Tracing injected CO 2 in the Cranfield enhanced oil recovery field (MS, USA) using He, Ne and Ar isotopes

Gyӧre, Domokos; Stuart, Finlay M.; Gilfillan, Stuart; Waldron, Susan

doi:10.1016/j.ijggc.2015.09.009

Cited by 65 publications

(58 citation statements)

References 43 publications

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“…Noble gases (He, Ne, Ar, Kr and Xe) exist in trace amounts in geological environments and they can be used as tracers within natural CO 2 reservoirs (Gilfillan et al, 2008;Gilfillan et al, 2009;Zhou et al, 2012;Sathaye et al, 2014) and for CO 2 used in EOR projects (Nimz and Hudson, 2005;Györe et al, 2015;Györe et al, 2017). As such, small amounts of noble gas blends can also be intentionally added to the CO 2 being injected for storage or be measured in the captured CO 2 stream and used as tracers to monitor CO 2 movement (Hovorka et al, 2013;Flude et al, 2016;Flude et al, 2017).…”

Section: Introductionmentioning

confidence: 99%

Experimental determination of noble gases and SF6, as tracers of CO2 flow through porous sandstone

et al. 2018

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A B S T R A C TIn order to label the CO 2 injected underground for geological storage and allow it to be differentiated from natural sources, a panoply of additive chemical tracers have been proposed. Yet, the transport of these tracers relative to CO 2 in pore space is currently poorly constrained. This leads to uncertainty as to whether tracers will act as an early warning of CO 2 arrival, or be preferentially retained in the pore space making them ineffective. Here, we present the factors affecting transport of noble gases and SF 6 relative to CO 2 in a porous rock. Using a porous sandstone core, each of the tracers were loaded into a sample loop and injected as discrete gas pulses into a CO 2 carrier stream at five different experiment pressures (10-50 kPag upstream to ambient pressure downstream). Tracer arrival profiles were measured using a quadrupole mass spectrometer. Significantly, our results show that peak arrival times of helium were slower than the other noble gases at each pressure gradient. The differences in peak arrival times between helium and other noble gases increased as the pressure gradient along the system decreased and the curve profiles for each noble gas differ significantly. The heavier noble gases (Kr and Xe) along with SF 6 show an earlier arrival time and a wider curve profile compared to He and Ne curves through the CO 2 carrier gas stream. This shows that Kr and Xe could be substituted for SF 6 , a potent greenhouse gas, in tracer applications. For comparison, CO 2 pulses were passed through a N 2 carrier gas resulting in significantly slower peak arrival times compared to those of noble gases and SF 6 . Hence, all investigated tracers when co-injected with CO 2 could potentially act as early warning tracers of CO 2 arrival, though we find that Kr, Xe and SF 6 will provide the most robust advance warning. Analysis of our experimental results shows that they cannot be explained by a simple one dimensional flow model through a porous medium. We outline a conceptual model that incorporates different preferential flow paths depending on flow velocities of individual gas streams. This model can explain the observed dataset and shows that the flow of noble gases and SF 6 tracers is influenced by pore-scale heterogeneity.

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Section: Introductionmentioning

confidence: 99%

Experimental determination of noble gases and SF6, as tracers of CO2 flow through porous sandstone

et al. 2018

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“…Consequently, the neon measurements did not rule out a contribution of mantle 20 Ne ( 20 Ne/ 22 Ne = 13.8). However, neon 21 Ne/ 22 Ne ratios were similar to the atmospheric values and therefore do not indicate the addition of crustal 21 Ne.…”

Section: Noble Gasesmentioning

confidence: 60%

“…The path of CO 2 transport from its source to Bravo Dome was interpreted from CO 2 and noble gas (He, Ne, Ar, Kr, and Xe) isotopic ratios . Noble gases measured from producing wells at a CO 2 ‐EOR field identified dissolution of injected CO 2 into formation water . Methane exsolution after CO 2 ‐water interaction has been investigated for natural gas recovery and tracing injected CO 2 .…”

Section: Fluid Migration and Evolutionmentioning

confidence: 99%

“…20 Noble gases measured from producing wells at a CO 2 -EOR field identified dissolution of injected CO 2 into formation water. 21 Methane exsolution after CO 2 -water interaction has been investigated for natural gas recovery 22 and tracing injected CO 2 . 23 Gilfillan et al 24 studied vertical transport of CO 2 and noble gases in natural springs, but only in the dissolved phase.…”

Section: Fluid Migration and Evolutionmentioning

confidence: 99%

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Light hydrocarbon and noble gas migration as an analogue for potential CO₂ leakage: numerical simulations and field data from three hydrocarbon systems

Anderson¹,

Alfi²,

Hovorka

2019

Greenhouse Gases

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Sites where anthropogenic CO2 captured from industrial sources is stored in deep geological formations for climate change mitigation are required to show secure retention of the injected CO2. Monitoring, reporting, and verification (MRV) plans are needed to indicate that no CO2 release has occurred. We explored the degree to which direct comparison between a surface anomaly and reservoir geochemistry using various geochemical parameters can be used for attribution. We used data collected on light hydrocarbons and noble gases throughout the sedimentary column at three CO2 enhanced oil recovery (EOR) sites to understand the processes that may cause fluid evolution. Light hydrocarbon and noble gases were sampled from reservoirs, gas‐bearing intervals above reservoirs, and groundwater. Vertical profiles indicated that lighter components are relatively enriched during migration (i.e. chromatographic separation). Static and numerical models were designed to simulate episodic gas migration and geochemical alteration of these geochemical parameters from solubility and sorption. The effects of hydrocarbon solubility were minimal (Bernard ratio changes within 5.2%) although field data were within the range of expected alterations from sorption. Forward models of CO2 migration and noble gas interactions showed that CO2 stripping causes an enrichment of crustal noble gases. In areas where natural fluxes of CO2 from depth are non‐existent, the occurrence of crustal noble gas signature may distinguish fugitive CO2 from the reservoir from natural near‐surface sources, and could be considered to explain apparent fluid anomalies. © 2019 Society of Chemical Industry and John Wiley & Sons, Ltd.

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“…Temperature difference between the injected CO 2 and the reservoir could be several tens of degrees in centigrade. For example, at Cranfield, the reservoir temperature was 125°C, while the CO 2 injection temperature was 35°C . The significant cooling may lead to a large thermal stress in the storage formations, which, combined with the injection pressure, may create small thermal fractures in the formation.…”

Section: Resultsmentioning

confidence: 99%

Effects of variable injection rate on reservoir responses and implications for CO₂ storage in saline aquifers

Maggi

Zhang

et al. 2019

Greenhouse Gases

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Past reservoir simulations of carbon dioxide (CO2) storage in saline aquifers have shown that the injection procedure can influence CO2 storage efficiency and injectivity. To investigate the influence of injection rate and timing on reservoir dynamics and storage performance, scenarios of continuous and intermittent injections were devised for storing 1 million tonnes of CO2 per year for 30 years and were assessed through numerical simulations on saline aquifers constructed with real field data. Our results show that almost all the intermittent injections need higher injection pressure than the constant injection for the same targeted amount of CO2. Only one intermittent injection showed the potential to have a lower injection pressure than the constant injection. The injectivity for the constant injection consistently declines over the years, while the intermittent injections result in an injectivity above a reference value for some years, with the number of years that maintain the injectivity linearly increasing with the length of the injection break. The injectivity for an intermittent injection peaks a few years later after the injection starts. Intermittent injections improve the residual and solubility trapping by up to 15% only in the first few years of injection, but the differences in trapping efficiencies among all the injections are within a few percent in the long term. Therefore, the intermittent injections would be useful for a CO2 storage project to make the best use of a reservoir in 5–10 years under the injection pressure restrictions. © 2019 Society of Chemical Industry and John Wiley & Sons, Ltd.

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Tracing injected CO 2 in the Cranfield enhanced oil recovery field (MS, USA) using He, Ne and Ar isotopes

Cited by 65 publications

References 43 publications

Experimental determination of noble gases and SF6, as tracers of CO2 flow through porous sandstone

Experimental determination of noble gases and SF6, as tracers of CO2 flow through porous sandstone

Light hydrocarbon and noble gas migration as an analogue for potential CO₂ leakage: numerical simulations and field data from three hydrocarbon systems

Effects of variable injection rate on reservoir responses and implications for CO₂ storage in saline aquifers

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Tracing injected CO 2 in the Cranfield enhanced oil recovery field (MS, USA) using He, Ne and Ar isotopes

Cited by 65 publications

References 43 publications

Experimental determination of noble gases and SF6, as tracers of CO2 flow through porous sandstone

Experimental determination of noble gases and SF6, as tracers of CO2 flow through porous sandstone

Light hydrocarbon and noble gas migration as an analogue for potential CO2 leakage: numerical simulations and field data from three hydrocarbon systems

Effects of variable injection rate on reservoir responses and implications for CO2 storage in saline aquifers

Contact Info

Product

Resources

About

Light hydrocarbon and noble gas migration as an analogue for potential CO₂ leakage: numerical simulations and field data from three hydrocarbon systems

Effects of variable injection rate on reservoir responses and implications for CO₂ storage in saline aquifers