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In this study, water and whole rock samples from hydraulically fractured wells in the Marcellus Shale (Middle Devonian), and water from conventional wells producing from Upper Devonian sandstones were analyzed for lithium concentrations and isotope ratios ( 7 Li). The distribution of lithium concentrations in different mineral groups was determined using sequential extraction. Structurally bound Li, predominantly in clays, accounted for 75-91 wt. % of total Li, whereas exchangeable sites and carbonate cement contain negligible Li (< 3%). Up to 20% of the Li is present in the oxidizable fraction (organic matter and sulfides). The δ 7 Li values for whole rock shale in Greene Co., Pennsylvania, and Tioga Co., New York, ranged from-2.3 to +4.3‰, similar to values reported for other shales in the literature. The  7 Li values in shale rocks with stratigraphic depth record progressive weathering of the source region; the most weathered and clay-rich strata with isotopically light Li are found closest to the top of the stratigraphic section. Diagenetic illite-smectite transition could also have partially affected the bulk Li content and isotope ratios of the Marcellus Shale. In Greene Co., southwest Pennsylvania, the Upper Devonian sandstone formation waters have  7 Li values of +14.6 ± 1.2 (2SD, n = 25), and are distinct from Marcellus Shale formation waters which have  7 Li of +10.0 ± 0.8 (2SD, n = 12). These two formation waters also maintain distinctive 87 Sr/ 86 Sr ratios suggesting hydrologic separation between these units. Applying temperature-dependent illitilization model to Marcellus Shale, we found that Li concentration in clay minerals increased with Li concentration in pore fluid during diagenetic illite-smectite transition. Samples from north central PA show a much smaller range in both δ 7 Li and 87 Sr/ 86 Sr than in southwest Pennsylvania. Spatial variations in Li and δ 7 Li values show that Marcellus formation waters are not homogeneous across the Appalachian Basin. Marcellus formation waters in the northeastern Pennsylvania portion of the basin show a much smaller range in both δ 7 Li and 87 Sr/ 86 Sr, suggesting long term, cross-formational fluid migration in this region. Assessing the impact of potential mixing of fresh water with deep formation water requires establishment of a geochemical and isotopic baseline in the shallow, fresh water aquifers, and site specific characterization of formation water, followed by long-term monitoring, particularly in regions of future shale gas development.

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Waters coproduced with hydrocarbons from unconventional oil and gas reservoirs such as the hydraulically fractured Middle Devonian Marcellus Shale in the Appalachian Basin, USA, contain high levels of total dissolved solids (TDS), including Ba, which has been variously ascribed to drilling mud dissolution, interaction with pore fluids or shale exchangeable sites, or fluid migration through fractures. Here, we show that Marcellus Shale produced waters contain some of the heaviest Ba (high 138 Ba/ 134 Ba) measured to date (δ 138 Ba = +0.36‰ to +1.49‰ ± 0.06‰) and are distinct from overlying Upper Devonian/Lower Mississippian reservoirs (δ 138 Ba = −0.83‰ to −0.52‰). Marcellus Shale produced water values do not overlap with drilling mud barite (δ 138 Ba ≈ 0.0‰) and are significantly offset from Ba reservoirs within the producing portion of the Marcellus Shale, including exchangeable sites and carbonate cement. Precipitation, desorption, and diffusion processes are insufficient or in the wrong direction to produce the observed enrichments in heavy Ba. We hypothesize that the produced water is derived primarily from brines adjacent to and most likely below the Marcellus Shale, although such deep brines have not yet been obtained for Ba isotope analysis. Barium isotopes show promise for tracking formation waters and for understanding water-rock interaction under downhole conditions.

Lithium (Li) concentrations of produced water from unconventional (horizontally drilled and hydraulically fractured shale) and conventional gas wells in Devonian reservoirs in the Appalachian Plateau region of western Pennsylvania range from 0.6 to 17 mmol kg À1 , and Li isotope ratios, expressed as in d 7 Li, range from +8.2 to +15&. Li concentrations are as high as 40 mmol kg À1 in produced waters from Plio-Pleistocene through Jurassicaged reservoirs in the Gulf Coast Sedimentary Basin analyzed for this study, and d 7 Li values range from about +4.2 to +16.6&. Because of charge-balance constraints and rock buffering, Li concentrations in saline waters from sedimentary basins throughout the world (including this study) are generally positively correlated with chloride (Cl), the dominant anion in these fluids. Li concentrations also vary with depth, although the extent of depth dependence differs among sedimentary basins. In general, Li concentrations are higher than expected from seawater or evaporation of seawater and therefore require water-mineral reactions that remove lithium from the minerals. Li isotope ratios in these produced waters vary inversely with temperature. However, calculations of temperature-dependent fractionation of d 7 Li between average shale d 7 Li (À0.7&) and water result in d 7 Li water that is more positive than that of most produced waters. This suggests that aqueous d 7 Li may reflect transport of water from depth and/or reaction with rocks having d 7 Li lighter than average shale.

Injection of fracturing fluids into shales during hydraulic stimulation can result in various chemical reactions involving the injected fluid and host shale rock. Differences in chemical composition between the injected fluids and fractured rock can result in mineral precipitation along shale fractures and within the shale matrix, potentially affecting long-term gas recovery from the shale. Our prior research showed that mineral precipitation and dissolution occur along freshly-generated fractures, and within the shale matrix, during core flood experiments in which laboratory-fractured Marcellus Shale was exposed to simulated hydraulic fracturing fluids. Many of the mineral precipitation reactions were hypothesized to occur due to the inability for antiscaling compounds in the fracturing fluids to control mineral precipitation at elevated temperature and pressure. In some locations along the fracture, proppant was cemented to shale surfaces through secondary mineral precipitates. The present study focuses on core flood experiments using fresh core and site hydraulic fracturing fluid from the Marcellus Shale Energy and Environmental Laboratory site (MSEEL; Morgantown, WV) at reservoir pressure and temperature conditions. The objectives of this study are to evaluate the reproducibility of the earlier experiments using fresh core, and to identify causes for any observed differences with the prior outcrop-based experiments.