Both unconventional and conventional oil and gas production have led to instances of brine contamination of near-surface environments from spills of saline produced waters. Strontium isotope ratios ( 87 Sr/ 86 Sr) have been used as a sensitive tracer of sources of brine contamination in surface waters and shallow aquifers in areas where oil and gas production are limited to only a few reservoirs and produced water sources are well-defined. Recent expansion of conventional and unconventional oil and gas production to additional tight formations within sedimentary basins has resulted in production of formation waters from multiple oil and gas reservoirs that may have similar chemical and isotopic ratios, including 87 Sr/ 86 Sr. This study evaluates the utility of 87 Sr/ 86 Sr, the most widely available tracer dataset beyond major ion chemistry and water stable isotopes, as a tracer of brine contamination related to conventional and unconventional oil and gas production in the Williston, Appalachian and Permian basins. Multiple stacked oil and gas reservoirs within each basin have overlapping formation water 87 Sr/ 86 Sr, based on a non-parametric statistical test. For example, in the Appalachian Basin, produced waters from unconventional gas production in the Middle Devonian Marcellus and Upper Ordovician Utica shales have overlapping 87 Sr/ 86 Sr. In the Permian Basin, produced waters from the unconventional Pennsylvanian-Permian Wolfcamp Shale and conventional and unconventional Pennsylvanian Cisco/Canyon/Strawn formations have similar 87 Sr/ 86 Sr. In the Williston Basin produced waters from Late Devonian to Early Mississippian Bakken Formation unconventional oil production have overlapping 87 Sr/ 86 Sr with produced waters associated with minor production of conventional oil from the Middle Devonian Winnipegosis. Improved spatial characterization of 87 Sr/ 86 Sr and other isotopic signatures of produced waters from various oil/gas reservoirs are needed to constrain geographic and depth variability of produced waters in hydrocarbon producing regions. This is particularly important, as unconventional oil and gas production expands in areas of existing conventional oil and gas production, where delineating sources of saline produced waters in cases of accidental surface spills or subsurface leakage will become a greater challenge. Sr isotopes alone may not be able to distinguish produced waters in areas with overlapping production from reservoirs with similar isotopic signatures. • Sr isotopes may not be effective tracers where stacked reservoirs are present. • More Sr isotope data required to understand spatial/depth variability. • Multiple tracers may be needed to identify sources of contamination.

Global groundwater volumes in the upper 2 km of the Earth's continental crust—critical for water security—are well estimated. Beyond these depths, a vast body of largely saline and non-potable groundwater exists down to at least 10 km—a volume that has not yet been quantified reliably at the global scale. Here, we estimate the amount of groundwater present in the upper 10 km of the Earth's continental crust by examining the distribution of sedimentary and crystalline rocks with depth and applying porosity-depth relationships. We demonstrate that groundwater in the 2–10 km zone (what we call “deep groundwater”) has a volume comparable to that of groundwater in the upper 2 km of the Earth's crust. These new estimates make groundwater the largest continental reservoir of water, ahead of ice sheets, provide a basis to quantify geochemical cycles, and constrain the potential for large-scale isolation of waste fluids.

Large volumes of saline formation water are both produced from and injected into sedimentary basins as a by-product of oil and gas production. Despite this, the location of production and injection wells has not been studied in detail at the regional scale and the effects on deep groundwater flow patterns (i.e., below the base of groundwater protection) possibly driving fluid flow toward shallow aquifers remain uncertain. Even where injection and production volumes are equal at the basin scale, local changes in hydraulic head can occur due to the distribution of production and injection wells. In the Canadian portion of the Williston Basin, over 4.6 × 109 m3 of water has been co-produced with 5.4 × 108 m3 of oil, and over 5.5 × 109 m3 of water has been injected into the subsurface for salt water disposal or enhanced oil recovery. Despite approximately equal values of produced and injected fluids at the sedimentary basin scale over the history of development, cumulative fluid deficits and surpluses per unit area in excess of a few 100 mm are present at scales of a few 100 km2 . Fluid fluxes associated with oil and gas activities since 1950 likely exceed background groundwater fluxes in these areas. Modeled pressures capable of creating upward hydraulic gradients are predicted for the Midale Member and Mannville Group, two of the strata with the highest amounts of injection in the study area. This could lead to upward leakage of fluids if permeable pathways, such as leaky wells, are present.

Deep meteoric waters comprise a key component of the hydrologic cycle, transferring water, energy, and life between the earth’s surface and deeper crustal environments, yet little is known about th...

The impacts of Pleistocene glaciation on groundwater flow systems in sedimentary basins are widely recognized, but the timing and distribution of subglacial recharge events remain poorly constrained. We investigate the spatial and temporal variability of recharge events from glaciations over the last 2 million years in the Williston Basin, Canada. Integration of fluid chemistry, stable isotope data, and transport modeling indicate that meltwater arrived at depths of ∼600–1000 m in the northcentral region of the Williston Basin at two separate time periods, 75–150 and 300 ka, which we attribute to permeability differences between stacked aquifer systems. Our findings indicate that meltwater recharge extended along the northern margin of the Williston Basin as well as previously identified recharge areas to the east. Given the distance of measurements from recharge areas, evidence of recharge from the early to mid-Pleistocene appears to be preserved in the Williston Basin.

The interactions between old abandoned wellbores of suspect well integrity with hydraulic fracturing (HF), enhanced oil recovery (EOR), or salt water disposal (SWD) operations can result in upward leakage of deep aqueous liquids into overlying aquifers. This potential for upward fluid migration is largely unquantified as monitoring abandoned wells is rarely done, and leakage may go unnoticed especially when in deeper aquifers. This study performs a proximity analysis between old abandoned wells and HF, EOR, and SWD wells, and identifies commingled old abandoned wellbores, which are those wells where groundwater may flow from one aquifer to one or more other aquifers, to identify the locations with the greatest potential for upward aqueous fluid migration at three study sites in the Western Canadian Sedimentary Basin. Our analysis indicates that at all three study sites there are several locations where HF, EOR, or SWD operations are located in close proximity to a given old abandoned well. Much of this overlap occurs in formations above typically produced hydrocarbon reservoirs but below exploited potable aquifers, otherwise known as the intermediate zone, which is often connected between abandonment plugs in old abandoned wells. Information on the intermediate zone is often lacking, and this study suggests that unanticipated alterations to groundwater flow systems within the intermediate zone may be occurring. Results indicate the need for more field-based research on the intermediate zone.

It is commonly thought that old groundwater cannot be pumped sustainably, and that recently recharged groundwater is inherently sustainable. We argue that both old and young groundwaters can be used in physically sustainable or unsustainable ways.

Watersheds have served as one of our most basic units of organization in hydrology for over 300 years (Dooge, 1988, https://doi.org/10.1080/02626668809491223; McDonnell, 2017, https://doi.org/10.1038/ngeo2964; Perrault, 1674, https://www.abebooks.com/first‐edition/lorigine‐fontaines‐Perrault‐Pierre‐Petit‐Imprimeur/21599664536/bd). With growing interest in groundwater‐surface water interactions and subsurface flow paths, hydrologists are increasingly looking deeper. But the dialog between surface water hydrologists and groundwater hydrologists is still embryonic, and many basic questions are yet to be posed, let alone answered. One key question is: where is the bottom of a watershed? Knowing where to draw the bottom boundary has not yet been fully addressed in the literature, and how to define the watershed “bottom” is a fraught question. There is large variability across physical and conceptual models regarding how to implement a watershed bottom, and what counts as “deep” varies markedly in different communities. In this commentary, we seek to initiate a dialog on existing approaches to defining the bottom of the watershed. We briefly review the current literature describing how different communities typically frame the answer of just how deep we should look and identify situations where deep flow paths are key to developing realistic conceptual models of watershed systems. We then review the common conceptual approaches used to delineate the watershed lower boundary. Finally, we highlight opportunities to trigger this potential research area at the interface of catchment hydrology and hydrogeology.

The impacts of unconventional oil and gas production via high-volume hydraulic fracturing (HVHF) on water resources, such as water use, groundwater and surface water contamination, and disposal of produced waters, have received a great deal of attention over the past decade. Conventional oil and gas production (e.g., enhanced oil recovery [EOR]), which has been occurring for more than a century in some areas of North America, shares the same environmental concerns, but has received comparatively little attention. Here, we compare the amount of produced water versus saltwater disposal (SWD) and injection for EOR in several prolific hydrocarbon producing regions in the United States and Canada. The total volume of saline and fresh to brackish water injected into depleted oil fields and nonproductive formations is greater than the total volume of produced waters in most regions. The addition of fresh to brackish "makeup" water for EOR may account for the net gain of subsurface water. The total amount of water injected and produced for conventional oil and gas production is greater than that associated with HVHF and unconventional oil and gas production by well over a factor of 10. Reservoir pressure increases from EOR and SWD wells are low compared to injection of fluids for HVHF, however, the longer duration of injections could allow for greater solute transport distances and potential for contamination. Attention should be refocused from the subsurface environmental impacts of HVHF to the oil and gas industry as a whole.

The ideas presented by Stahl (2018) are intriguing. There is a wealth of information that supports that groundwater pumping has perturbed the hydrologic cycle at a global scale (Konikow 2011; Rodell et al. 2018) and perturbations to global elemental cycles would not be unexpected. However, the analysis presented by Stahl (2018) is problematic. Stahl assumes that the 45% of produced waters from oil field operations that were not used in enhanced oil recovery (EOR) are released into the more active portion of the hydrological cycle based on 2007 figures for the United States from Clark and Veil (2009). This figure is substantially lower in reality. Clark and Veil (2009) report that 38.2% of produced waters were injected into nonproducing strata. This injection occurs almost exclusively through Class II disposal wells, which are typically installed in saline aquifers (EPA 2018). Similar practices have been noted in Canada, where there has been a net gain in the amount of water in the Western Canada Sedimentary Basin (Ferguson 2015). In addition, Stahl states that 45% of Shell’s produced water is discharged at the surface based on an estimate from Khatib and Verbeek (2003). However, that study also noted that much of this discharge was to the ocean as part of offshore drilling activities. The overestimation of addition of produced water to the active portion of global elemental cycles will have a notable effect on estimates of fluxes of elements such as Li, Na, Cl, and Ca, which are found in high concentrations

Brines are commonly found at depth in sedimentary basins. Many of these brines are known to be connate waters that have persisted since the early Paleozoic Era. Yet questions remain about their distribution and mechanisms for retention at depth in the Earth's crust. Here we demonstrate that there is insufficient topography to drive these dense fluids from the bottom of deep sedimentary basins. Our assessment based on driving force ratio indicates that sedimentary basins with driving force ratio > 1 contain connate waters and frequently host large evaporite deposits. These stagnant conditions appear to be relatively stable over geological time and insensitive to factors such as glaciations, erosion, compaction, and hydrocarbon generation.

Groundwater resources are being stressed from the top down and bottom up. Declining water tables and near-surface contamination are driving groundwater users to construct deeper wells in many US aquifer systems. This has been a successful short-term mitigation measure where deep groundwater is fresh and free of contaminants. Nevertheless, vertical salinity profiles are not well-constrained at continental-scales. In many regions, oil and gas activities use pore spaces for energy production and waste disposal. Here we quantify depths that aquifer systems transition from fresh-to-brackish and where oil and gas activities are widespread in sedimentary basins across the United States. Fresh-brackish transitions occur at relatively shallow depths of just a few hundred meters, particularly in eastern US basins. We conclude that fresh groundwater is less abundant in several key US basins than previously thought; therefore drilling deeper wells to access fresh groundwater resources is not feasible extensively across the continent. Our findings illustrate that groundwater stores are being depleted not only by excessive withdrawals, but due to injection, and potentially contamination, from the oil and gas industry in areas of deep fresh and brackish groundwater.

Extensive dissolution of evaporites has occurred in the Williston Basin, Canada, but it is unclear what effect this has had on bulk permeability. The bulk of this dissolution has occurred from the Prairie Evaporite Formation, which is predominantly halite and potash. However, minor evaporite beds and porosity infilling have also been removed from the overlying Dawson Bay and Souris River formations, which are predominantly carbonates. This study examines whether permeability values in the Dawson Bay and Souris River formations have been affected by dissolution, by analyzing 142 drillstem tests from those formations. For both the Dawson Bay and Souris River formations, the highest permeabilities were found in areas where halite dissolution had occurred. However, the mean permeabilities were not statistically different in areas of halite dissolution compared to those containing connate water. Subsequent precipitation of anhydrite is known to have clogged pore spaces and fractures in some instances. Geochemical relationships found here support this idea but there is no statistically significant relationship between anhydrite saturation and permeability. Geomechanical effects, notably closure of fractures due to collapse, could be a mitigating factor. The results indicate that coupling dissolution and precipitation to changes in permeability in regional flow models remains a significant challenge.