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Opine dehydrogenases (ODHs) from the bacterial pathogens Staphylococcus aureus, Pseudomonas aeruginosa, and Yersinia pestis perform the final enzymatic step in the biosynthesis of a new class of opine metallophores, which includes staphylopine, pseudopaline, and yersinopine, respectively. Growing evidence indicates an important role for this pathway in metal acquisition and virulence, including in lung and burn-wound infections (P. aeruginosa) and in blood and heart infections (S. aureus). Here, we present kinetic and structural characterizations of these three opine dehydrogenases. A steady-state kinetic analysis revealed that the three enzymes differ in α-keto acid and NAD(P)H substrate specificity and nicotianamine-like substrate stereoselectivity. The structural basis for these differences was determined from five ODH X-ray crystal structures, ranging in resolution from 1.9 to 2.5 Å, with or without NADP(+) bound. Variation in hydrogen bonding with NADPH suggested an explanation for the differential recognition of this substrate by these three enzymes. Our analysis further revealed candidate residues in the active sites required for binding of the α-keto acid and nicotianamine-like substrates and for catalysis. This work reports the first structural kinetic analyses of enzymes involved in opine metallophore biosynthesis in three important bacterial pathogens of humans.

© 2018 The Author(s). Methane clumped-isotope compositions provide a new approach to understanding the formational conditions of methane from both biogenic and thermogenic sources. Under some conditions, these compositions can be used to reconstruct the formational temperatures of the gas, and this capability can be applied to common subsets of both biogenic and thermogenic systems. Additionally, there are examples in which clumped-isotope compositions do not reflect gas-formation temperatures but instead mixing effects and kinetic phenomena; such kinetic effects also occur in common and recognizable subtypes of biogenic and thermogenic gases. Here we review the use of methane clumped-isotope measurements for understanding the origin of methane in the subsurface. We review methane clumped-isotope measurements from numerous biogenic and thermogenic natural gas reservoirs.We then place these measurements in the context of common frameworks for identifying the formational conditions of methane including the use of methane δ13C and δD values and C1/C2-3ratios. Finally, we propose a framework for how methane clumped isotopes can be used to identify the origin of methane accumulations.

Evaluation of petroleum-fluid properties, hydrocarbon shows, and source-rock characteristics requires new tools to properly recognize and correct for drilling and test-induced contamination, which is increasingly common in modern deepwater field operations. Oil exploration, development, and now production, are more frequently conducted in deeper-water environments where the challenges faced by drilling and operations can severely impact the evaluation of oil and rock geochemistry and fluid properties. Poorly consolidated sediments, swelling clay minerals, and responses to evolving environmental regulations regarding offshore disposal of drill cuttings have resulted in the widespread use of enhanced mineral oil or synthetic-based muds. Also, water-based drilling fluids used in some deepwater operations contain additives that may impact fluid and rock geochemistry. For example, asphalt-based shale stabilizers are added to aid well-bore competency and prevent sticking drill pipe, and polyalkylated glycols are added to depress freezing temperatures and prevent the formation of gas hydrates in the drilling mud. Because these and other additives are often a significant component of water-based muds, they may affect the geochemical signature of fluids and rocks and alter fluid properties. Highly saline brines are another important source of contamination as they are used in completion fluids, water-wet muds, and are emulsified in oil-wet muds. Brine components impact metal contents of petroleum-fluid tests and complicate the determination of formation-water compositions. Despite potential problems introduced by these additives, successful strategies can be devised to accurately access key geochemical and engineering parameters.

Summary Biodegradation of oils in nature is important in reservoirs cooler than approximately 80°C. Oils from shallower, cooler reservoirs tend to be progressively more biodegraded than those in deeper, hotter reservoirs. Increasing levels of biodegradation generally cause a decline in oil quality, diminishing the producibility and value of the oil as API gravity and distillate yields decrease; in addition, viscosity, sulfur, asphaltene, metals, vacuum residua, and total acid numbers increase. For a specific hydrocarbon system (similar source type and level of maturity), general trends exist for oil-quality parameters vs. present-day reservoir temperatures of It has long been observed that fresh, oxygenated waters in contact with reservoir oil can cause extensive aerobic biodegradation. More recently, it has been recognized that anaerobic sulfate-reducing and fermenting bacteria also can degrade petroleum. Highly saline formation waters may inhibit bacterial degradation and effectively shield oils from oil-quality deterioration. The timing of hydrocarbon charge(s) and the post-charge temperature history of the reservoir can have major effects on oil quality. Reservoirs undergoing current charging with hydrocarbons may overwhelm the ability of bacteria to degrade the oil, resulting in better-than-anticipated oil quality. Fresh charge to reservoirs containing previously degraded oil will upgrade oil quality. Calibrated methods of oil-quality risking, based on a detailed evaluation of reservoir charge and temperature history and local controls on biodegradation, need to be developed on a play and prospect basis.

Making of methane deep underground Technologies such as hydraulic fracturing, or “fracking,” can now extract natural gas from underground reservoirs. Within the gas, the ratio of certain isotopes holds clues to its origins. Stolper et al. analyzed a wide range of natural gas, including samples from some of the most active fracking sites in the United States. Using a “clumped isotope” technique, the authors could estimate the high temperatures at which methane formed deep underground, as well as the lower temperatures at which ancient microbes produced methane. The approach can help to distinguish the degree of mixing of gas from both sources. Science , this issue p. 1500

A combination of fluid inclusion and geochemical analyses were conducted on rocks and reservoir fluids to develop an improved understanding of down-dip oil potential in a mature exploration play, onshore Abu Dhabi. Exploration for oil in the region is complicated by low permeability carbonate reservoirs, poor seismic imaging, and complex hydrocarbon maturation and migration histories. In addition, a broad range of fluid properties, including gas, condensate, and high API oil make evaluation of reservoir fluid phase difficult to evaluate. In this challenging environment, geochemical and fluid inclusion techniques are effective tools for identifying down-dip oil potential from gas cap fluids and reservoir rock samples. Fluid inclusion data are used to develop a hydrocarbon emplacement history, which constrains the distribution of fluids throughout the exploration area. In some areas, under-saturated gas inclusions trapped at present-day temperatures suggest a high risk for down-dip oil. Conversely, other structures contain oil inclusions that have been displaced recently by saturated gas, suggesting good potential for down-dip oil. Geochemical analyses of recovered fluids were independently utilized to predict the likelihood of down-dip oil. These combined techniques were placed in a geologic framework to regionally risk the potential for down-dip oil throughout the exploration area. This allows for improved resource evaluation and prioritization of exploration efforts in areas of the play where a high probability of down-dip oil exists.