Modelling carbon dioxide accumulation at Sleipner: Implications for underground carbon storage

Bickle, M. J.; Chadwick, Andy; Huppert, Herbert E.; Hallworth, Mark A.; Lyle, Sarah

doi:10.1016/j.epsl.2006.12.013

Cited by 223 publications

(171 citation statements)

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“…Further downstream, the flows have been observed to form more elongated shapes (Bickle et al 2007;Vasco et al 2010;Boait et al 2012). Using the satellite interferometric and seismic data provided by Vasco et al (2010) and Boait et al (2012) as reference, we infer that the horizontal extents of the largest CO 2 currents at In Salah and Sleipner are both characterized by W ≈ 1 km.…”

Section: Geophysical Discussionmentioning

confidence: 99%

“…The injection of CO 2 at both sites is achieved through an effective point source at an injection well, near which the flow can be approximated as axisymmetric (Lyle et al 2005;Nordbotten & Celia 2006;Bickle et al 2007). Further downstream, the flows have been observed to form more elongated shapes (Bickle et al 2007;Vasco et al 2010;Boait et al 2012).…”

Section: Geophysical Discussionmentioning

confidence: 99%

“…The Sleipner test site consists of a sandstone aquifer with an approximate total thickness of 200 m partitioned into several interstitial porous layers, of characteristic thickness H ≈ 20 m, by a series of relatively thin and impermeable mudstone boundaries (Bickle et al 2007;Boait et al 2012). Representative values for the porosity φ ≈ 0.35, permeability k ≈ 10 −12 m 2 , viscosity of carbon dioxide µ ≈ 6 × 10 −5 Pa s, viscosity of brine µ ≈ 7 × 10 −4 Pa s, density of carbon dioxide ρ ≈ 700 kg m −3 , density of brine ρ a ≈ 1000 kg m −3 and mean volumetric flux of injection Q ≈ 0.04 m 3 s −1 have been documented (Boait et al 2012).…”

Section: Geophysical Discussionmentioning

confidence: 99%

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Fluid injection into a confined porous layer

2014

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We present a theoretical and experimental study of viscous flows injected into a porous medium that is confined vertically by horizontal impermeable boundaries and filled with an ambient fluid of different density and viscosity. General three-dimensional equations describing such flows are developed, showing that the dynamics can be affected by two separate contributions: spreading due to gradients in hydrostatic pressure, and that due to the pressure drop introduced by the injection. In the illustrative case of a two-dimensional injection of fluid at a constant volumetric rate, the injected fluid initially forms a viscous gravity current insensitive both to the depth of the medium and to the viscosity of the ambient fluid. Beyond a characteristic time scale, the dynamics transition to being dominated by the injection pressure, and the injected fluid eventually intersects the second boundary to form a second moving contact line. Three different late-time asymptotic regimes can emerge, depending on whether the viscosity of the injected fluid is less than, equal to or greater than that of the ambient fluid. With a less viscous injection, the flow undergoes a slow decay towards a similarity solution in which the two contact lines extend linearly in time with differing prefactors. Perturbations from this long-term state are shown to decay algebraically with time. Equal viscosities result in both contact lines approaching the same leading-order asymptotic position but with a first-order correction to the distance between them that expands as t 1/2 due to gravitational spreading. For a more viscous injection, the distance between the contact lines approaches a constant value, with perturbations decaying exponentially. Data from a new series of laboratory experiments confirm these theoretical predictions.

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Section: Geophysical Discussionmentioning

confidence: 99%

Section: Geophysical Discussionmentioning

confidence: 99%

Section: Geophysical Discussionmentioning

confidence: 99%

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Fluid injection into a confined porous layer

2014

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“…This storage unit is overlain by about 900 meters of competent low permeability caprock and a further 900 meter thick surface layer. The research in the area of geologic sequestration of carbon dioxide has largely focused on either the consideration of fluid dynamics or the geochemical influences of the carbon dioxide injection process [Bickle et al, 2007] and the developments are continually being extended to include hydro-geomechanics aspects of the sequestration process [Rutqvist et al, 2007[Rutqvist et al, , 2008b.…”

Section: Introductionmentioning

confidence: 99%

Heave of a surficial rock layer due to pressures generated by injected fluids

Selvadurai

2009

Geophysical Research Letters

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[1] This paper examines the problem of heave developed in a surface or caprock layer of a storage formation due to the injection of pressurized fluids at depth. The problem is of interest to the deep geologic disposal of hazardous wastes and the geologic sequestration of carbon dioxide by injection. The paper develops a mathematical model that assumes elastic behavior of the storage medium while the surface rock layer is modeled as a thin plate. Elastic solutions are developed for the axisymmetric flexure deflections of the surface layer during internal pressurization over a flat circular region. The model provides a convenient tool for the preliminary estimation of the influence of injection pressures on the integrity of surface rock layers. Citation: Selvadurai, A. P. S. (2009), Heave of a surficial rock layer due to pressures generated by injected fluids, Geophys. Res. Lett., 36, L14302,

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“…To develop the geologic storage supply curve, we first consider how much CO 2 can be trapped in the pore space of an aquifer. Trapping is essential to prevent upward leakage of the buoyant CO 2 to shallower formations or the surface (17,18). Although trapping can be analyzed over a wide range of length scales, we consider trapping at the large scale of an entire geologic basin because large volumes of CO 2 will need to be stored to offset emissions (3).…”

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confidence: 99%

Lifetime of carbon capture and storage as a climate-change mitigation technology

Szulczewski

MacMinn²,

Herzog³

et al. 2012

Proc. Natl. Acad. Sci. U.S.A.

436

314

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In carbon capture and storage (CCS), CO 2 is captured at power plants and then injected underground into reservoirs like deep saline aquifers for long-term storage. While CCS may be critical for the continued use of fossil fuels in a carbon-constrained world, the deployment of CCS has been hindered by uncertainty in geologic storage capacities and sustainable injection rates, which has contributed to the absence of concerted government policy. Here, we clarify the potential of CCS to mitigate emissions in the United States by developing a storage-capacity supply curve that, unlike current large-scale capacity estimates, is derived from the fluid mechanics of CO 2 injection and trapping and incorporates injection-rate constraints. We show that storage supply is a dynamic quantity that grows with the duration of CCS, and we interpret the lifetime of CCS as the time for which the storage supply curve exceeds the storage demand curve from CO 2 production. We show that in the United States, if CO 2 production from power generation continues to rise at recent rates, then CCS can store enough CO 2 to stabilize emissions at current levels for at least 100 y. This result suggests that the large-scale implementation of CCS is a geologically viable climate-change mitigation option in the United States over the next century.carbon sequestration | pressure dissipation | residual trapping | solubility trapping C arbon dioxide is a well-documented greenhouse gas, and a growing body of evidence indicates that anthropogenic CO 2 emissions are a major contributor to climate change (1). One promising technology to mitigate CO 2 emissions is carbon capture and storage (CCS) (2-4). In the context of this study, CCS involves capturing CO 2 from the flue gas of power plants, compressing it into a supercritical fluid, and then injecting it into deep saline aquifers for long-term storage (4, 5). Compared with other mitigation technologies such as renewable energy, CCS is important because it may enable the continued use of fossil fuels, which currently supply >80% of the primary power for the planet (6, 7). We focus on CO 2 produced by power plants because electric power generation currently accounts for >40% of worldwide CO 2 emissions (8) and because power plants are large, stationary point sources of emissions where CO 2 capture technology will likely be deployed first (4). We further restrict our analysis to coal-and gas-fired power plants because they emit more CO 2 than any other type of plant: Since 2000, they have emitted ∼97% by mass of the total CO 2 produced by electricitygenerating power plants in the United States (9). We focus on storing this CO 2 in deep saline aquifers because they are geographically widespread and their storage capacity is potentially very large (4, 5).We define the storage capacity of a saline aquifer to be the maximum amount of CO 2 that could be injected and securely stored under geologic constraints, such as the aquifer's size and the integrity of its caprock. Regulatory, legal, and economic factors...

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Modelling carbon dioxide accumulation at Sleipner: Implications for underground carbon storage

Cited by 223 publications

References 13 publications

Fluid injection into a confined porous layer

Fluid injection into a confined porous layer

Heave of a surficial rock layer due to pressures generated by injected fluids

Lifetime of carbon capture and storage as a climate-change mitigation technology

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