Tracking the interaction between injected CO₂ and reservoir fluids using noble gas isotopes in an analogue of large-scale carbon capture and storage

Industrial scale carbon capture and storage technology relies on the secure long term storage of CO2 in the subsurface. The engineering and safety of a geological storage site is critically dependent on how and where CO2 will be stored over the lifetime of the site. Hence, there is a need to determine how injected CO2 is stored and identify how injected CO2 interacts with sub-surface fluids. Since July 2008 ∼1 Mt of CO2 has been injected into the Cranfield enhanced oil recovery (EOR) field (MS, USA), sourced from a portion of the natural CO2 produced from the nearby Jackson Dome CO2 reservoir. Monitoring and tracking of the amount of recycled CO2 shows that a portion of the injected CO2 has been retained in the reservoir. Here, we show that the noble gases (20Ne, 36Ar, 84Kr, 132Xe) that are intrinsic to the injected CO2 can be combined with CO2/3He and δ13CCO2 measurements to trace both the dissolution of the CO2 into the formation water, and the interaction of CO2 with the residual oil. Samples collected 18 months after CO2 injection commenced show that the CO2 has stripped the noble gases from the formation water. The isotopic composition of He suggests that ∼0.2%, some 7 kt, of the injected CO2 has dissolved into formation water. The CO2/3He and δ13CCO2 values imply that dissolution is occurring at pH = 5.8, consistent with the previous determinations. δ13CCO2 measurements and geochemical modelling rule out significant carbonate precipitation and we determine that the undissolved CO2 after 18 months of injection (1.5 Mt) is stored by stratigraphic or residual trapping. After 45 months of CO2 injection, the noble gas concentrations appear to be affected by CO2-oil interaction, overprinting the signature of the formation water

Inherent tracers for carbon capture and storage in sedimentary formations: composition and applications

Inherent tracers - the “natural” isotopic and trace gas composition of captured CO₂ streams – are potentially powerful tracers for use in CCS technology. This review outlines for the first time the expected carbon isotope and noble gas compositions of captured CO₂ streams from a range of feedstocks, CO₂-generating processes and carbon capture techniques. The C-isotope composition of captured CO₂ will be most strongly controlled by the feedstock, but significant isotope fractionation is possible during capture; noble gas concentrations will be controlled by the capture technique employed. Comparison with likely baseline data suggests that CO₂ generated from fossil fuel feedstocks will often have δ13C distinguishable from storage reservoir CO₂. Noble gases in amine-captured CO₂ streams are likely to be low concentration, with isotopic ratios dependant on the feedstock, but CO₂ captured from oxyfuel plants may be strongly enriched in Kr and Xe which are potentially valuable subsurface tracers. CO₂ streams derived from fossil fuels will have noble gas isotope ratios reflecting a radiogenic component that will be difficult to distinguish in the storage reservoir, but inheritance of radiogenic components will provide an easily recognisable signature in the case of any unplanned migration into shallow aquifers or to the surface

Constraining the Geochemical Fingerprints of Gases from the UK Carboniferous Coal Measures at the Glasgow Geoenergy Observatories Field Site, Scotland

Usage of thermal energy contained in abandoned, flooded, coal mines has the potential to contribute to low carbon heating or cooling supply and assist in meeting net-zero carbon emission targets. However, hazardous ground gases, such as CH4 and CO2, can be found naturally in superficial deposits, coal bearing strata and abandoned mines. Determining the presence, magnitude, and origin of subsurface gases, and how their geochemical fingerprints evolve within the shallow subsurface is vital to developing an understanding of how to manage the risk posed by ground gases in geoenergy technology development. Here, we present the first CH4 and CO2 concentration-depth profiles and stable isotope (δ13CCH4, δ13CCO2, and δDCH4) profiles obtained from UK mine workings, through analysis of headspace gas samples degassed from cores and chippings collected during construction of the Glasgow Observatory. These are used to investigate the variability of gas fingerprints with depth within unmined Carboniferous coal measures and Glasgow coal mine workings. Stable isotope compositions of CH4 (δ13CCH4 = −73.4‰ to −14.3‰; δ13CCO2 = −29‰ to −6.1‰; δDCH4 = −277‰ to −88‰) provide evidence of a biogenic source, with carbonate reduction being the primary pathway of CH4 production. Gas samples collected at depths of 63–79 m exhibit enrichments in 13CCH4 and 2H, indicating the oxidative consumption of CH4. This correlates with their proximity to the Glasgow Ell mine workings, which will have increased exposure to O2 from the atmosphere as a result of mining activities. CO2 gas is more abundant than CH4 throughout the succession in all three boreholes, exhibiting high δ13CCO2 values relative to the CH4 present. Gases from unmined bedrock exhibit the highest δ13CCO2 values, with samples from near-surface superficial deposits having the lowest δ13CCO2 values. δ13CCO2 values become progressively lower at shallower depths (above 90 m), which can be explained by the increasing influence of shallow groundwaters containing a mixture of dissolved marine carbonate minerals (∼0‰) and soil gas CO2 (−26‰) as depth decreases. Our findings provide an insight into the variability of mine derived gases within 200 m of the surface, providing an important ‘time-zero’ record of the site, which is required in the design of monitoring approaches

Multi-Isotope Geochemical Baseline Study of the Carbon Management Canada Research Institutes CCS Field Research Station (Alberta, Canada), Prior to CO2 Injection

Carbon capture and storage (CCS) is an industrial scale mitigation strategy for reducing anthropogenic CO2 from entering the atmosphere. However, for CCS to be routinely deployed, it is critical that the security of the stored CO2 can be verified and that unplanned migration from a storage site can be identified. A number of geochemical monitoring tools have been developed for this purpose, however, their effectiveness critically depends on robust geochemical baselines being established prior to CO2 injection. Here we present the first multi-well gas and groundwater characterisation of the geochemical baseline at the Carbon Management Canada Research Institutes Field Research Station. We find that all gases exhibit CO2 concentrations that are below 1%, implying that bulk gas monitoring may be an effective first step to identify CO2 migration. However, we also find that predominantly biogenic CH4 (∼90%–99%) is pervasive in both groundwater and gases within the shallow succession, which contain numerous coal seams. Hence, it is probable that any upwardly migrating CO2 could be absorbed onto the coal seams, displacing CH4. Importantly, 4He concentrations in all gas samples lie on a mixing line between the atmosphere and the elevated 4He concentration present in a hydrocarbon well sampled from a reservoir located below the Field Research Station (FRS) implying a diffusive or advective crustal flux of 4He at the site. In contrast, the measured 4He concentrations in shallow groundwaters at the site are much lower and may be explained by gas loss from the system or in situ production generated by radioactive decay of U and Th within the host rocks. Additionally, the injected CO2 is low in He, Ne and Ar concentrations, yet enriched in 84Kr and 132Xe relative to 36Ar, highlighting that inherent noble gas isotopic fingerprints could be effective as a distinct geochemical tracer of injected CO2 at the FRS

He and Ne as tracers of natural CO2 migration up a fault from a deep reservoir

Capture and geological storage of CO2 is emerging as an attractive means of economically abating anthropogenic CO2 emissions from point sources. However, for the technology to be widely deployed it is essential that a reliable means to assess a site for both storage performance and regulation compliance exists. Hence, the ability to identify the origin of any CO2 seepage measured at the near-surface and ground surface and determine if it originates from a deep storage site or a different source is critical. As an analogue for post-emplacement seepage, here we examine natural CO2 rich springs and groundwater wells in the vicinity of the St. Johns Dome CO2 reservoir located on the border of Mid-Arizona/New Mexico, USA. Extensive travertine deposits in the region document a long history of migration of CO2 rich fluids to the surface. The presence of CO2 rich fluids today are indicated by high levels of HCO3− in surface spring and groundwater well waters. We document measurements of dissolved noble gases and carbon isotopes from these springs and wells. We show that a component of the He fingerprint measured in gaseous CO2 sampled in the deep reservoir, can be traced along a fault plane to occur in waters from both groundwater wells and the majority of springs emerging at the surface above the reservoir. Our results show for the first time that CO2 can be fingerprinted from source to surface using noble gases and illustrates that this technique could be used to identify dissolved CO2 migration from engineered storage sites

Estimating geological CO2 storage security to deliver on climate mitigation

Carbon capture and storage (CCS) can help nations meet their Paris CO2 reduction commitments cost-effectively. However, lack of confidence in geologic CO2 storage security remains a barrier to CCS implementation. Here we present a numerical program that calculates CO2 storage security and leakage to the atmosphere over 10,000 years. This combines quantitative estimates of geological subsurface CO2 retention, and of surface CO2 leakage. We calculate that realistically well-regulated storage in regions with moderate well densities has a 50% probability that leakage remains below 0.0008% per year, with over 98% of the injected CO2 retained in the subsurface over 10,000 years. An unrealistic scenario, where CO2 storage is inadequately regulated, estimates that more than 78% will be retained over 10,000 years. Our modelling results suggest that geological storage of CO2 can be a secure climate change mitigation option, but we note that long-term behaviour of CO2 in the subsurface remains a key uncertainty

Quantifying geological CO2 storage security to deliver on climate mitigation

Bryan Lovell Meeting 2019 in London, 21 - 23 January 2019Carbon Capture and Storage (CCS) can help nations meet their Paris CO2 reduction commitments cost-effectively. However, lack of confidence in geologic CO2 storage security remains a barrier to CCS implementation. Leak rates of 0.01% yr-1, equivalent to 99% retention of the stored CO2 after 100 years, are referred to by many stakeholders as adequate to ensure the effectiveness of CO2 storage. Secure storage must allow global average temperature increases, driven by excess CO2, to remain well below 2°C; these timescales are typically modelled to be 10,000 years. Thus, leakage rates must remain below an average linear rate of 0.01% yr-1 for that timespan. Many studies that assess global industry-wide risk of subsurface gas leakage do not specifically consider subsurface CO2 retention mechanisms, despite experimental measurements showing that residual trapping may immobilise a significant proportion of the CO2 almost immediately on injection. The published studies that incorporate subsurface CO2 retention into their risk assessments are for site-specific, real or hypothetical, hydrogeological models, rather than industry-wide, regional, or global scenarios. Here, we present a numerical program that calculates CO2 storage security and leakage to the atmosphere over 10kyr. This links processes of geologically measured CO2 subsurface retention (residual and dissolution trapping), and CO2 leakage estimates (based on measured surface fluxes from appropriate analogues). We model 12 GtCO2 of cumulative storage based on the EU¿s 2050 target, commencing injection in 2020, and calculate CO2 retention for well-regulated onshore and offshore scenarios, and for a hypothetical onshore, poorly regulated scenario. The Storage Security Calculator (SSC) is a tool to simulate the long-term (10kyr) security of CO2 storage at a basin scale. Simulations show that CO2 storage in regions with moderate abandoned well densities and that are regulated using current best practice will retain 96% of the injected CO2 over 10,000 years in more than half of cases, with maximum leakage of 9.6% in fewer than 5% of cases. Poorly unregulated storage is less secure, but over 10,000 years, less than 27% of injected CO2 leaks in half of the simulations; up to 34% leaks in just 5% of cases. This leakage is primarily through undetected and poorly abandoned legacy wells, and could be reduced through effective leak identification and prompt remediation of leakage. Natural subsurface immobilisation means that this leakage will not continue indefinitely. Regulators can most effectively improve CO2 storage security by identifying and monitoring abandoned wells, and perform reactive remediation should they leak. Geological storage of CO2 is a secure, resilient and feasible option for climate mitigation even in overly pessimistic poorly regulated storage scenarios and thus CO2 storage can effectively contribute to meeting the Paris 2015 target

Author Correction: Noble gases confirm plume-related mantle degassing beneath Southern Africa

Correction to: Nature Communications https://doi.org/10.1038/s41467-019-12944-6, published online 5 November 2019 The original version of the Supplementary Information associated with this Article included tracked changes. The HTML has been updated to include a corrected version of the Supplementary Information without tracked changes

Solubility trapping in formation water as dominant CO2 sink in natural gas fields

Injecting CO2 into deep geological strata is proposed as a safe and economically favourable means of storing CO2 captured from industrial point sources1, 2, 3. It is difficult, however, to assess the long-term consequences of CO2 flooding in the subsurface from decadal observations of existing disposal sites1, 2. Both the site design and long-term safety modelling critically depend on how and where CO2 will be stored in the site over its lifetime2, 3, 4. Within a geological storage site, the injected CO2 can dissolve in solution or precipitate as carbonate minerals. Here we identify and quantify the principal mechanism of CO2 fluid phase removal in nine natural gas fields in North America, China and Europe, using noble gas and carbon isotope tracers. The natural gas fields investigated in our study are dominated by a CO2 phase and provide a natural analogue for assessing the geological storage of anthropogenic CO2 over millennial timescales1, 2, 5, 6. We find that in seven gas fields with siliciclastic or carbonate-dominated reservoir lithologies, dissolution in formation water at a pH of 5–5.8 is the sole major sink for CO2. In two fields with siliciclastic reservoir lithologies, some CO2 loss through precipitation as carbonate minerals cannot be ruled out, but can account for a maximum of 18 per cent of the loss of emplaced CO2. In view of our findings that geological mineral fixation is a minor CO2 trapping mechanism in natural gas fields, we suggest that long-term anthropogenic CO2 storage models in similar geological systems should focus on the potential mobility of CO2 dissolved in wate

Time zero for net zero : a coal mine baseline for decarbonising heat

Mine water geothermal energy could provide sustainable heating, cooling and storage to assist in the decarbonisation of heat and achieving Net Zero carbon emissions. However, mined environments are highly complex and we currently lack the understanding to confidently enable a widespread, cost-effective deployment of the technology. Extensive and repeated use of the mined subsurface as a thermal source/store and the optimisation of operational infrastructure encompasses a range of scientific and technical challenges that require broad partnerships to address. We present emerging results of a pioneering multidisciplinary collaboration formed around an at-scale mine water geothermal research infrastructure in Glasgow, United Kingdom. Focused on a mined, urban environment, a range of approaches have been applied to both characterise the environmental change before geothermal activities to generate “time zero” datasets, and to develop novel monitoring tools for cost-effective and environmentally-sound geothermal operations. Time zero soil chemistry, ground gas, surface water and groundwater characterisation, together with ground motion and seismic monitoring, document ongoing seasonal and temporal variability that can be considered typical of a post-industrial, urban environment underlain by abandoned, flooded coal mine workings. In addition, over 550 water, rock and gas samples collected during borehole drilling and testing underwent diverse geochemical, isotopic and microbiological analysis. Initial results indicate a connected subsurface with modern groundwater, and resolve distinctive chemical, organic carbon and stable isotope signatures from different horizons that offer promise as a basis for monitoring methods. Biogeochemical interactions of sulphur, carbon and iron, plus indications of microbially-mediated mineral oxidation/reduction reactions require further investigation for long term operation. Integration of the wide array of time zero observations and understanding of coupled subsurface processes has significant potential to inform development of efficient and resilient geothermal infrastructure and to inform the design of fit-for-purpose monitoring approaches in the quest towards meeting Net Zero targets