ALBERT

Description: 〈p〉Type I interferons are highly potent cytokines essential for self-protection against tumors and infections. Deregulations of type I interferon signaling are associated with multiple diseases that require novel therapeutic options. Here, we identified the small molecule, IT1t, a previously described CXCR4 ligand, as a highly potent inhibitor of Toll-like receptor 7 (TLR7)–mediated inflammation. IT1t inhibits chemical (R848) and natural (HIV) TLR7-mediated inflammation in purified human plasmacytoid dendritic cells from blood and human tonsils. In a TLR7-dependent lupus-like model, in vivo treatment of mice with IT1t drives drastic reduction of both systemic inflammation and anti–double-stranded DNA autoantibodies and prevents glomerulonephritis. Furthermore, IT1t controls inflammation, including interferon α secretion, in resting and stimulated cells from patients with systemic lupus erythematosus. Our findings highlight a groundbreaking immunoregulatory property of CXCR4 signaling that opens new therapeutic perspectives in inflammatory settings and autoimmune diseases.〈/p〉

Description: We present a new method to determine the total dissolved solids (TDS) concentration and the stable isotope composition of drill-core-derived Porewater in oil sands reservoirs of northeastern Alberta, Canada. The technique described here uses two end-member mixing relationships between the stable isotope compositions of drilling fluids and formation waters from mechanically extracted porewater samples to calculate the formation water TDS, $${\delta }^{2}\mathrm{H}$$ , and $${\delta }^{18}\mathrm{O}$$ values. Analysis of water samples extracted directly from McMurray Formation drill core provides an inexpensive and robust advance in the ability to characterize the properties of reservoir pore waters that can be widely deployed because of the ubiquity of drill-core sampling. Porewater data from three oil sands wells from different locations within the Athabasca region are presented in this study. Water derived from these wells had TDS values of 860 to 45,000 mg/L, $${\delta }^{2}\mathrm{H}$$ values of –172 to –149, and $${\delta }^{18}\mathrm{O}$$ values of –22.4 to –19.3. These values are consistent with regional trends in formation water salinity and stable isotope compositions, and illustrate the wide range of TDS values that can be found in McMurray Formation waters. The ability to characterize aqueous fluids within bitumen-saturated reservoirs is a new development that enables measurement of aqueous fluid properties that is not easily obtained by other sampling means. This methodology provides a tool to understand the origin and movement of reservoir water related to natural groundwater flow, or to anthropogenic influence by steam injection. Novel in situ extraction technologies that use electromagnetic heating systems may also benefit from detailed characterization of aqueous reservoir fluids to accurately determine the properties of the reservoir porewater.

Description: A new stable isotope approach was used to determine the total dissolved solids concentration and stable isotope composition for oil sands drill core extracted porewater at the Suncor–Firebag oil sands field in northeastern Alberta, Canada. A stable isotope mixing approach was used to correct for contamination by drilling fluids in the porewater samples. The mean isotopic compositions of oxygen ( $${\delta }^{18}\mathrm{O}$$ ) and hydrogen ( $${\delta }^{2}\mathrm{H}$$ ) in water for fluid samples from 12 wells at Firebag were –20.5 ± 1.4 and –157 ± 11, respectively. The mean total dissolved solids (TDS) concentration of the reservoir formation water in 12 sampled wells was 1100 ± 400 mg/L (1). These results suggest that the McMurray Formation water at Firebag is primarily derived from Holocene groundwater recharge, and that the water within the bitumen reservoir is similar to groundwater well samples obtained within the McMurray Formation at Firebag. The results obtained in this study are consistent with regional trends and previously proposed local hydrogeological flow conditions.

Description: Total dissolved solids (TDS) concentrations of 258 Lower Cretaceous McMurray Formation water samples in the Athabasca oil sands region (54 to 58°N and 110 to 114°W) were mapped using published data from recent government reports and environmental impact assessments. McMurray Formation waters varied from nonsaline (240 mg/L) to brine (279,000 mg/L) with a regional trend of high salinity water approximately following the partial dissolution front of the Devonian Prairie Evaporite Formation. The simplest hydrogeological explanation for the observed formation water salinity data is that Devonian aquifers are locally connected to the McMurray Formation via conduits in the sub-Cretaceous karst system in the region overlying the partial dissolution front of the Prairie Evaporite Formation. The driving force for upward formation water flow is provided by the Pleistocene glaciation events that reversed the regional Devonian flow system over the past 2 m.y. in the Athabasca region. This study demonstrates that a detailed approach to hydrogeological assessment is required to elucidate TDS concentrations in McMurray Formation waters at an individual lease-area scale. The observed heterogeneity in formation water TDS and the potential for present day upward flow has implications for both mining and in situ oil sands resource development.