated with the deepwater wells in the Gulf of Mexico. Our strategy is to base the volume-translated (VT) Peng–Robinson (PR) and Soave–Redlich–Kwong (SRK) cubic equations of state (EoSs) and perturbed-chain, statistical associating fluid theory (PC-SAFT) on an extensive data base of high temperature (278–533 K), high pressure (6.9–276 MPa) density rather than fitting the models to low pressure saturated liquid density data. This high-temperature, high-pressure (HTHP) data base consists of literature data for hydrocarbons ranging from methane to C40. The three new models developed in this work, HTHP VT-PR EoS, HTHP VT-SRK EoS, and hybrid PC-SAFT, yield mean absolute percent deviation values (MAPD) for HTHP hydrocarbon density of ∼2.0%, ∼1.5%, and An effort was also made to provide accurate hydrocarbon viscosity models based on literature data. Viscosity values are estimated with the frictional theory (f-theory) and free volume (FV) theory of viscosity. The best results were obtained when the PC-SAFT equation was used to obtain both the attractive and repulsive pressure inputs to f-theory, and the density input to FV theory. Both viscosity models provide accurate results at pressures to 100 MPa but experimental and model results can deviate by more than 25% at pressures above 200 MPa.

DuPont’s perfluoropolyether oil Krytox $$^{\textregistered }$$ GPL 102 is a promising candidate for the high-temperature, high-pressure Deepwater viscosity standard (DVS). The preferred DVS is a thermally stable liquid that exhibits a viscosity of roughly 20 $$\hbox {mPa} \cdot \hbox {s}$$ at 533 K and 241 MPa; a viscosity value representative of light oils found in ultra-deep formations beneath the deep waters of the Gulf of Mexico. A windowed rolling-ball viscometer designed by our team is used to determine the Krytox $$^{\textregistered }$$ GPL 102 viscosity at pressures to 245 MPa and temperatures of 311 K, 372 K, and 533 K. At 533 K and 243 MPa, the Krytox $$^{\textregistered }$$ GPL 102 viscosity is $$(27.2 \pm 1.3)\,\hbox {mPa} \cdot \hbox {s}$$ . The rolling-ball viscometer viscosity results for Krytox $$^{\textregistered }$$ GPL 102 are correlated with an empirical 10-parameter surface fitting function that yields an MAPD of 3.9 %. A Couette rheometer is also used to measure the Krytox $$^{\textregistered }$$ GPL 102 viscosity, yielding a value of $$(26.2 \pm 1)\,\hbox {mPa} \cdot \hbox {s}$$ at 533 K and 241 MPa. The results of this exploratory study suggest that Krytox $$^{\textregistered }\, \hbox {GPL}$$ 102 is a promising candidate for the DVS, primarily because this fluoroether oil is thermally stable and exhibits a viscosity closer to the targeted value of 20 mPa $$\cdot $$ s at 533 K and 241 MPa than any other fluid reported to date. Nonetheless, further studies must be conducted by other researcher groups using various types of viscometers and rheometers on samples of Krytox GPL $$^{\textregistered }$$ 102 from the same lot to further establish the properties of Krytox GPL $$^{\textregistered }$$ 102.

In order to evaluate the extent of CO2–water–rock interactions in geological formations for C sequestration, three batch experiments were conducted on alkali feldspars–CO2–brine interactions at 150–200 °C and 300 bars. The elevated temperatures were necessary to accelerate the reactions to facilitate attainable laboratory measurements. Temporal evolution of fluid chemistry was monitored by major element analysis of in situ fluid samples. SEM, TEM and XRD analysis of reaction products showed extensive dissolution features (etch pits, channels, kinks and steps) on feldspars and precipitation of secondary minerals (boehmite, kaolinite, muscovite and paragonite) on feldspar surfaces. Therefore, these experiments have generated both solution chemistry and secondary mineral identity. The experimental results show that partial equilibrium was not attained between secondary minerals and aqueous solutions for the feldspar hydrolysis batch systems. Evidence came from both solution chemistry (supersaturation of the secondary minerals during the entire experimental duration) and metastable co-existence of secondary minerals. The slow precipitation of secondary minerals results in a negative feedback in the dissolution–precipitation loop, reducing the overall feldspar dissolution rates by orders of magnitude. Furthermore, the experimental data indicate the form of rate laws greatly influence the steady state rates under which feldspar dissolution took place. Negligence of both the mitigating effects of secondary mineral precipitation and the sigmoidal shape of rate–ΔGr relationship can overestimate the extent of feldspar dissolution during CO2 storage. Finally, the literature on feldspar dissolution in CO2-charged systems has been reviewed. The data available are insufficient and new experiments are urgently needed to establish a database on feldspar dissolution mechanism, rates and rate laws, as well as secondary mineral information at CO2 storage conditions.

Invert emulsions are used to drill for oil and gas when good wellbore stability and high temperature tolerance are required. These drilling fluids contain a solid phase and two immiscible liquid phases stabilised with a polymeric surfactant. In ultra deep drilling, due to high temperature, the surfactant degrades causing phase separation. However, fine particles can be used as stabilisers, and the result is a Pickering emulsion. Here, we demonstrate that the use of a combination of hydrophobic nanoparticles and organically modified nanoclay results in stable water-in-oil invert emulsions model drilling fluids. These gel-like model fluids have the desired plastic viscosity and yield stress suitable for drilling fluid applications that can be modified by adjusting the nanoparticle-content. Aging experiments at 225 ◦ C showed that they also have high-temperature stability for demanding drilling operations.

CO2 miscible and immiscible displacements and hydrocarbon miscible floods are commonly plagued by low volumetric sweep efficiency, early gas breakthrough, high gas utilization ratios, and significant gas re-compression and recycle. Rather than addressing these problems via the water-alternating-gas (WAG) injection sequence that reduces gas relative permeability or the generation of gas-in-brine foams for reduced mobility, we propose increasing the viscosity of high pressure CO2 or NGL via the dissolution of dilute concentrations of thickening agents. There are two strategies for increasing the viscosity of high pressure fluids; the dissolution of ultrahigh molecular weight polymers or associating polymers, or the dissolution of small molecules that self-assemble in solution to form viscosity-enhancing linear or helical supramolecular structures. Ideally a very small amount of the thickener will be required (roughly 0.1wt%) to elevate the CO2 or NGL viscosity to the same value as the oil being displaced (typically a 10-100 fold increase). Further, the thickened CO2 or thickened NGL should be a stable, transparent solution that does not require a heating/cooling cycle for viscosity enhancement to occur. Thickener solubility and viscosity were determined over a 25-100oC range. Each of the three major NGL constituents (ethane, propane and butane) was thickened with an ultrahigh molecular polymer (commercial drag reducing agent), resulting in a 2-30 fold increase in viscosity at polymer concentrations of 0.5wt% or less. The polymer dissolved at the lowest pressure in butane and was most effective as a thickener in butane. Three small molecule thickeners were identified for the NGL constituents; tri-alkyl-tin fluoride, hydroxyaluminum disoap, and a phosphate ester-crosslinker mixture. Remarkable viscosity enhancements were attained for propane and butane with the tri-alkyl-tin fluoride and aluminum soap; the crosslinked phosphate ester solutions exhibited modest viscosity increases. Only tri-alkyl-tin fluoride thickened ethane. CO2 thickeners were assessed with a falling ball viscometer and pressure drop associated with flow through Berea sandstone. 4-5 fold increases in viscosity were attained with 1wt% of a high molecular weight polyfluoroacrylate. 3-4 fold increases in viscosity were attained with 1wt% high molecular weight polydimethyl siloxane, but a very large amount of toluene co-solvent was required. Although a remarkably effective small molecule thickener was designed for CO2 (100-fold increase at 1.3wt%), it required a heating/cooling cycle and a very large amount of hexane co-solvent. We have identified the first polymeric and small molecule thickeners ever reported for ethane. Further, this study presents the largest viscosity increases ever reported for propane and butane with polymers and small molecule thickeners. We have presented the most effective polymeric thickeners for CO2 reported to date. This paper also summarizes numerous molecular architectures that are not viable for CO2 and highlights the most promising compounds that continue to be refined.

CCS research has been focused on CO2 storage in geologic formations, with many potential risks. An alternative to conventional geologic storage is carbon mineralization, where CO2 is reacted with metal cations to form carbonate minerals. Mineralization methods can be broadly divided into two categories: in situ and ex situ. In situ mineralization, or mineral trapping, is a component of underground geologic sequestration, in which a portion of the injected CO2 reacts with alkaline rock present in the target formation to form solid carbonate species. In ex situ mineralization, the carbonation reaction occurs above ground, within a separate reactor or industrial process. This literature review is meant to provide an update on the current status of research on CO2 mineralization. 2

Summary Several commercially available and a few experimental, nonionic surfactants were identified that are capable of dissolving in carbon dioxide (CO2) in dilute concentration at typical minimum- miscibility-pressure (MMP) conditions and, upon mixing with brine in a high-pressure windowed cell, stabilizing CO2-in-brine foams. These slightly CO2-soluble, water-soluble surfactants include branched alkylphenol ethoxylates, branched alkyl ethoxylates, a fatty-acid-based surfactant, and a predominantly linear ethoxylated alcohol. Many of the surfactants were between 0.02 to 0.06 wt% soluble in CO2 at 1,500 psia and 25°C, and most demonstrated some capacity to stabilize foam. The most- stable foams observed in a high-pressure windowed cell were attained with branched alkylphenol ethoxylates, several of which were studied in high-pressure small-angle-neutron-scattering (HP SANS) tests, transient mobility tests using Berea sandstone cores, and high-pressure computed-tomography (CT)-imaging tests using polystyrene cores. HP SANS analysis of foams residing in a small windowed cell demonstrated that the nonylphenol ethoxylate SURFONIC® N-150 [15 ethylene oxide (EO) groups] generated emulsions with a greater concentration of droplets and a broader distribution of droplet sizes than the shorter-chain analogs with 9–12 ethoxylates. The in-situ formation of weak foams was verified during transient mobility tests by measuring the pressure drop across a Berea sandstone core as a CO2/surfactant solution was injected into a Berea sandstone core initially saturated with brine; the pressure-drop values when surfactant was dissolved in the CO2 were at least twice those attained when pure CO2 was injected into the same brine-saturated core. The greatest mobility reduction was achieved when surfactant was added both to the brine initially in the core and to the injected CO2. CT imaging of CO2 invading a polystyrene core initially saturated with 5 wt% KI brine indicated that despite the oil-wet nature of this medium, a sharp foam front propagated through the core, and CO2 fingers that formed in the absence of a surfactant were completely suppressed by foams formed because of the addition of nonylphenol ethoxylate surfactant to the CO2 or the brine.

Nanohybrid catalysts that comprised montmorillonite (Mt) matrix and embedded zero-valent Fe nanoparticle are presented. In this process, clay particles are used as 2-dimensional template that induce the growth of intercalated nanomaterials. Fe polycations are first embedded within the interlayer space and then reduced to Fe nanoparticles through thermal annealing in reducing atmosphere. Structural studies using electron microscopy and high energy X-ray show that the intercalated status of the polycations dictates the crystal structure, shape and size of final Fe compound particles. The magnetic property and caltalytic efficacy of hybrid particles have been verified using magnetometer measurement and Fenton reaction. Hybrized α-Fe nanoparticles show high magnetization inherent to zero valent Fe, and high catalytic efficacy in decomposing Rhodamine B due to their zero valency and large surface areas. This simple synthesis process of stable iron nanoparticle without organic agents will be beneficial for large scale production of highly effective catalysts exploiting controlled phase and shape of embedded nanoparticles.

Long term containment of stored CO 2 in deep geological reservoirs will depend on the performance of the caprock to prevent the buoyant CO 2 from escaping to shallow drinking water aquifers or the ground surface. Here we report new laboratory experiments on CO 2 –brine–caprock interactions and a review of the relevant literature. The Eau Claire Formation is the caprock overlying the Mount Simon sandstone formation, one of the target geological CO 2 storage reservoirs in the Midwest USA region. Batch experiments of Eau Claire shale dissolution in brine were conducted at 200 °C and 300 bars to test the extent of fluid-rock reactions. Scanning electron microscopy (SEM) and X-ray diffraction (XRD) analysis indicate minor dissolution of K-feldspar and anhydrite, and precipitation of pore-filling and pore-bridging illite and/or smectite, and siderite in the vicinity of pyrite. We also reviewed relevant reactivity experiments, modeling work, and field observations in the literature in an attempt to help define the framework for future studies on the geochemical systems of the caprock overlain on geological CO 2 storage formations. Reactivity of the caprock is generally shown to be low and limited to the vicinity of the CO 2 –caprock interface, and is related to the original caprock mineralogical and petrophysical properties. Stable isotope studies indicate that CO 2 exists in both free phase and dissolved phase within the caprock. Carbonate and feldspar dissolution is reported in most studies, along with clay and secondary carbonate precipitation. Currently, research is mainly focused on the micro-fracture scale geochemistry of the shaly caprock. More attention is required on the potential pore scale reactions that may become significant given the long time scale associated with geological carbon storage.

A novel CO2 sequestration concept is reported that combines SO2 removal and CO2 capture and sequestration, using a bauxite-processing residue which is a waste product and with waste brine water from oil/gas production. The bauxite residue/brine mixture of 46/54 v/v exhibited a CO2 sequestration capacity of > 0.078 mol L–1 when exposed to pure CO2 at 20 °C and 2.73 MPa. At a higher temperature of 140 °C, a bauxite residue/brine mixture of 80/20 v/v indicated a CO2 sequestration capacity of > 0.094 mol L–1 when exposed to pure CO2 at 3.85 MPa. Under the same reaction conditions, an identical ratio of reaction mixture exposed to simulated flue gas at a similar initial pressure was capable of sequestering 0.16 mol of CO2 and > 99.9 % of the applied SO2. Calcite formation was verified as a product of bauxite/brine mixture carbonation. The caustic bauxite residues (pH 12.5–13.5) and acidic wastewater brine (pH 3–5) are also effectively neutralized after participating as reactive reagents in the conceptual process.

Development of in situ electromagnetic (EM) retorting technologies and design of specific EM well logging tools requires an understanding of various process parameters (applied frequency, mineral phases present, water content, organic content and temperature) on oil shale dielectric properties. In this literature review on oil shale dielectric properties, we found that at low temperatures ( 200 °C) and constant frequency, e′ generally increases with temperature regardless of grade while e″ fluctuates. At these temperatures, maximum values for both e′ and e″ differ based upon oil shale grade. Formation fluids, mineral-bound water, and oil shale varve geometry also affect measured dielectric properties. This review presents and synthesizes prior work on the influence of applied frequency, oil shale grade, water, and temperature on the dielectric properties of oil shales that can aid in the future development of frequency- and temperature-specific in situ retorting technologies and oil shale grade assay tools.

Heterostructures between montmorillonite and embedded alpha-Fe2O3 nanoparticles are explored to create new hybrid particles with high magnetic response and magnetic-field induced tunability. α-Fe2O3 nanoparticles are hybridized to montmorillonite clays by using an intercalation technique. Also, stable aqueous fluids consisting of the heterostructured particles are prepared and the rheology of the fluids under external magnetic field is examined. When α-Fe2O3 a nanoparticles are embedded in the interlayer space of montmorillonite clays, the magnetization per Fe atom increases at most 60 times. This unique combination of the magnetization and the coercivity is traced to the suppressed growth of embedded α-Fe2O3 nanoparticles by the aluminosilicate layers, leading to the size control, anisotropic magnetic interaction, and uniaxial stress of two-dimensionally distributed α-Fe2O3 nanoparticles. Furthermore, high magnetization of heterostructured particles leads to strong dependence of fluids' viscosity on the external magnetic field. The present study indicates that the new heterostructured particles have unique magnetic fielddependent properties that are not attainable in individual clay or iron oxide particles.

One of the most promising methods proposed to mitigate global [Formula: see text] and one that is useful in enhanced oil recovery is carbon sequestration, a process in which [Formula: see text] is pressurized and injected into geologic formations. A technical challenge surrounding the geologic sequestration of [Formula: see text] is tracking the movement of the fluids pumped underground. Monitoring, verification, and accounting activities related to [Formula: see text] storage are important for assuring that any sequestered [Formula: see text] does not escape to the surface and can be considerably aided by reflection seismic-based detection methods. Through the use of lab-scale velocity measurements under in-situ conditions, combined with multiple 3D reflection seismic surveys, we hope to effectively track the movements of [Formula: see text] after injection.

Ex-situ carbonation of mixtures of caustic byproduct materials and produced oil-field brine provides a niche opportunity to sequester anthropogenic CO2, while concomitantly reducing the basicity of the reactive slurry. A series of tests were conducted to investigate a novel reaction concept designed to achieve neutralization of mixtures of acidic oil field produced brine and caustic industrial byproducts while sequestering substantial quantities of anthropogenic carbon dioxide (CO2) in a mixed-flow reactor. Experiments were conducted to determine the CO2-bearing capacity of reactive mixtures of brine from the Oriskany Sandstone Formation with three caustic industrial byproducts: flue gas desulfurization (FGD) spray dryer ash, Class C fly ash subbituminous coal combustion byproduct, and bauxite residue slurry from the alumina production process. Reactions were conducted in a closed, well-mixed (1,500 rpm) reactor with gas composed of 29.46% vol./vol. CO2 balanced by nitrogen gas (N2) fed at a rate...

Suspensions of ZnO nanoparticles in water were prepared with the two-step powder dispersion process using several methods of ultrasonication. The dispersion of ZnO was found to proceed by a fragmentation process, with minimum achievable particle size in the range 50 to 300 nm. This is consistent with other oxide nanopowder systems, in which most primary particulates still remain in hardened aggregates that cannot be further reduced. A submersible accelerometer probe was developed and used to measure the relative ultrasonic energy field in the liquid for the various ultrasonication methods. Oscillation at the expected frequencies was identified in each case, with strong variability at different locations in the liquid volume.

A novel CO 2 separation concept is described wherein the enzyme carbonic anhydrase (CA) is used to increase the overall rate of CO 2 absorption after which hydrated CO 2 reacts with regenerable amine-bearing polyacrylamide buffering beads (PABB). Following saturation of the material's immobilized tertiary amines, CA-bearing carrier water is separated and recycled to the absorption stage while CO 2 -loaded material is thermally regenerated. Process application of this concept would involve operation of two or more columns in parallel with thermal regeneration with low-pressure steam taking place after the capacity of a column of amine-bearing polymeric material was exceeded. PABB CO 2 -bearing capacity was evaluated by thermogravimetric analysis (TGA) for beads of three acrylamido buffering monomer ingredient concentrations: 0 mol/kg bead, 0.857 mol/kg bead, and 2 mol/kg bead. TGA results demonstrate that CO 2 -bearing capacity increases with increasing PABB buffering concentration and that up to 78% of the theoretical CO 2 -bearing capacity was realized in prepared PABB samples (0.857 mol/kg recipe). The highest observed CO 2 -bearing capacity of PABB was 1.37 mol of CO 2 per kg dry bead. TGA was also used to assess the regenerability of CO 2 -loaded PABB. Preliminary results suggest that CO 2 is partially driven from PABB samples at temperatures as low as 55 °C, with complete regeneration occurring at 100 °C. Other physical characteristics of PABB are discussed. In addition, the effectiveness of bovine carbonic anhydrase for the catalysis of CO 2 dissolution is evaluated. Potential benefits and drawbacks of the proposed process are discussed.

Exposure to 7 MPa of helium at room temperature alters the texture of Upper Freeport coal in a lump form. The differences in texture and porosity between coal powder and lumps may affect the transport and interaction of fluids and coal. In this work, the information about the coal texture and micro- and meso-porosity was obtained via the BET, BJH, and Dubinin–Astakhov analyses. We further investigated the free-fluid-phase volume (free-volume) effects due to helium interaction with the powder and the lumps. During the manometric experiment, helium penetration into the dry coal matrix resulted in slow relaxation of pressure. After exposure of coal to helium, there have been no significant changes of the macroscopic dimensions observed and the relaxation process can be attributed to microscopic ‘free-volume’ effects. Evolution of the sorption–desorption rates indicates that exposure to helium may change the texture and apparent (helium) density of dry coal.

The permeability of coal samples from Pittsburgh Seam was determined using carbon dioxide as the flowing fluid. The confining pressure was varied to cover a wide range of depths. The permeability was determined as a function of exposure time of carbon dioxide while the confining stress was kept constant. The porosities of the coal samples were found to be very low and most of the samples had porosities less than 1%. The permeability of these coal samples was very low—less than 1 μD. Since the objective of this study was to investigate the influence of CO2 exposure on coal permeability, it was necessary to increase the initial permeability of the coal samples by introducing a fracture. A longitudinal fracture was induced mechanically, and CT scans were taken to ensure that the fracture was present throughout the sample and that the sample was not damaged otherwise during the process. In this study, the permeability of coal was determined by using pressure transient methods. Two types of pressure pulses were used: A-spike and Sine-6 pressure transients. It was first established that the permeability of fractured coal samples did not change with exposure time when an inert gas (Argon) was used as the fluid medium in the experiments. However, the permeability of coal samples decreased significantly when carbon dioxide was used as the fluid medium. This reduction can be attributed to the coal swelling phenomenon. The results show that the permeability reduction in fractured coal samples can be over 90% of the original value, and the exposure time for such reductions can range from 1.5 days up to a week, typically about 2 days under laboratory conditions. The permeability decreased significantly with the increase in confining pressure. The higher confining pressure appears to close internal fractures causing a reduction in permeability.

Aqueous zinc oxide (ZnO) suspensions were prepared using a two-step preparation method in which an aggregated nanocrystalline ZnO powder was dispersed in water using a polyelectrolyte. The fluid showed anomalously high thermal conductivity when compared with the Maxwell and Hamilton-Crosser predictions. However, analysis of the particle size distribution showed that the fluid contained aggregated 20 nm crystallites of ZnO with a high volume fraction of particles larger than 100 nm. Sedimentation experiments revealed that particles settled out of the stationary fluid over times ranging from 0.1 hours to well over 10,000 hours. The size of the particles remaining in suspension agreed well with predictions made using Stoke's law, suggesting flocculation was not occurring in the fluids. Finally, a new concept of nanofluid stability is introduced based on the height of the fluid, sedimentation, Brownian motion and the kinetic energy of the particles.

Laser ablation of magnesium in deionized water (DW), solutions of DW and sodium dodecyl sulfate (SDS) with different concentrations, acetone and 2-propanol has been conducted. The results showed that ablation in acetone and 2-propanol yielded MgO and Mg nanocrystallites as isolated particles and agglomerated chains probably intermixed with organic residues resulting from the alteration/decomposition of the solvents under the high-energy conditions. Brucite-like Mg(OH)2 particles were mainly produced by laser ablation of Mg in either DW or DW-SDS solutions. Ablation in DW yielded particles of fiber-like shapes having a diameter of about 5-10nm and length-as long as 150 nm. Materials produced in DW-SDS solutions were composed of various size and shape particles. Some had rough surfaces with irregular shapes. Small particles were about 20-30 nm and larger particles were about 120 nm. Particles with rodlike, triangular, and plate-like shapes were also observed.