Denver-Julesburg Basin Research Articles

Mitigating membrane wetting in the treatment of unconventional oil and gas wastewater by membrane distillation: A comparison of pretreatment with omniphobic membrane

The treatment of unconventional oil and gas (UOG) wastewater by membrane distillation (MD) is a promising alternative to disposal via deep-well injection for UOG wastewater management. However, MD has been constrained by membrane pore wetting, which could be induced by surfactants that are commonly used in hydraulic fracturing fluids. Herein, we investigated and compared two strategies, namely pretreatment via coagulation-adsorption and the use of omniphobic membranes, for wetting mitigation in MD treatment of UOG wastewater from the Denver-Julesburg Basin, Colorado. Both strategies were able to mitigate membrane wetting, but pretreatment exhibited better treatment efficiency than the use of omniphobic membranes that was subject to significant membrane fouling. Membrane characterization using scanning electron microscopy, energy dispersive X-ray spectroscopy, and attenuated total reflectance-Fourier transform infrared spectroscopy demonstrated the effective reduction of membrane fouling and scaling after pretreatment. Further, ultrahigh pressure liquid chromatography (UHPLC) coupled with quadrupole time-of-flight mass spectrometry (LC/QToF/MS) was performed to investigate the efficacy of pretreatment in removing surfactants. Pretreatment was found to be highly efficient at removing polyethylene glycol (PEG) and polypropylene glycol (PPG) surfactant classes, which were likely responsible for membrane wetting. Our findings suggest that pretreatment could have comparable or even better effectiveness than omniphobic membranes for improving MD treatment of UOG wastewater with high wetting potential. Comparative investigations on these two wetting mitigation strategies are valuable for rational selection of appropriate strategies to promote practical applications of MD to industrial wastewater treatment. • Membrane wetting occurs in MD treatment of UOG wastewater. • Pretreatment and omniphobic membranes as wetting mitigation strategies. • Pretreatment outperforms omniphobic membranes. • Key surfactant classes removed by pretreatment are identified.

Tracer analysis in flow channel characterization and modelling of gas and CO2 injection EOR in unconventional reservoirs

A large amount of unproduced oil remains in unconventional shale reservoirs. In this paper we present the use of water and oil tracers as a key factor in flow channel characterization and in constructing a viable numerical model to forecast oil and gas recovery by depletion drive and enhancing oil recovery (EOR) by hydrocarbon gas or CO2 injection in Niobrara and Codell formations in the Denver-Julesburg (DJ) Basin. First, a dual-porosity compositional model was built based on seismic interpretation results, well logs, and core analysis. Two hydraulic fracture scenarios, (1) uniform dimensions and (2) variable dimensions, were included in the static rock frame of the numerical model. Production performance matching demonstrated that the use of variable length and height for hydraulic fractures led to a more realistic representation of the reservoir performance. On another front, injection of water and oil tracers and flowback analysis provided the means to better quantify the fracture network distribution, flow communication between wells, and hydraulic fracture performance in each well. Finally, two ‘huff-and-puff’ (injection, shut-in, production) cycles of lean gas and CO2 injection into the reservoir were modeled to assess EOR potential of cyclic gas injection. With identical gas injection rates, lean gas produced more oil than CO2; however, CO2-EOR modeling results indicated that a substantial amount of CO2 was stored in the reservoir. The net carbon stored after CO2-EOR was approximately 13% of the injected CO2 and CO2 utilization was 39,000 scf per incremental oil barrel produced which is much larger than the average CO2 utilization of about 12,000 scf per incremental oil barrel produced in conventional reservoirs. However, the produced CO2 from unconventional reservoir EOR operation can be recycled to achieve complete storage of CO2 — rendering CO2-EOR an effective means of decarbonization. Finally, transmissibility analysis of an existing major fault zone in the study area indicated that CO2 did not leak via a major fault in the study area nor via the associated nearby natural fractures in the study area.

Chemostratigraphy of Unconventional Shale Reservoirs: A Case Study of the Niobrara Formation within the Denver-Julesburg Basin

Chemostratigraphy of Unconventional Shale Reservoirs: A Case Study of the Niobrara Formation within the Denver-Julesburg Basin

Spatial distribution of atmospheric oil and natural gas volatile organic compounds in the Northern Colorado Front Range

Methane and nonmethane volatile organic compounds (VOCs) were monitored near Boulder in the Northern Colorado Front Range to investigate their spatial distribution and sources as a part of the Front Range Air Pollution and Photochemistry Experiment (FRAPPE) and the Deriving Information on Surface conditions from Column and Vertically Resolved Observations Relevant to Air Quality (DISCOVER-AQ) campaign, in summer 2014. A particular emphasis was the study of the contribution of emissions from oil and natural gas (O&NG) operations on the regional air quality. One network extended along an elevation gradient from the City of Boulder (elevation ≈1,600 m) to the University of Colorado Mountain Research Station (≈2900 m) on the eastern slopes of the Rocky Mountains. Light alkane petroleum hydrocarbons had the highest mole fraction of the VOCs that could be analyzed with the applied techniques. The longer lived VOCs ethane and propane decreased with increasing elevation, suggesting that Boulder and the surrounding plains were a source of these anthropogenic compounds. VOC diurnal time series showed a few events with elevated mole fractions at the mountain sites, which were likely the result of the upslope transport of plumes with elevated VOCs from the plains. Within the other site network, which extended into suburban East Boulder County (EBC), VOCs were monitored at 5 sites increasingly close to O&NG development in the Denver Julesburg Basin. Mean mole fractions and variability of primarily O&NG-associated VOCs (ethane, propane, butane isomers) increased by a factor of 2.4–5.2 with closer proximity to the O&NG producing region. Median mole fractions of C2–C5 n-alkanes and of imuch-butane at the EBC sites were higher than those previously reported from 28 larger urban areas in the United States. Among the VOCs that could be quantified with the gas chromatography methods, VOCs most clearly associated to O&NG-related emissions (C2–C5 alkanes) accounted for 52%–79% of the VOC hydroxyl radical reactivity (OHR). The horizontal gradient in OHR of the considered VOCs, with ≈3 times higher values at the furthest eastern sites, points toward higher chemical reactivity and ozone production potential from these ozone precursors in the eastern area of the county than within the City of Boulder.

A case study of vertical hydraulic fracture growth, stress variations with depth and shear stimulation in the Niobrara Shale and Codell Sand, Denver-Julesburg Basin, Colorado

We have carried out a geomechanical study of three wells, one each in the Niobrara A, Niobrara C, and Codell Sandstone to investigate how the state of stress and stress variations with depth affect vertical hydraulic fracture growth and shear stimulation of preexisting fractures. We determine that the higher magnitudes of measured least principal stress values in the Niobrara A and C shales are the result of viscoplastic stress relaxation. Using a density log and a vertical transverse isotropy velocity model developed to accurately locate the microseismic events, we theoretically calculated a continuous profile of the magnitude of the least principal stress with depth. This stress profile explains the apparent vertical hydraulic fracture growth as inferred from the well-constrained depths of the associated microseismic events. Finally, we determine that because of the upward propagation of hydraulic fractures from the Niobrara C to the Niobrara A, the latter formation experienced considerably more shear stimulation, which may contribute to the greater production of oil and gas from that formation.

Sequence stratigraphy of the Niobrara Formation: Implications for age-constraining tectonic events and stratigraphic complexities in the Denver-Julesburg Basin, United States

The Upper Cretaceous Niobrara Formation in the Denver-Julesburg (D-J) Basin, United States, records late Turonian–early Campanian transgressive–regressive cycles that governed the rhythmic character of pelagic and detrital sedimentation along the former carbonate ramp of the Western Interior seaway (WIS). The general stratigraphic and architectural complexity of the full Niobrara section has long been recognized; however, fine-scale subdivision of the formation from a sequence stratigraphic aspect has been lacking and is critical for basin-scale analysis. The timing and controls of significant changes in architectural and sediment-accumulation patterns have important implications for the Niobrara petroleum system. As part of this study, we present a sequence stratigraphic framework appropriate for the distal carbonate ramp of the WIS. We project published biozone mapping and radiometric ages into basin-wide well control to establish the timing of chronostratigraphic surfaces. Age-constrained isochore maps reveal a chronology of dynamic paleoseafloor morphology that is critical to understanding the stratigraphic and architectural evolution of the Niobrara. At a regional scale, thickness patterns suggest that the north-south–oriented flexural forebulge in the Sevier foreland basin had migrated eastward to the position of the future Rocky Mountains, a location coincident with the western edge of dominantly pelagic carbonate deposition in the backbulge of the WIS basin. At the D-J Basin scale, chronostratigraphic isochore maps of four third-order sequences, and their finer-scale subintervals, record two broadly distinct periods of depositional influence in the Niobrara. Between ca. 90.0 and ca. 85.7 Ma (upper Turonian–lower Santonian), relatively even deposition was dominated by a pattern of differential sediment accumulation. Systematic reversals of thicks and thins through time are indicative of compensational infilling patterns with no influence of tectonic uplifts along the seafloor. In contrast, from ca. 85.7 to ca. 81.7 Ma (lower Santonian–lower Campanian), a reorganization of earlier architecture was driven by the influence of sublinear uplifts along the trend of the emergent Transcontinental arch. As a result, sediment accumulation was dominated by patterns of draping over the long-lived paleohighs. Absolute timing of the architectural changes of the Niobrara suggests a link among Sevier thrusting events, a migrating flexural forebulge, and uplifts at reactivated basement shear zones in the distal foreland. Thus, both active tectonics and the inherited Proterozoic basement fabric of the WIS influenced the evolution of the Niobrara Formation. This example from the Cretaceous WIS shows that age-constraining sequence stratigraphy for regional isochore mapping can reveal relationships among the structural response to far-field tectonic events, oceanographic variations, and stratigraphic architecture.

Atmospheric oil and natural gas hydrocarbon trends in the Northern Colorado Front Range are notably smaller than inventory emissions reductions

From 2008 to mid-2016, there was more than a 7-fold increase in oil production and nearly a tripling of natural gas production in the Colorado Denver–Julesburg Basin (DJB). This study utilized air samples collected at the Boulder Atmospheric Observatory (BAO) tower in southwestern Weld County in the DJB to investigate atmospheric mole fraction trends of methane and volatile organic compounds (VOCs). Elevated methane and propane mole fractions and low values (<1) in the ratio of i-pentane to n-pentane at BAO were found to be associated with flow patterns that transport air from the northeast (NE) to east (E) sector to the site, the direction where the primary locations of oil and natural gas (O&NG) extraction and processing activities are located. Median mole fractions of the O&NG tracer propane at BAO were 10 times higher than background values when winds came from the NE quadrant. This contrasts with lower mole fractions of O&NG-related constituents in air parcels arriving at BAO from the south, the direction of the major urban area of Denver. None of O&NG tracers, for example, methane and propane, show statistically significant trends in mole fraction (relative to the background) over the study period in air transported from the DJB. Also, longer term acetylene mole fraction changes were not seen in NE quadrant or south sector samples. A significant decline in the mole fraction ratio of i-pentane to n-pentane in the NE sector data provides evidence of an increasing influence of O&NG on the overall composition of VOCs measured at BAO, a change not seen in measurements from the south (urban) sector. These results suggest that O&NG emissions and resulting atmospheric mole fractions have remained relatively constant over 2008–2016. The behavior in the observations is in contrast to the most recent VOC emissions inventory. While the inventory projects O&NG total VOC emission reductions between 2011 and 2020, of –6.5% per year despite the large production increases, the best estimate of the propane emission rate of change for the DJB-filtered data during 2008–2016 is much smaller, that is, –1.5% per year.

Sequence stratigraphy and regional context of the Mancos-Niobrara in the northern San Juan Basin

In the northern San Juan Basin, the Niobrara Formation is represented by the upper half of the Mancos Shale (the Smoky Hill Member and Cortez Member). This section is generally equivalent to the Niobrara Formation along the Colorado Front Range. Although the Fort Hays Limestone is absent west of Pagosa Springs, the C Chalk and B Chalk are well-expressed as two resistant bench-forming calcareous units in the northern San Juan Basin. These two calcareous units have also been established as prospective hydrocarbon targets by operators in the area. Calcareous facies equivalent to the A Chalk were not deposited in the northern San Juan Basin due to siliciclastic dilution during the regressive latter half of the Niobrara marine cycle. The overall third-order Niobrara marine cycle includes these members of the Mancos Shale: the Juana Lopez, Montezuma Valley, Smoky Hill, and Cortez members. The Smoky Hill Member sits just above the basal Niobrara unconformity in most of the study area, and the entire section also has greater thickness and siliciclastic content than its equivalent farther east along the Front Range. Several extensive outcrop locations (in and around Pagosa Springs, Piedra, and Durango, CO) along with three new cores along the CO-NM border form the foundation for sequence stratigraphic interpretation of the Niobrara marine cycle in this study. All these locations and cores were tied back to the Mancos reference section at Mesa Verde National Park established by Leckie et al. (1997) which provides detailed description and biostratigraphy for the entire Mancos Shale. Establishing and applying a sequence stratigraphic framework to any section creates consistent reference standards for communication, research, and further correlation. Comparisons of chemostratigraphic data from equivalent strata between the northern San Juan Basin and Denver-Julesburg (DJ) Basin reveal significant differences in the timing and style of source-rock deposition (and associated low-oxygen conditions). The sequence stratigraphic framework also emphasizes tremendous lateral facies changes in the basal Niobrara section (i.e., Fort Hays Limestone to Tocito Sandstone). Once refined and applied, this stratigraphic framework can be used for predicting the distribution of reservoir properties, in addition to enhancing understanding of the Niobrara marine cycle and the Western Interior Seaway.

Evaluation of sequencing batch bioreactor followed by media filtration for organic carbon and nitrogen removal in produced water

Produced water contains high concentrations of total dissolved solids (TDS), metals, and organic matter. In areas of high water stress, beneficial reuse of produced water needs to be considered. This study evaluates the treatment capabilities, efficiency, and limitations of a sequencing batch reactor (SBR) to remove organic material and nutrients from produced water. SBRs have been used to facilitate biological organic and nutrient removal from municipal and industrial waste streams. Although the bacteria responsible for the treatment of municipal and most industrial wastewaters cannot tolerate the high TDS concentrations in produced water, the microorganisms native to produced water have the capacity to treat produced water. In a bench scale bioreactor test using produced water from the Denver-Julesburg Basin, the produced water was determined to be nutrient limited with respect to phosphorus. By adding a phosphorus supplement, soluble chemical oxygen demand (COD) removal was increased by over 20 % and ammonia removal increased by approximately 40 %. Various supplements, including KH2PO4, centrate from an anaerobic digester, and activated sludge from a municipal SBR, were added to the bioreactors to determine which of them was more effective. A pilot scale SBR followed by media filtration was used to evaluate the effects of operating conditions on produced water treatment. The hydraulic residence time ranged from 1.67 to 8.3 days during various phases of operation, with no measured effect on treatment performance. Adding 7.5 mg-P/L of KH2PO4 as a phosphorus supplement had the most significant effect on treatment performance of the system. The majority of COD removal switched locations from the filter columns to the bioreactors. Comparing total organic carbon to COD, the biologically available portion of COD appears to be treated in the SBR while recalcitrant carbon and inorganic material may need to be removed via physical or chemical methods.

Evaluating oil and gas contributions to ambient nonmethane hydrocarbon mixing ratios and ozone-related metrics in the Colorado Front Range

Recently, oil and natural gas (O&NG) production activities in the Denver-Julesburg Basin have expanded rapidly. Associated nonmethane hydrocarbon (NMHC) emissions contribute to photochemical formation of ground-level ozone and include benzene as well as other hazardous air pollutants. Using positive matrix factorization (PMF) and chemical mass balance (CMB) methods, we estimate how much O&NG activities and other sources contribute to morning NMHC mixing ratios measured from 2013 to mid-2016 at a site in Platteville, CO, in the Denver-Julesburg Basin, and at a contrasting site in downtown Denver. A novel adjoint sensitivity analysis method is then used to estimate corresponding contributions to ozone and ozone-linked mortality in the Denver region. Average 6–9 am NMHC mixing ratios in Platteville were seven times higher than those in Denver in 2013 but four times higher in 2016. CMB estimates that O&NG activities contributed to the Platteville (Denver) site an average of 96% (56%) of NMHC on a carbon basis while PMF indicated 92% (33%). Average vehicle-related contributions of NMHC are estimated as 41% by CMB and 53% by PMF in Denver. Estimates of the fractional contribution to potential ozone and ozone-linked mortality from O&NG activities are smaller while those from vehicles are larger than the NMHC contributions. CMB (PMF) indicate that greater than 78% (40%) of annual average benzene in Denver is attributable to vehicle emissions while greater than 75% (67%) of benzene in Platteville is attributable to O&NG activities.

Microbial and Biogeochemical Indicators of Methane in Groundwater Aquifers of the Denver Basin, Colorado.

The presence of methane and other hydrocarbons in domestic-use groundwater aquifers poses significant environmental and human health concerns. Isotopic measurements are often relied upon as indicators of groundwater aquifer contamination with methane. While these parameters are used to infer microbial metabolisms, there is growing evidence that isotopes present an incomplete picture of subsurface microbial processes. This study examined the relationships between microbiology and chemistry in groundwater wells located in the Denver-Julesburg Basin of Colorado, a rapidly urbanizing area with active oil and gas development. A primary goal was to determine if microbial data can reliably indicate the quantities and sources of groundwater methane. Comprehensive chemical and molecular analyses were performed on 39 groundwater well samples from five aquifers. Elevated methane concentrations were found in only one aquifer, and both isotopic and microbial data support a microbial origin. Microbial parameters had similar explanatory power as chemical parameters for predicting sample methane concentrations. Furthermore, a subset of samples with unique microbiology corresponded with unique chemical signatures that may be useful indicators of methane gas migration, potentially from nearby coal seams interacting with the aquifer. Microbial data may allow for more accurate determination of groundwater contamination and improved long-term water quality monitoring compared solely to isotopic and chemical data in areas with microbial methane.

On-site treatment capacity of membrane distillation powered by waste heat or natural gas for unconventional oil and gas wastewater in the Denver-Julesburg Basin

Leveraging waste heat has been considered to have significant potential for promoting the economic feasibility of wastewater treatment in unconventional oil and gas (UOG) production. However, its availability near well sites has not been fully understood and other energy sources may be also feasible. In this work, we quantitatively investigate the viability of using waste heat and well-pad natural gas to power on-site wastewater treatment by membrane distillation (MD) for twenty randomly selected wells located in the Denver-Julesburg (DJ) Basin, U.S. Results show that waste heat produced from on-site electrical loads is insufficient for MD treatment of all the wastewater generated during UOG production (2.2–24.3% of thermal energy required for MD treatment). Waste heat from hydraulic fracturing, which persists only for a short timeframe, is able to meet the full or partial energy requirement during the peak period of wastewater production (17–1005% of thermal energy required for MD treatment within the first two months of production), but this scenario varies among wells and is dependent on the energy efficiency of MD. Compared to waste heat, natural gas is a more consistent energy source. The treatment capacity of MD powered by natural gas at the well pad exceeds full wastewater treatment demands for all the twenty wells, with only two wells requiring short-term wastewater storage. Our work indicates that although waste heat has the potential to reduce the electricity consumption and cost of UOG wastewater treatment, it is unlikely to supply sufficient thermal energy required by MD for long-term treatment. Natural gas can serve as an alternative or complementary energy resource. Further investigations, in particular techno-economic analyses, are needed to identify the best suitable energy source or combination for on-site UOG wastewater treatment.

Critical Diagenetic Features Controlling Intergranular Flow Paths and Matrix Permeability in the Codell Sandstone, Northeastern Colorado

The Codell Sandstone is a hydrocarbon-bearing, tight sand (permeability <0.1 mD) that is an active target for unconventional hydrocarbon production in the Denver-Julesburg Basin. In northeastern Colorado, the intergranular microporous drainage network within this clay-rich sandstone is poorly understood, with a strong diagenetic control suggested by the lack of correlation between permeability and depositional facies. Core samples from the Wattenberg Field and Redtail areas in Weld County were used to identify which diagenetic processes were most important in developing a connected pore network. Thirteen diagenetic features were defined using thin-section petrography and electron microprobe mineralogical phase mapping, and skeletonized flow paths were delineated by epifluorescence imaging. Quartz overgrowths, mechanical compaction, and clay cements (illite, chlorite, and kaolinite) are better developed in the laminated facies than the burrowed facies. Authigenic calcite and pyrite, and dissolution of framework grains are equally developed in both types of facies. Cumulative 2D flow-path lengths positively co-vary with permeability, indicating that the skeletonized paths capture the features that control permeability. The longest flow paths in high permeability (≥0.09 mD) samples follow micropores created along the periphery of framework grains where the discontinuous quartz overgrowths abut clays. Micropores within intergranular clay masses (detrital, pore-filling cements, and authigenic replacements) associate with shorter flow paths that dominate in low permeability (≤ 0.01 mD) samples and feed the longer paths in high permeability samples. While compaction and all types of cements had a negative impact on the original pore network, the development of long contacts between quartz overgrowths and mechanically juxtaposed grains eventually became beneficial to the drainage system. The increased surface area along those contacts increased the continuity of the flow paths developed along grain surfaces. All observations indicate that the minute quartz overgrowths, and the high authigenic rugosity they created along grain boundaries, were a key diagenetic event in creating the most efficient drainage networks that now facilitate the movement of hydrocarbons at the core-plug scale.

Understanding oil and gas pneumatic controllers in the Denver–Julesburg basin using optical gas imaging

ABSTRACTIn the spring of 2018, a 10-day field study was conducted in Colorado’s Denver-Julesburg oil and natural gas production basin to improve information on well pad pneumatic controller (PC) populations and identify PCs with potential maintenance issues (MIs) causing excess emissions through a novel optical gas imaging (OGI) survey approach. A total of 500 natural gas-emitting PCs servicing 102 wells (4.9 PCs/well) were surveyed at 31 facilities operated by seven different companies. The PCs were characterized by their designed operational function and applications, with 83% of the PC population identified as intermittent PCs (IPCs). An OGI inspection protocol was used to investigate emissions on 447 working PCs from this set. OGI detected continuous emissions from 11.3% of observed IPCs and these were classified as experiencing some level of MIs. OGI imaging modes were observed to have a significant effect on emission detectability with high sensitivity mode detection rates being approximately 2 times higher compared to auto mode. Fourteen snapshot emission measurements (not including actuations) were conducted on IPCs in this category using a high-volume sampling device with augmented quality assurance procedures with observed emissions rates ranging from 0.1 up to 31.3 scf/hr (mean = 2.8 scf/hr). For PCs with continuous depressurization type (CPC), 36.8% had continuous emissions observed by OGI. Four supporting emission measurements were conducted on CPCs with one unit exceeding the low bleed regulatory emission threshold with an emission rate of 9.9 scf/hr (mean = 4.2 scf/hr). Additional information was collected on PC actuation events, as observed with OGI, which showed a strong correlation between observed actuation events and facility production compared to observed continuous emissions caused by MIs which did not correlate with facility production.Implications: A novel survey approach of pneumatic controllers at oil and natural gas production facilities in the Denver-Julesburg basin, using optical gas imaging and supporting emission measurements, was demonstrated as an effective method to identify controllers with potential maintenance issues causing excess emissions. The results of the pneumatic controller and optical gas imaging surveys improved information on pneumatic controller populations within the basin and also demonstrated the significant effect optical gas imaging modes have on emission detections.

Air quality impacts from oil and natural gas development in Colorado

The rise of hydraulic fracturing techniques has fostered rapid growth of oil and natural gas (O&NG) extraction in areas across the United States. In the Denver-Julesburg Basin (DJB), which mostly overlaps with Weld County in the Northern Colorado Front Range (NCFR) north of the City of Denver Metropolitan Area (DMA), the well drilling has increasingly approached, and in many instances moved into urban residential areas. During the same time, the region has also experienced steady population growth. The DMA – NCFR has been in exceedance of the ozone U.S. National Ambient Air Quality Standard (NAAQS) and was designated a non-attainment area of the standard in 2007. Despite State efforts to curb precursors, ozone has consistently remained above the standard. A growing number of atmospheric studies has provided an ever increasing body of literature for assessing influences from O&NG industry emissions on air quality in the DMA-NCFR. This paper provides 1. An overview of available literature on O&NG influences on the regional air quality, 2. A summary of the pertinent findings presented in these works, 3. An assessment of the most important pollutants and air quality impacts, 4. Identification of knowledge and monitoring gaps, and 5. Recommendations for future research and policy.

Geochemical and microbial characterizations of flowback and produced water in three shale oil and gas plays in the central and western United States

Limited understanding of wastewater streams produced from shale oil and gas wells impedes best practices of wastewater treatment and reuse. This study provides a comprehensive and comparative analysis of flowback and produced water from three major and newly developed shale plays (the Bakken shale, North Dakota; the Barnett shale, Texas; and the Denver-Julesburg (DJ) basin, Colorado) in central and western United States. Geochemical features that included more than 10 water quality parameters, dissolved organic matter, as well as microbial community structures were characterized and compared. Results showed that wastewater from Bakken and Barnett shales has extremely high salinity (∼295 g/L total dissolved solids (TDS)) and low organic concentration (80–252 mg/L dissolved organic carbon (DOC)). In contrast, DJ basin showed an opposite trend with low TDS (∼30 g/L) and high organic content (644 mg/L DOC). Excitation-emission matrix (EEM) fluorescence spectra demonstrated that more humic acid and fluvic acid-like organics with higher aromaticity existed in Bakken wastewater than that in Barnett and DJ basin. Microbial communities of Bakken samples were dominated by Fe (III)-reducing bacteria Geobacter, lactic acid bacteria Lactococcus and Enterococcus, and Bradyrhizobium, while DJ basin water showed higher abundance of Rhodococcus, Thermovirga, and sulfate reducing bacteria Thermotoga and Petrotoga. All these bacteria are capable of hydrocarbon degradation. Hydrogenotrophic methanogens dominated the archaeal communities in all samples.

Degradation of polyethylene glycols and polypropylene glycols in microcosms simulating a spill of produced water in shallow groundwater.

Polyethylene glycols (PEGs) and polypropylene glycols (PPGs) are frequently used in hydraulic fracturing fluids and have been detected in water returning to the surface from hydraulically fractured oil and gas wells in multiple basins. We identified degradation pathways and kinetics for PEGs and PPGs under conditions simulating a spill of produced water to shallow groundwater. Sediment-groundwater microcosm experiments were conducted using four produced water samples from two Denver-Julesburg Basin wells at early and late production. High-resolution mass spectrometry was used to identify the formation of mono- and di-carboxylated PEGs and mono-carboxylated PPGs, which are products of PEG and PPG biodegradation, respectively. Under oxic conditions, first-order half-lives were more rapid for PEGs (<0.4-1.1 d) compared to PPGs (2.5-14 d). PEG and PPG degradation corresponded to increased relative abundance of primary alcohol dehydrogenase genes predicted from metagenome analysis of the 16S rRNA gene. Further degradation was not observed under anoxic conditions. Our results provide insight into the differences between the degradation rates and pathways of PEGs and PPGs, which may be utilized to better characterize shallow groundwater contamination following a release of produced water.

Succession of toxicity and microbiota in hydraulic fracturing flowback and produced water in the Denver–Julesburg Basin

Hydraulic fracturing flowback and produced water (FPW) samples were analyzed for toxicity and microbiome characterization over 220 days for a horizontally drilled well in the Denver-Julesberg (DJ) Basin in Colorado. Cytotoxicity, mutagenicity, and estrogenicity of FPW were measured via the BioLuminescence Inhibition Assay (BLIA), Ames II mutagenicity assay (AMES), and Yeast Estrogen Screen (YES). Raw FPW stimulated bacteria in BLIA, but were cytotoxic to yeast in YES. Filtered FPW stimulated cell growth in both BLIA and YES. Concentrating 25× by solid phase extraction (SPE) revealed significant toxicity throughout well production by BLIA, toxicity during the first 55 days of flowback by YES, and mutagenicity by AMES. The selective pressures of fracturing conditions (including toxicity) affected bacterial and archaeal communities, which were characterized by 16S rRNA gene V4V5 region sequencing. Conditions selected for thermophilic, anaerobic, halophilic bacteria and methanogenic archaea from the groundwater used for fracturing fluid, and from the native shale community. Trends in toxicity echoed the microbial community, which indicated distinct stages of early flowback water, a transition stage, and produced water. Biota in another sampled DJ Basin horizontal well resembled similarly aged samples from this well. However, microbial signatures were unique compared to samples from DJ Basin vertical wells, and wells from other basins. These data can inform treatability, reuse, and management decisions specific to the DJ Basin to minimize adverse environmental health and well production outcomes.

Assessing a low-cost methane sensor quantification system for use in complex rural and urban environments.

Low-cost sensors have the potential to facilitate the exploration of air quality issues on new temporal and spatial scales. Here we evaluate a low-cost sensor quantification system for methane through its use in two different deployments. The first was a one-month deployment along the Colorado Front Range and included sites near active oil and gas operations in the Denver-Julesberg basin. The second deployment was in an urban Los Angeles neighborhood, subject to complex mixtures of air pollution sources including oil operations. Given its role as a potent greenhouse gas, new low-cost methods for detecting and monitoring methane may aid in protecting human and environmental health. In this paper, we assess a number of linear calibration models used to convert raw sensor signals into ppm concentration values. We also examine different choices that can be made during calibration and data processing, and explore cross-sensitivities that impact this sensor type. The results illustrate the accuracy of the Figaro TGS 2600 sensor when methane is quantified from raw signals using the techniques described. The results also demonstrate the value of these tools for examining air quality trends and events on small spatial and temporal scales as well as their ability to characterize an area - highlighting their potential to provide preliminary data that can inform more targeted measurements or supplement existing monitoring networks.

Colorado Operators Reaping Rewards From Sticking by ‘Predictable’ DJ-Niobrara

Colorado oil production is surging to record levels, outpacing the other major producing US states in year-over-year gains on the backs of the steady-and-predictable Denver-Julesburg (DJ) Basin and overlapping Niobrara Shale. As overall US oil output continues to surge, attention has been drawn to the Permian Basin and SCOOP and STACK plays. Operators have flocked to West Texas, southeastern New Mexico, and central Oklahoma to stake claims to land they believe will usher them into a new, leaner era for the industry. The expansive Permian alone, which covers more than 75,000 sq miles, has accounted for the bulk of US oil production increases and mergers and acquisitions over the last couple of years. Although they are intertwined and together encompass parts of Colorado border states Wyoming, Nebraska, and Kansas, the DJ and Niobrara offer a fraction of the acreage and prospective resources of the Permian. But the existing acreage quality is high. Relatively few companies have large positions in the region, with leadership of many of those firms having earned their stripes with nearby competitors. Mike Eberhard, chief operating officer of SRC Energy, previously known as Synergy Resources and one of the region’s largest pure-play firms, explained that the DJ is attractive because “it has a very good rate of return” due mainly to low well and takeaway costs, which makes it competitive with the other major basins. He previously served as completions manager for Anadarko Petroleum’s DJ Basin program. “We have a very good infrastructure” in the region, he said. “We don’t have a lot of [midstream companies] going over the top of each other, trying to get into the next location. Most of the acreage out here is dedicated for midstream. Everybody kind of knows who has what, and we do development around that.” Meanwhile, “the service sector has been here since the ‘60s.” Denver also serves as a stable source of skilled workers, “so you’re not putting up man camps” like in the Bakken and Permian where labor costs and turnover can be high. “And we don’t make a lot of water with the wells. We don’t have a lot of disposal issues,” which are common in areas such as the Permian.