Lawson Michael

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Last Name
Lawson
First Name
Michael
ORCID
0000-0003-2743-3773

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  • Article
    Rapid microbial methanogenesis during CO2 storage in hydrocarbon reservoirs
    (Nature Research, 2021-12-22) Tyne, Rebecca L. ; Barry, Peter H. ; Lawson, Michael ; Byrne, David J. ; Warr, Oliver ; Xie, Hao ; Hillegonds, Darren ; Formolo, Michael ; Summers, Zara M. ; Skinner, Brandon ; Eiler, John M. ; Ballentine, Christopher J.
    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.
  • Article
    Noble gases in deepwater oils of the U.S. Gulf of Mexico
    (American Geophysical Union, 2018-10-10) Barry, Peter H. ; Lawson, Michael ; Meurer, William P. ; Cheng, Anran ; Ballentine, Christopher J.
    Hydrocarbon migration and emplacement processes remain underconstrained despite the vast potential economic value associated with oil and gas. Noble gases provide information about hydrocarbon generation, fluid migration pathways, reservoir conditions, and the relative volumes of oil versus water in the subsurface. Produced gas He‐Ne‐Ar‐Kr‐Xe data from two distinct oil fields in the Gulf of Mexico (Genesis and Hoover‐Diana) are used to calibrate a model that takes into account both water‐oil solubility exchange and subsequent gas cap formation. Reconstructed noble gas signatures in oils reflect simple (two‐phase) oil‐water exchange imparted during migration from the source rock to the trap, which are subsequently modified by gas cap formation at current reservoir conditions. Calculated, oil to water volume ratios (Vo/Vw) in Tertiary‐sourced oils from the Hoover‐Diana system are 2–3 times greater on average than those in the Jurassic sourced oils from the Genesis reservoirs. Higher Vo/Vw in Hoover‐Diana versus Genesis can be interpreted in two ways: either (1) the Hoover reservoir interval has 2–3 times more oil than any of the individual Genesis reservoirs, which is consistent with independent estimates of oil in place for the respective reservoirs, or (2) Genesis oils have experienced longer migration pathways than Hoover‐Diana oils and thus have interacted with more water. The ability to determine a robust Vo/Vw, despite gas cap formation and possible gas cap loss, is extremely powerful. For example, when volumetric hydrocarbon ratios are combined with independent estimates of hydrocarbon migration distance and/or formation fluid volumes, this technique has the potential to differentiate between large and small oil accumulations.