Description: Highlights • Inherent & added tracers were tested for CO2 leakage attribution & quantification. • Additionally, CO2 leakage was quantified directly by the inverted funnel-technique. • All tracers except 18O were capable of attributing the CO2 source. • In total, ∼43 % of total injected CO2 leaked across the seabed. To inform cost-effective monitoring of offshore geological storage of carbon dioxide (CO2), a unique field experiment, designed to simulate leakage of CO2 from a sub-seafloor storage reservoir, was carried out in the central North Sea. A total of 675 kg of CO2 were released into the shallow sediments (∼3 m below seafloor) for 11 days at flow rates between 6 and 143 kg d-1. A set of natural, inherent tracers (13C, 18O) of injected CO2 and added, non-toxic tracer gases (octafluoropropane, sulfur hexafluoride, krypton, methane) were used to test their applicability for CO2 leakage attribution and quantification in the marine environment. All tracers except 18O were capable of attributing the CO2 source. Tracer analyses indicate that CO2 dissolution in sediment pore waters ranged from 35 % at the lowest injection rate to 41% at the highest injection rate. Direct measurements of gas released from the sediment into the water column suggest that 22 % to 48 % of the injected CO2 exited the seafloor at, respectively, the lowest and the highest injection rate. The remainder of injected CO2 accumulated in gas pockets in the sediment. The methodologies can be used to rapidly confirm the source of leaking CO2 once seabed samples are retrieved.

Description: Author Posting. © American Geophysical Union, 2019. This article is posted here by permission of American Geophysical Union for personal use, not for redistribution. The definitive version was published in Geochemistry, Geophysics, Geosystems XX (2019): Tyne, R. L., Barry, P. H., Hillegonds, D. J., Hunt, A. G., Kulongoski, J. T., Stephens, M. J., Byrne, D. J., & Ballentine, C. J. A novel method for the extraction, purification, and characterization of noble gases in produced fluids. Geochemistry Geophysics Geosystems, 20, (2019): 5588-5597, doi: 10.1029/2019GC008552.

Description: 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.

Description: This work was supported by a Natural Environment Research Council studentship to R. L. Tyne (grant NE/L002612/1) and the USGS (grant 15‐080‐250), as part of the California State Water Resource Control Board's, Oil and Gas Regional Groundwater Monitoring Program (RMP). Data can be accessed in Tables 1 and 2 and in the data release from Gannon et al. (2018). We thank the owners and operators at the Fruitvale Oil Field for access to wells. We thank Stuart Gilfillan and an anonymous reviewer for their constructive reviews as well as Marie Edmonds for editorial handling. We also thank Matthew Landon and Myles Moor from the USGS who provided helpful comments on an earlier version of the manuscript. Any use of trade, firm or product names are for descriptive purposes only and do not imply endorsement by the U.S. Government.

Description: 2020-04-14

Description: © The Author(s), 2022. This article is distributed under the terms of the Creative Commons Attribution License. The definitive version was published in Tyne, R., Barry, P., Cheng, A., Hillegonds, D., Kim, J.-H., McIntosh, J., & Ballentine, C. Basin architecture controls on the chemical evolution and 4He distribution of groundwater in the Paradox Basin. Earth and Planetary Science Letters, 589, (2022):117580, https://doi.org/10.1016/j.epsl.2022.117580.

Description: Fluids such as 4He, H2, CO2 and hydrocarbons accumulate within Earth's crust. Crustal reservoirs also have potential to store anthropogenic waste (e.g., CO2, spent nuclear fuel). Understanding fluid migration and how this is impacted by basin stratigraphy and evolution is key to exploiting fluid accumulations and identifying viable storage sites. Noble gases are powerful tracers of fluid migration and chemical evolution, as they are inert and only fractionate by physical processes. The distribution of 4He, in particular, is an important tool for understanding diffusion within basins and for groundwater dating. Here, we report noble gas isotope and abundance data from 36 wells across the Paradox Basin, Colorado Plateau, USA, which has abundant hydrocarbon, 4He and CO2 accumulations. Both groundwater and hydrocarbon samples were collected from 7 stratigraphic units, including within, above and below the Paradox Formation (P.Fm) evaporites. Air-corrected helium isotope ratios (0.0046 - 0.127 RA) are consistent with radiogenic overprinting of predominantly groundwater-derived noble gases. The highest radiogenic noble gas concentrations are found in formations below the P.Fm. Atmosphere-derived noble gas signatures are consistent with meteoric recharge and multi-phase interactions both above and below the P.Fm, with greater groundwater-gas interactions in the shallower formations. Vertical diffusion models, used to reconstruct observed groundwater helium concentrations, show the P.Fm evaporite layer to be effectively impermeable to helium diffusion and a regional barrier for mobile elements but, similar to other basins, a basement 4He flux is required to accumulate the 4He concentrations observed beneath the P.Fm. The verification that evaporites are regionally impermeable to diffusion, of even the most diffusive elements, is important for sub-salt helium and hydrogen exploration and storage, and a critical parameter in determining 4He-derived mean groundwater ages. This is critical to understanding the role of basin stratigraphy and deformation on fluid flow and gas accumulation.

Description: This work was supported by a Natural Environment Research Council studentship to R.L. Tyne (Grant ref. NE/L002612/1). We gratefully acknowledge the William F. Keck Foundation for support of this research, and the National Science Foundation (NSF EAR #2120733). J.C. McIntosh and C.J. Ballentine are fellows of the CIFAR Earth4D Subsurface Science and Exploration Program. The authors would like to acknowledge the U.S. Bureau of Reclamation, Paradox Resources, Navajo Petroleum, US Oil and Gas INC, Anson Resources, Lantz Indergard (Lisbon Valley Mining Co.), Ambria Dell'Oro and Mohammad Marza for help with sampling.

Description: © The Author(s), 2021. This article is distributed under the terms of the Creative Commons Attribution License. The definitive version was published in Tyne, R. L., Barry, P. H., Lawson, M., Byrne, D. J., Warr, O., Xie, H., Hillegonds, D. J., Formolo, M., Summers, Z. M., Skinner, B., Eiler, J. M., & Ballentine, C. J. Rapid microbial methanogenesis during CO2 storage in hydrocarbon reservoirs. Nature, 600(7890), (2021): 670-674, https://doi.org/10.1038/s41586-021-04153-3.

Description: Carbon capture and storage (CCS) is a key technology to mitigate the environmental impact of carbon dioxide (CO2) emissions. An understanding of the potential trapping and storage mechanisms is required to provide confidence in safe and secure CO2 geological sequestration1,2. Depleted hydrocarbon reservoirs have substantial CO2 storage potential1,3, and numerous hydrocarbon reservoirs have undergone CO2 injection as a means of enhanced oil recovery (CO2-EOR), providing an opportunity to evaluate the (bio)geochemical behaviour of injected carbon. Here we present noble gas, stable isotope, clumped isotope and gene-sequencing analyses from a CO2-EOR project in the Olla Field (Louisiana, USA). We show that microbial methanogenesis converted as much as 13–19% of the injected CO2 to methane (CH4) and up to an additional 74% of CO2 was dissolved in the groundwater. We calculate an in situ microbial methanogenesis rate from within a natural system of 73–109 millimoles of CH4 per cubic metre (standard temperature and pressure) per year for the Olla Field. Similar geochemical trends in both injected and natural CO2 fields suggest that microbial methanogenesis may be an important subsurface sink of CO2 globally. For CO2 sequestration sites within the environmental window for microbial methanogenesis, conversion to CH4 should be considered in site selection.

Description: R.L.T. was supported by a Natural Environment Research Council studentship (grant reference NE/L002612/1). C.J.B. and P.H.B. acknowledge A. Regberg and B. Meurer for their support of the project and help with sample collection. C.J.B. was part supported by an Earth4D CIFAR fellowship. P.H.B. was supported by NSF awards 1923915 and 2015789. O.W. was supported by Natural Sciences and Engineering Research Council of Canada Discovery and Accelerator grants awarded to the Sherwood Lollar research group and acknowledges B. Sherwood Lollar’s support for the project. Z.M.S. acknowledges J. Biddle and G. Christman for their help in generating the microbial data.

Description: © The Author(s), 2021. This article is distributed under the terms of the Creative Commons Attribution License. The definitive version was published in Tyne, R. L., Barry, P. H., Karolyte, R., Byrne, D. J., Kulongoski, J. T., Hillegonds, D. J., & Ballentine, C. J. Investigating the effect of enhanced oil recovery on the noble gas signature of casing gases and produced waters from selected California oil fields. Chemical Geology, 584, (2021): 120540. https://doi.org/10.1016/j.chemgeo.2021.120540.

Description: 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.

Description: This work was supported by a Natural Environment Research Council studentship to R.L.Tyne (Grant ref. NE/L002612/1) and the U.S. Geological Survey (Grant ref. 15-080-250), as part of the California State Water Resource Control Board's Oil and Gas Regional Groundwater Monitoring Program (RMP).