Geology topics

Mark A Engle

Publications and source records attributed to Mark A Engle.

8 recordsLinked to original sources

USGS2024

Illegal dumping of oil and gas wastewater alters arid soil microbial communities

The Permian Basin, underlying southeast New Mexico and west Texas, is one of the most productive oil and gas (OG) provinces in the United States. Oil and gas production yields large volumes of wastewater with complex chemistries, and the environmental health risks posed by these OG wastewaters on sensitive desert ecosystems are poorly understood. Starting in November 2017, 39 illegal dumps, as defined by federal and state regulations, of OG wastewater were identified in southeastern New Mexico, releasing ~600,000 L of fluid onto dryland soils. To evaluate the impacts of these releases, we analyzed changes in soil geochemistry and microbial community composition by comparing soils from within OG wastewater dump-affected samples to unaffected zones. We observed significant changes in soil geochemistry for all dump-affected compared with control samples, reflecting the residual salts and hydrocarbons from the OG-wastewater release (e.g., enriched in sodium, chloride, and bromide). Microbial community structure significantly ( P < 0.01) differed between dump and control zones, with soils from dump areas having significantly ( P < 0.01) lower alpha diversity and differences in phylogenetic composition. Dump-affected soil samples showed an increase in halophilic and halotolerant taxa, including members of the Marinobacteraceae, Halomonadaceae, and Halobacteroidaceae, suggesting that the high salinity of the dumped OG wastewater was exerting a strong selective pressure on microbial community structure. Taxa with high similarity to known hydrocarbon-degrading organisms were also detected in the dump-affected soil samples. Overall, this study demonstrates the potential for OG wastewater exposure to change the geochemistry and microbial community dynamics of arid soils.

Applied and Environmental Microbiology↗

USGS2022

Dissolved organic matter within oil and gas associated wastewaters from U.S. unconventional petroleum plays: Comparisons and consequences for disposal and reuse

Wastewater generated during petroleum extraction (produced water) may contain high concentrations of dissolved organics due to their intimate association with organic-rich source rocks, expelled petroleum, and organic additives to fluids used for hydraulic fracturing of unconventional (e.g., shale) reservoirs. Dissolved organic matter (DOM) within produced water represents a challenge for treatment prior to beneficial reuse. High salinities characteristic of produced water, often 10× greater than seawater, coupled to the complex DOM ensemble create analytical obstacles with typical methods. Excitation-emission matrix spectroscopy (EEMS) can rapidly characterize the fluorescent component of DOM with little impact from matrix effects. We applied EEMS to evaluate DOM composition in 18 produced water samples from six North American unconventional petroleum plays. Represented reservoirs include the Eagle Ford Shale (Gulf Coast Basin), Wolfcamp/Cline Shales (Permian Basin), Marcellus Shale and Utica/Point Pleasant (Appalachian Basin), Niobrara Chalk (Denver-Julesburg Basin), and the Bakken Formation (Williston Basin). Results indicate that the relative chromophoric DOM composition in unconventional produced water may distinguish different lithologies, thermal maturity of resource types (e.g., heavy oil vs. dry gas), and fracturing fluid compositions, but is generally insensitive to salinity and DOM concentration. These results are discussed with perspective toward DOM influence on geochemical processes and the potential for targeted organic compound treatment for the reuse of produced water.

Colorado, Montana, Nebraska, New York, North Dakot↗

USGS2021

Machine learning can assign geologic basin to produced water samples using major ion geochemistry

Understanding the geochemistry of waters produced during petroleum extraction is essential to informing the best treatment and reuse options, which can potentially be optimized for a given geologic basin. Here, we used the US Geological Survey’s National Produced Waters Geochemical Database (PWGD) to determine if major ion chemistry could be used to classify accurately a produced water sample to a given geologic basin based on similarities to a given training dataset. Two datasets were derived from the PWGD: one with seven features but more samples (PWGD7), and another with nine features but fewer samples (PWGD9). The seven-feature dataset, prior to randomly generating a training and testing (i.e., validation) dataset, had 58,541 samples, 20 basins, and was classified based on total dissolved solids (TDS), bicarbonate (HCO 3 ), Ca, Na, Cl, Mg, and sulfate (SO 4 ). The nine-feature dataset, prior to randomly splitting into a training and testing (i.e., validation) dataset, contained 33,271 samples, 19 basins, and was classified based on TDS, HCO 3 , Ca, Na, Cl, Mg, SO 4 , pH, and specific gravity. Three supervised machine learning algorithms—Random Forest, k-Nearest Neighbors, and Naïve Bayes—were used to develop multi-class classification models to predict a basin of origin for produced waters using major ion chemistry. After training, the models were tested on three different datasets: Validation7, Validation9, and one based on data absent from the PWGD. Prediction accuracies across the models ranged from 23.5 to 73.5% when tested on the two PWGD-based datasets. A model using the Random Forest algorithm predicted most accurately compared to all other models tested. The models generally predicted basin of origin more accurately on the PWGD7-based dataset than on the PWGD9-based dataset. An additional dataset, which contained data not in the PWGD, was used to test the most accurate model; results suggest that some basins may lack geochemical diversity or may not be well described, while others may be geochemically diverse or are well described. A compelling result of this work is that a produced water basin of origin can be determined using major ions alone and, therefore, deep basinal fluid compositions may not be as variable within a given basin as previously thought. Applications include predicting the geochemistry of produced fluid prior to drilling at different intervals and assigning historical produced water data to a producing basin.

Natural Resources Research↗

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↗

USGS2021

Geochemical and geophysical indicators of oil and gas wastewater can trace potential exposure pathways following releases to surface waters

Releases of oil and gas (OG) wastewaters can have complex effects on stream-water quality and downstream organisms, due to sediment-water interactions and groundwater/surface water exchange. Previously, elevated concentrations of sodium (Na), chloride (Cl), barium (Ba), strontium (Sr), and lithium (Li), and trace hydrocarbons were determined to be key markers of OG wastewater releases when combined with Sr and radium (Ra) isotopic compositions. Here, we assessed the persistence of an OG wastewater spill in a creek in North Dakota using a combination of geochemical measurements and modeling, hydrologic analysis, and geophysical investigations. OG wastewater comprised 0.1 to 0.3% of the stream-water compositions at downstream sites in February and June 2015 but could not be quantified in 2016 and 2017. However, OG-wastewater markers persisted in sediments and pore water for 2.5 years after the spill and up to 7.2-km downstream from the spill site. Concentrations of OG wastewater constituents were highly variable depending on the hydrologic conditions. Electromagnetic measurements indicated substantially higher electrical conductivity under the bank adjacent to a seep 7.2 km downstream from the spill site. Geomorphic investigations revealed mobilization of sediment is an important contaminant transport process. Labile Ba, Ra, Sr, and ammonium (NH 4 ) concentrations extracted from sediments indicated sediments are a long-term reservoir of these constituents, both in the creek and on the floodplain. Using the drivers of ecological effects identified at this intensively studied site we identified 41 watersheds across the North Dakota landscape that may be subject to similar episodic inputs from OG wastewater spills. Effects of contaminants released to the environment during OG waste management activities remain poorly understood; however, analyses of Ra and Sr isotopic compositions, as well as trace inorganic and organic compound concentrations at these sites in pore-water provide insights into potentials for animal and human exposures well outside source-remediation zones.

North Dakota↗

USGS2020

Utica shale play oil and gas brines: Geochemistry and factors influencing wastewater management

The Utica and Marcellus Shale Plays in the Appalachian Basin are the fourth and first largest natural gas producing plays in the United States, respectively. Hydrocarbon production generates large volumes of brine (“produced water”) that must be disposed of, treated, or reused. Though Marcellus brines have been studied extensively, there are few studies from the Utica Shale Play. This study presents new brine chemical analyses from 16 Utica Shale Play wells in Ohio and Pennsylvania. Results from Na–Cl–Br systematics and stable and radiogenic isotopes suggest that the Utica Shale Play brines are likely residual pore water concentrated beyond halite saturation during the formation of the Ordovician Beekmantown evaporative sequence. The narrow range of chemistry for the Utica Shale Play produced waters (e.g., total dissolved solids = 214–283 g/L) over both time and space implies a consistent composition for disposal and reuse planning. The amount of salt produced annually from the Utica Shale Play is equivalent to 3.4% of the annual U.S. halite production. Utica Shale Play brines have radium activities 580 times the EPA maximum contaminant level and are supersaturated with respect to barite, indicating the potential for surface and aqueous radium hazards if not properly disposed of.

Kentucky, Maryland, New York, Ohio, Pennsylvania, ↗

USGS2020

Origin and geochemistry of formation waters from the lower Eagle Ford Group, Gulf Coast Basin, south central Texas

The lower Eagle Ford Group (LEFG) is one of the most productive continuous hydrocarbon plays in the United States but few associated produced waters data and minimal interpretation have been published. This effort focuses on results from compositional and isotopic data from 39 produced water samples collected from horizontal wells producing from the LEFG in south central Texas. The depth of the LEFG increases by approximately 1 km across the study area, from northwest (2.9 km) to southeast (3.9 km). Associated increases in calculated reservoir temperature (125-165 C), development of reservoir over-pressuring (400-800 bars total pressure), and increased thermal maturity (heavy oil to gas condensate) also occur along this trend. Produced water salinity starts at nearly 100 g/L in the shallowest samples and decreases linearly with depth to <35 g/L. Comparison of Br/Cl and ⁸⁷Sr/⁸⁶Sr data between LEFG produced waters and the Louann salt, suggests that halite recycling is the mechanism behind salinity greater than seawater. Decreasing salinity with depth and thermal maturity in the Gulf Coast Basin have previously been shown to be a result of release of inter-layer water during smectite to illite conversion. The produced water samples show increasing 18O and decreasing 2H with depth, which is attributed temperature-dependent isotope fractionation of O and H exchange between seawater and clays and calcite with increasing temperature. Multiple sources of data indicate that the waters in the LEFG are not connate, but rather entered the unit prior to smectite-illite conversion. Presence of allochthonous water in many major tight oil and shale gas plays in the U.S., including the LEFG, suggests there is unknown mechanism allowing for water advection into low permeability reservoirs.

Texas↗

USGS2019

Geochemical data for produced waters from conventional and unconventional oil and gas wells: Results from Colorado, USA

Geochemical data for more than 120,000 oil and natural gas wells from the major sedimentary basins in the USA are listed in the USGS National Produced Waters Geochemical Database [1]. In this summary, we report and discuss the geochemical data on produced waters obtained from published literature and the Colorado Oil and Gas Conservation Commission (COGCC) from close to 4,000 new oil and gas wells in Colorado. We emphasize geochemical data of produced waters from shale and tight reservoirs that have increased dramatically in Colorado since 2011, due to deep horizontal drilling, downhole telemetry and massive multi-stage hydraulic fracturing. These operations require large volumes of fresh water, but contamination of groundwater is the major environmental concern. Also, induced seismicity caused by water injection has been reported from several areas in Colorado, including Trinidad, Raton basin, and Greely, Denver basin. Produced water salinities in Colorado obtained from unconventional oil and gas wells are relatively low, generally less than 30,000 mg/L TDS. Produced water salinities from conventional oil and gas wells overlap those from unconventional wells, but many wells have higher salinities (up to 90,000 mg/L TDS) and different chemical compositions.

Colorado↗