Kulongoski Justin T.

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Justin T.

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  • Article
    Occurrence and sources of radium in groundwater associated with oil fields in the southern San Joaquin Valley, California
    (American Chemical Society, 2019-08-07) McMahon, Peter B. ; Vengosh, Avner ; Davis, Tracy A. ; Landon, Matthew K. ; Tyne, Rebecca L. ; Wright, Michael T. ; Kulongoski, Justin T. ; Hunt, Andrew G. ; Barry, Peter H. ; Kondash, Andrew J. ; Wang, Zhen ; Ballentine, Christopher J.
    Geochemical data from 40 water wells were used to examine the occurrence and sources of radium (Ra) in groundwater associated with three oil fields in California (Fruitvale, Lost Hills, South Belridge). 226Ra+228Ra activities (range = 0.010–0.51 Bq/L) exceeded the 0.185 Bq/L drinking-water standard in 18% of the wells (not drinking-water wells). Radium activities were correlated with TDS concentrations (p < 0.001, ρ = 0.90, range = 145–15,900 mg/L), Mn + Fe concentrations (p < 0.001, ρ = 0.82, range = <0.005–18.5 mg/L), and pH (p < 0.001, ρ = −0.67, range = 6.2–9.2), indicating Ra in groundwater was influenced by salinity, redox, and pH. Ra-rich groundwater was mixed with up to 45% oil-field water at some locations, primarily infiltrating through unlined disposal ponds, based on Cl, Li, noble-gas, and other data. Yet 228Ra/226Ra ratios in pond-impacted groundwater (median = 3.1) differed from those in oil-field water (median = 0.51). PHREEQC mixing calculations and spatial geochemical variations suggest that the Ra in the oil-field water was removed by coprecipitation with secondary barite and adsorption on Mn–Fe precipitates in the near-pond environment. The saline, organic-rich oil-field water subsequently mobilized Ra from downgradient aquifer sediments via Ra-desorption and Mn/Fe-reduction processes. This study demonstrates that infiltration of oil-field water may leach Ra into groundwater by changing salinity and redox conditions in the subsurface rather than by mixing with a high-Ra source.
  • Article
    Noble gas signatures constrain oil-field water as the carrier phase of hydrocarbons occurring in shallow aquifers in the San Joaquin Basin, USA
    (Elsevier, 2021-08-18) Karolytė, Rūta ; Barry, Peter H. ; Hunt, Andrew G. ; Kulongoski, Justin T. ; Tyne, Rebecca L. ; Davis, Tracy A. ; Wright, Michael T. ; McMahon, Peter B. ; Ballentine, Christopher J.
    Noble gases record fluid interactions in multiphase subsurface environments through fractionation processes during fluid equilibration. Water in the presence of hydrocarbons at the subsurface acquires a distinct elemental signature due to the difference in solubility between these two fluids. We find the atmospheric noble gas signature in produced water is partially preserved after hydrocarbons production and water disposal to unlined ponds at the surface. This signature is distinct from meteoric water and can be used to trace oil-field water seepage into groundwater aquifers. We analyse groundwater (n = 30) and fluid disposal pond (n = 2) samples from areas overlying or adjacent to the Fruitvale, Lost Hills, and South Belridge Oil Fields in the San Joaquin Basin, California, USA. Methane (2.8 × 10−7 to 3 × 10−2 cm3 STP/cm3) was detected in 27 of 30 groundwater samples. Using atmospheric noble gas signatures, the presence of oil-field water was identified in 3 samples, which had equilibrated with thermogenic hydrocarbons in the reservoir. Two (of the three) samples also had a shallow microbial methane component, acquired when produced water was deposited in a disposal pond at the surface. An additional 6 samples contained benzene and toluene, indicative of interaction with oil-field water; however, the noble gas signatures of these samples are not anomalous. Based on low tritium and 14C contents (≤ 0.3 TU and 0.87–6.9 pcm, respectively), the source of oil-field water is likely deep, which could include both anthropogenic and natural processes. Incorporating noble gas analytical techniques into the groundwater monitoring programme allows us to 1) differentiate between thermogenic and microbial hydrocarbon gas sources in instances when methane isotope data are unavailable, 2) identify the carrier phase of oil-field constituents in the aquifer (gas, oil-field water, or a combination), and 3) differentiate between leakage from a surface source (disposal ponds) and from the hydrocarbon reservoir (either along natural or anthropogenic pathways such as faulty wells).
  • Article
    Groundwater residence time estimates obscured by anthropogenic carbonate
    (American Association for the Advancement of Science, 2021-04-21) Seltzer, Alan M. ; Bekaert, David V. ; Barry, Peter H. ; Durkin, Kathryn E. ; Mace, Emily K. ; Aalseth, Craig E. ; Zappala, Jake C. ; Mueller, Peter ; Jurgens, Bryant C. ; Kulongoski, Justin T.
    Groundwater is an important source of drinking and irrigation water. Dating groundwater informs its vulnerability to contamination and aids in calibrating flow models. Here, we report measurements of multiple age tracers (14C, 3H, 39Ar, and 85Kr) and parameters relevant to dissolved inorganic carbon (DIC) from 17 wells in California’s San Joaquin Valley (SJV), an agricultural region that is heavily reliant on groundwater. We find evidence for a major mid-20th century shift in groundwater DIC input from mostly closed- to mostly open-system carbonate dissolution, which we suggest is driven by input of anthropogenic carbonate soil amendments. Crucially, enhanced open-system dissolution, in which DIC equilibrates with soil CO2, fundamentally affects the initial 14C activity of recently recharged groundwater. Conventional 14C dating of deeper SJV groundwater, assuming an open system, substantially overestimates residence time and thereby underestimates susceptibility to modern contamination. Because carbonate soil amendments are ubiquitous, other groundwater-reliant agricultural regions may be similarly affected.
  • Article
    High (3)He/(4)He in central Panama reveals a distal connection to the Galápagos plume
    (National Academy of Sciences, 2021-11-23) Bekaert, David V. ; Gazel, Esteban ; Turner, Stephen ; Behn, Mark D. ; de Moor, J. Maarten ; Zahirovic, Sabin ; Manea, Vlad C. ; Hoernle, Kaj A. ; Fischer, Tobias P. ; Hammerstrom, Alexander ; Seltzer, Alan M. ; Kulongoski, Justin T. ; Patel, Bina S. ; Schrenk, Matthew O. ; Halldórsson, Saemundur ; Nakagawa, Mayuko ; Ramírez, Carlos J. ; Krantz, John A. ; Yucel, Mustafa ; Ballentine, Christopher J. ; Giovannelli, Donato ; Lloyd, Karen G. ; Barry, Peter H.
    It is well established that mantle plumes are the main conduits for upwelling geochemically enriched material from Earth's deep interior. The fashion and extent to which lateral flow processes at shallow depths may disperse enriched mantle material far (>1,000 km) from vertical plume conduits, however, remain poorly constrained. Here, we report He and C isotope data from 65 hydrothermal fluids from the southern Central America Margin (CAM) which reveal strikingly high 3He/4He (up to 8.9RA) in low-temperature (≤50 °C) geothermal springs of central Panama that are not associated with active volcanism. Following radiogenic correction, these data imply a mantle source 3He/4He >10.3RA (and potentially up to 26RA, similar to Galápagos hotspot lavas) markedly greater than the upper mantle range (8 ± 1RA). Lava geochemistry (Pb isotopes, Nb/U, and Ce/Pb) and geophysical constraints show that high 3He/4He values in central Panama are likely derived from the infiltration of a Galápagos plume–like mantle through a slab window that opened ∼8 Mya. Two potential transport mechanisms can explain the connection between the Galápagos plume and the slab window: 1) sublithospheric transport of Galápagos plume material channeled by lithosphere thinning along the Panama Fracture Zone or 2) active upwelling of Galápagos plume material blown by a “mantle wind” toward the CAM. We present a model of global mantle flow that supports the second mechanism, whereby most of the eastward transport of Galápagos plume material occurs in the shallow asthenosphere. These findings underscore the potential for lateral mantle flow to transport mantle geochemical heterogeneities thousands of kilometers away from plume conduits.
  • Article
    Investigating the effect of enhanced oil recovery on the noble gas signature of casing gases and produced waters from selected California oil fields
    (Elsevier, 2021-09-25) Tyne, Rebecca L. ; Barry, Peter H. ; Karolytė, Rūta ; Byrne, David J. ; Kulongoski, Justin T. ; Hillegonds, Darren ; Ballentine, Christopher J.
    In regions where water resources are scarce and in high demand, it is important to safeguard against contamination of groundwater aquifers by oil-field fluids (water, gas, oil). In this context, the geochemical characterisation of these fluids is critical so that anthropogenic contaminants can be readily identified. The first step is characterising pre-development geochemical fluid signatures (i.e., those unmodified by hydrocarbon resource development) and understanding how these signatures may have been perturbed by resource production, particularly in the context of enhanced oil recovery (EOR) techniques. Here, we present noble gas isotope data in fluids produced from oil wells in several water-stressed regions in California, USA, where EOR is prevalent. In oil-field systems, only casing gases are typically collected and measured for their noble gas compositions, even when oil and/or water phases are present, due to the relative ease of gas analyses. However, this approach relies on a number of assumptions (e.g., equilibrium between phases, water-to-oil ratio (WOR) and gas-to-oil ratio (GOR) in order to reconstruct the multiphase subsurface compositions. Here, we adopt a novel, more rigorous approach, and measure noble gases in both casing gas and produced fluid (oil-water-gas mixtures) samples from the Lost Hills, Fruitvale, North and South Belridge (San Joaquin Basin, SJB) and Orcutt (Santa Maria Basin) Oil Fields. Using this method, we are able to fully characterise the distribution of noble gases within a multiphase hydrocarbon system. We find that measured concentrations in the casing gases agree with those in the gas phase in the produced fluids and thus the two sample types can be used essentially interchangeably. EOR signatures can readily be identified by their distinct air-derived noble gas elemental ratios (e.g., 20Ne/36Ar), which are elevated compared to pre-development oil-field fluids, and conspicuously trend towards air values with respect to elemental ratios and overall concentrations. We reconstruct reservoir 20Ne/36Ar values using both casing gas and produced fluids and show that noble gas ratios in the reservoir are strongly correlated (r2 = 0.88–0.98) to the amount of water injected within ~500 m of a well. We suggest that the 20Ne/36Ar increase resulting from injection is sensitive to the volume of fluid interacting with the injectate, the effective water-to-oil ratio, and the composition of the injectate. Defining both the pre-development and injection-modified hydrocarbon reservoir compositions are crucial for distinguishing the sources of hydrocarbons observed in proximal groundwaters, and for quantifying the transport mechanisms controlling this occurrence.
  • Article
    A novel method for the extraction, purification, and characterization of noble gases in produced fluids
    (Wiley, 2019-10-14) Tyne, Rebecca L. ; Barry, Peter H. ; Hillegonds, Darren ; Hunt, Andrew G. ; Kulongoski, Justin T. ; Stephens, Michael J. ; Byrne, David J. ; Ballentine, Christopher J.
    Hydrocarbon systems with declining or viscous oil production are often stimulated using enhanced oil recovery (EOR) techniques, such as the injection of water, steam, and CO2, in order to increase oil and gas production. As EOR and other methods of enhancing production such as hydraulic fracturing have become more prevalent, environmental concerns about the impact of both new and historical hydrocarbon production on overlying shallow aquifers have increased. Noble gas isotopes are powerful tracers of subsurface fluid provenance and can be used to understand the impact of EOR on hydrocarbon systems and potentially overlying aquifers. In oil systems, produced fluids can consist of a mixture of oil, water and gas. Noble gases are typically measured in the gas phase; however, it is not always possible to collect gases and therefore produced fluids (which are water, oil, and gas mixtures) must be analyzed. We outline a new technique to separate and analyze noble gases in multiphase hydrocarbon‐associated fluid samples. An offline double capillary method has been developed to quantitatively isolate noble gases into a transfer vessel, while effectively removing all water, oil, and less volatile hydrocarbons. The gases are then cleaned and analyzed using standard techniques. Air‐saturated water reference materials (n = 24) were analyzed and results show a method reproducibility of 2.9% for 4He, 3.8% for 20Ne, 4.5% for 36Ar, 5 .3% for 84Kr, and 5.7% for 132Xe. This new technique was used to measure the noble gas isotopic compositions in six produced fluid samples from the Fruitvale Oil Field, Bakersfield, California.