Sea urchins are dominant members of rocky temperate reefs around the world. They often occur in cavities within the rock, and fit so tightly, it is natural to assume they sculpted these “pits.” However, there are no experimental data demonstrating they bore pits. If they do, what are the rates and consequences of bioerosion to nearshore systems? We sampled purple sea urchins, Strongylocentrotus purpuratus, from sites with four rock types, three sedimentary (two sandstones and one mudstone) and one metamorphic (granite). A year-long experiment showed urchins excavated depressions on sedimentary rocks in just months. The rate of pit formation varied with rock type and ranged from <5 yr for medium-grain sandstone to >100 yr for granite. In the field, there were differences in pit size and shapes of the urchins (height:diameter ratio). The pits were shallow and urchins flatter at the granite site, and the pits were deeper and urchins taller at the sedimentary sites. Although overall pit sizes were larger on mudstone than on sandstone, urchin size accounted for this difference. A second, short-term experiment, showed the primary mechanism for bioerosion was ingestion of the substratum. This experiment eliminated potential confounding factors of the year-long experiment and yielded higher bioerosion rates. Given the high densities of urchins, large amounts of rock can be converted to sediment over short time periods. Urchins on sandstone can excavate as much as 11.4 kg m-2 yr-1. On a broader geographic scale, sediment production can exceed 100 t ha-1 yr-1, and across their range, their combined bioerosion is comparable to the sediment load of many rivers. The phase shift between urchin barrens and kelp bed habitats in the North Pacific is controlled by the trophic cascade of sea otters. By limiting urchin populations, these apex predators also may indirectly control a substantial component of coastal rates of bioerosion.
Unconventional gas drilling (UGD) has enabled extraordinarily rapid growth in the extraction of natural gas. Despite frequently expressed public concern, human health studies have not kept pace. We investigated the association of proximity to UGD in the Marcellus Shale formation and perinatal outcomes in a retrospective cohort study of 15,451 live births in Southwest Pennsylvania from 2007-2010. Mothers were categorized into exposure quartiles based on inverse distance weighted (IDW) well count; least exposed mothers (first quartile) had an IDW well count less than 0.87 wells per mile, while the most exposed (fourth quartile) had 6.00 wells or greater per mile. Multivariate linear (birth weight) or logistical (small for gestational age (SGA) and prematurity) regression analyses, accounting for differences in maternal and child risk factors, were performed. There was no significant association of proximity and density of UGD with prematurity. Comparison of the most to least exposed, however, revealed lower birth weight (3323 ± 558 vs 3344 ± 544 g) and a higher incidence of SGA (6.5 vs 4.8%, respectively; odds ratio: 1.34; 95% confidence interval: 1.10-1.63). While the clinical significance of the differences in birth weight among the exposure groups is unclear, the present findings further emphasize the need for larger studies, in regio-specific fashion, with more precise characterization of exposure over an extended period of time to evaluate the potential public health significance of UGD.
Asthma is common and can be exacerbated by air pollution and stress. Unconventional natural gas development (UNGD) has community and environmental impacts. In Pennsylvania, UNGD began in 2005, and by 2012, 6253 wells had been drilled. There are no prior studies of UNGD and objective respiratory outcomes.
Identifying the geochemical fingerprints of fluids that return to the surface after high volume hydraulic fracturing of unconventional oil and gas reservoirs has important applications for assessing hydrocarbon resource recovery, environmental impacts, and wastewater treatment and disposal. Here, we report for the first time, novel diagnostic elemental and isotopic signatures (B/Cl, Li/Cl, δ(11)B, and δ(7)Li) useful for characterizing hydraulic fracturing flowback fluids (HFFF) and distinguishing sources of HFFF in the environment. Data from 39 HFFFs and produced water samples show that B/Cl (>0.001), Li/Cl (>0.002), δ(11)B (25-31‰) and δ(7)Li (6-10‰) compositions of HFFF from the Marcellus and Fayetteville black shale formations were distinct in most cases from produced waters sampled from conventional oil and gas wells. We posit that boron isotope geochemistry can be used to quantify small fractions (∼0.1%) of HFFF in contaminated fresh water and likely be applied universally to trace HFFF in other basins. The novel environmental application of this diagnostic isotopic tool is validated by examining the composition of effluent discharge from an oil and gas brine treatment facility in Pennsylvania and an accidental spill site in West Virginia. We hypothesize that the boron and lithium are mobilized from exchangeable sites on clay minerals in the shale formations during the hydraulic fracturing process, resulting in the relative enrichment of boron and lithium in HFFF.
Sedimentary rocks at Yellowknife Bay (Gale Crater) on Mars include mudstone sampled by the Curiosity rover. The samples, John Klein and Cumberland, contain detrital basaltic minerals, Ca-sulfates, Fe oxide/hydroxides, Fe-sulfides, amorphous material, and trioctahedral smectites. The John Klein smectite has basal spacing of ~10 Å indicating little interlayer hydration. The Cumberland smectite has basal spacing at ~13.2 Å as well as ~10 Å. The ~13.2 Å spacing suggests a partially chloritized interlayer or interlayer Mg or Ca facilitating H2O retention. Basaltic minerals in the mudstone are similar to those in nearby eolian deposits. However, the mudstone has far less Fe-forsterite, possibly lost with formation of smectite plus magnetite. Late Noachian/Early Hesperian or younger age indicates that clay mineral formation on Mars extended beyond Noachian time.
- Journal of magnetic resonance (San Diego, Calif. : 1997)
- Published almost 6 years ago
Unconventional petroleum resources, particularly in shales, are expected to play an increasingly important role in the world’s energy portfolio in the coming years. Nuclear magnetic resonance (NMR), particularly at low-field, provides important information in the evaluation of shale resources. Most of the low-field NMR analyses performed on shale samples rely heavily on standard T1 and T2 measurements. We present a new approach using solid echoes in the measurement of T1 and T1-T2 correlations that addresses some of the challenges encountered when making NMR measurements on shale samples compared to conventional reservoir rocks. Combining these techniques with standard T1 and T2 measurements provides a more complete assessment of the hydrogen-bearing constituents (e.g., bitumen, kerogen, clay-bound water) in shale samples. These methods are applied to immature and pyrolyzed oil shale samples to examine the solid and highly viscous organic phases present during the petroleum generation process. The solid echo measurements produce additional signal in the oil shale samples compared to the standard methodologies, indicating the presence of components undergoing homonuclear dipolar coupling. The results presented here include the first low-field NMR measurements performed on kerogen as well as detailed NMR analysis of highly viscous thermally generated bitumen present in pyrolyzed oil shale.
Horizontal drilling and hydraulic fracturing are increasingly used for recovering energy resources in black shales across the globe. Although newly-drilled wells are providing access to rocks and fluids from kilometer depths to study the deep biosphere, we have much to learn about microbial ecology of shales before and after “fracking”. Recent studies provide a framework for considering how engineering activities alter this rock-hosted ecosystem. We first provide data on the geochemical environment and microbial habitability in pristine shales. Next we summarize data showing the same pattern across fractured shales: diverse assemblages of microbes are introduced into the subsurface, eventually converging to a low diversity, halotolerant, bacterial and archaeal community. Data we synthesized show that the shale microbial community predictably shifts in response to temporal changes in geochemistry, favoring conservation of key microorganisms regardless of inputs, shale location, or operators. We identified factors that constrain diversity in the shale and inhibit biodegradation at the surface, including salinity, biocides, substrates, and redox. Continued research in this engineered ecosystem is required to assess additive biodegradability, quantify infrastructure biocorrosion, treat wastewaters that return to the surface, and potentially enhance energy production through in situ methanogenesis.
- Proceedings of the National Academy of Sciences of the United States of America
- Published about 6 years ago
Concern has been raised in the scientific literature about the environmental implications of extracting natural gas from deep shale formations, and published studies suggest that shale gas development may affect local groundwater quality. The potential for surface water quality degradation has been discussed in prior work, although no empirical analysis of this issue has been published. The potential for large-scale surface water quality degradation has affected regulatory approaches to shale gas development in some US states, despite the dearth of evidence. This paper conducts a large-scale examination of the extent to which shale gas development activities affect surface water quality. Focusing on the Marcellus Shale in Pennsylvania, we estimate the effect of shale gas wells and the release of treated shale gas waste by permitted treatment facilities on observed downstream concentrations of chloride (Cl(-)) and total suspended solids (TSS), controlling for other factors. Results suggest that (i) the treatment of shale gas waste by treatment plants in a watershed raises downstream Cl(-) concentrations but not TSS concentrations, and (ii) the presence of shale gas wells in a watershed raises downstream TSS concentrations but not Cl(-) concentrations. These results can inform future voluntary measures taken by shale gas operators and policy approaches taken by regulators to protect surface water quality as the scale of this economically important activity increases.
The safe disposal of liquid wastes associated with oil and gas production in the United States is a major challenge given their large volumes and typically high levels of contaminants. In Pennsylvania, oil and gas wastewater is sometimes treated at brine treatment facilities and discharged to local streams. This study examined the water quality and isotopic compositions of discharged effluents, surface waters, and stream sediments associated with a treatment facility site in western Pennsylvania. The elevated levels of chloride and bromide, combined with the strontium, radium, oxygen, and hydrogen isotopic compositions of the effluents reflect the composition of Marcellus Shale produced waters. The discharge of the effluent from the treatment facility increased downstream concentrations of chloride and bromide above background levels. Barium and radium were substantially (>90%) reduced in the treated effluents compared to concentrations in Marcellus Shale produced waters. Nonetheless, (226)Ra levels in stream sediments (544-8759 Bq/kg) at the point of discharge were ∼200 times greater than upstream and background sediments (22-44 Bq/kg) and above radioactive waste disposal threshold regulations, posing potential environmental risks of radium bioaccumulation in localized areas of shale gas wastewater disposal.
Natural gas has become a leading source of alternative energy with the advent of techniques to economically extract gas reserves from deep shale formations. Here, we present an assessment of private well water quality in aquifers overlying the Barnett Shale formation of North Texas. We evaluated samples from 100 private drinking water wells using analytical chemistry techniques. Analyses revealed that arsenic, selenium, strontium and total dissolved solids (TDS) exceeded the Environmental Protection Agency’s Drinking Water Maximum Contaminant Limit (MCL) in some samples from private water wells located within 3 km of active natural gas wells. Lower levels of arsenic, selenium, strontium, and barium were detected at reference sites outside the Barnett Shale region as well as sites within the Barnett Shale region located more than 3 km from active natural gas wells. Methanol and ethanol were also detected in 29% of samples. Samples exceeding MCL levels were randomly distributed within areas of active natural gas extraction, and the spatial patterns in our data suggest that elevated constituent levels could be due to a variety of factors including mobilization of natural constituents, hydrogeochemical changes from lowering of the water table, or industrial accidents such as faulty gas well casings.