Geology topics

Glenn D. Jolly

Publications and source records attributed to Glenn D. Jolly.

5 recordsLinked to original sources

USGS2024

Evaluation of coal mine drainage and associated precipitates for radium and rare earth element concentrations

Coal mine drainage (CMD) and associated metal-rich precipitates have recently been proposed as unconventional sources of rare earth elements (REEs). However, the potential occurrence of radium (Ra), a known carcinogen, with the REE-bearing phases has not been investigated. We hypothesized that Ra may occur in solids that are precipitated from CMD as a “radiobarite” solid solution ((Ba,Sr,Ra)SO 4 ) and/or adsorbed with hydrous metal oxides. REEs have been documented to sorb or co-precipitate with iron (Fe), manganese (Mn), and aluminum (Al) oxyhydroxide in CMD solids. Likewise, Ra has been documented to sorb to hydrous Fe and Mn oxides especially where sulfate (SO 4 ) and/or barium (Ba) concentrations are insufficient to precipitate radiobarite. Thus, we conducted the first-ever survey of Ra concentrations in corresponding CMD water and solid samples in the United States. Samples were analyzed from 4 untreated and 9 treated CMD sites in both the bituminous and anthracite coal regions of Pennsylvania across a range of pH and SO 4 concentrations. The dissolved Ra in CMD was relatively low (<0.5 Bq/L), consistent with radiobarite solubility; however, CMD solids were largely composed of amorphous Fe, Al, and Mn oxyhydroxide and silicate minerals. Ra was associated with Mn-enriched CMD solids, upwards of 875 Bq/kg. Total REE + yttrium (Y) content in the CMD solids was enriched upwards of 3600 mg/kg and was significantly correlated with Al content. These preliminary results suggest that REE extraction may target Al-rich solids to avoid Ra in Mn-rich solids.

Pennsylvania↗

USGS2024

Produced water geochemistry from hydraulically stimulated Niobrara Formation petroleum wells: Origin of salinity and temporal perspectives on treatment and reuse

Produced water (i.e., a mixture of returned injection fluids and geologic formation brines) represents the largest volumetric waste stream associated with petroleum production in the United States. As such, produced water has been the focus of intense study with emphasis on understanding the geologic origin of the fluids, environmental impacts of unintended or intentional release, disposal concerns, and their commodity (e.g., lithium) potential. However, produced water geochemistry from many active petroleum plays remain poorly constrained leading to knowledge gaps associated with the origin of brine salinity and parameters (e.g., radium levels) that can impact treatment, disposal, and possible reuse. Here we evaluate the major ion geochemistry, radium concentrations, and stable water isotope composition of ~120 produced water samples collected from 17 producing unconventional petroleum wells in Weld County, Colorado from the Late Cretaceous Niobrara Formation. This sample set encompasses eight produced water time series from four new wells across production days 0 to ~365 and from four established wells across production days ~1000 to ~1700. Additionally, produced water from nine other established Niobrara Formation wells were sampled at discrete time points ranging from day 458 to day 2256, as well as hydraulic fracturing input fluids. These results expand the available Niobrara Formation produced water geochemical data, previously limited to few wells sampled within the first year of production, allowing for the heterogeneity of major ions and radium to be evaluated. Furthermore, we explore the geochemical relationships between major ion ratios and stable water isotope composition to understand the origin of salinity in Niobrara Formation brines from the Denver-Julesburg Basin. These findings are discussed with perspective toward potential treatment and reuse of Niobrara produced water prior to disposal.

Colorado, Nebraska, Wyoming↗

USGS2021

Insights on geochemical, isotopic, and volumetric compositions of produced water from hydraulically fractured Williston Basin oil wells

Tracing produced water origins from wells hydraulically fractured with freshwater-based fluids is sometimes predicated on assumptions that (1) each geological formation contains compositionally unique brine and (2) produced water from recently hydraulically fractured wells resembles fresher meteoric water more so than produced water from older wells. These assumptions are not valid in Williston Basin oil wells sampled in this study. Although distinct average 228 Ra/ 226 Ra ratios were found in water produced from the Bakken and Three Forks Formations, average δ 2 H, δ 18 O, specific gravity, and conductivity were similar but exhibited significant variability across five oil fields within each formation. Furthermore, initial produced water (“flowback”) was operationally defined based on the presence of glycol ether compounds and water from wells that had produced <56% of the amount of fluids injected and sampled within 160 days of fracturing. Flowback unexpectedly exhibited higher temperature, specific gravity, conductivity, δ 2 H, and δ 18 O, but lower oxidation–reduction potential and δ 11 B, relative to the wells thought to be producing formation brines (from wells with a produced-to-injected water ratio [PIWR] > 0.84 and sampled more than 316 days after fracturing). As such, establishing an overall geochemical and isotopic signature of produced water compositions based solely on chemical similarity to meteoric water and formation without the consideration of well treatments, well completion depth, or lateral location across the basin could be misleading if these signatures are assumed to be applicable across the entire basin. These findings have implications for using produced water compositions to understand the interbasin fluid flow and trace sources of hydraulic fracturing fluids.

Montana, North Dakota↗

USGS2017

Environmental signatures and effects of an oil and gas wastewater spill in the Williston Basin, North Dakota

Wastewaters from oil and gas development pose largely unknown risks to environmental resources. In January 2015, 11.4 M L (million liters) of wastewater (300 g/L TDS) from oil production in the Williston Basin was reported to have leaked from a pipeline, spilling into Blacktail Creek, North Dakota. Geochemical and biological samples were collected in February and June 2015 to identify geochemical signatures of spilled wastewaters as well as biological responses along a 44-km river reach. February water samples had elevated chloride (1030 mg/L) and bromide (7.8 mg/L) downstream from the spill, compared to upstream levels (11 mg/L and < 0.4 mg/L, respectively). Lithium (0.25 mg/L), boron (1.75 mg/L) and strontium (7.1 mg/L) were present downstream at 5–10 times upstream concentrations. Light hydrocarbon measurements indicated a persistent thermogenic source of methane in the stream. Semi-volatile hydrocarbons indicative of oil were not detected in filtered samples but low levels, including tetramethylbenzenes and di-methylnaphthalenes, were detected in unfiltered water samples downstream from the spill. Labile sediment-bound barium and strontium concentrations (June 2015) were higher downstream from the Spill Site. Radium activities in sediment downstream from the Spill Site were up to 15 times the upstream activities and, combined with Sr isotope ratios, suggest contributions from the pipeline fluid and support the conclusion that elevated concentrations in Blacktail Creek water are from the leaking pipeline. Results from June 2015 demonstrate the persistence of wastewater effects in Blacktail Creek several months after remediation efforts started. Aquatic health effects were observed in June 2015; fish bioassays showed only 2.5% survival at 7.1 km downstream from the spill compared to 89% at the upstream reference site. Additional potential biological impacts were indicated by estrogenic inhibition in downstream waters. Our findings demonstrate that environmental signatures from wastewater spills are persistent and create the potential for long-term environmental health effects.

North Dakota↗

USGS2014

Surface disposal of produced waters in western and southwestern Pennsylvania: potential for accumulation of alkali-earth elements in sediments

Waters co-produced with hydrocarbons in the Appalachian Basin are of notably poor quality (concentrations of total dissolved solids (TDS) and total radium up to and exceeding 300,000 mg/L and 10,000 pCi/L, respectively). Since 2008, a rapid increase in Marcellus Shale gas production has led to a commensurate rise in associated wastewater while generation of produced water from conventional oil and gas activities has continued. In this study, we assess whether disposal practices from treatment of produced waters from both shale gas and conventional operations in Pennsylvania could result in the accumulation of associated alkali earth elements. The results from our 5 study sites indicate that there was no increase in concentrations of total Ra (Ra-226) and extractable Ba, Ca, Na, or Sr in fluvial sediments downstream of the discharge outfalls (p > 0.05) of publicly owned treatment works (POTWs) and centralized waste treatment facilities (CWTs). However, the use of road spreading of brines from conventional oil and gas wells for deicing resulted in accumulation of Ra-226 (1.2 ×), and extractable Sr (3.0 ×), Ca (5.3 ×), and Na (6.2 ×) in soil and sediment proximal to roads (p < 0.05). Although this study is an important initial assessment of the impacts of these disposal practices, more work is needed to consider the environmental consequences of produced waters management.

Pennsylvania↗