Research project on CO2 geological storage and groundwaterresources: Large-scale hydrological evaluation and modeling of impact ongroundwater systems

Birkhölzer, Jens; Zhou, Quanlin; Rutqvist, Jonny; Jordan, Preston D.; Zhang, Keni; Tsang, Chin‐Fu

doi:10.2172/932564

Cited by 14 publications

(7 citation statements)

References 20 publications

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“…The regional‐scale variability in rock porosity and permeability in Mt. Simon, analyzed using data from natural gas storage fields and large‐scale aquifer tests, exhibits a trend of decreasing porosity and permeability from north to south (i.e., from shallower to deeper portions of the formation), possible because of overburden and consolidation (Birkholzer et al 2008). The depth‐averaged porosity and permeability values vary from 0.18 and several hundred mD in northern Illinois to less than 0.10 and several tens of mD in central Illinois.…”

Section: Site Description Of the Illinois Basinmentioning

confidence: 99%

“…The calculated pore compressibility (β p ) of the Mt. Simon Sandstone is 3.71 × 10 −10 Pa −1 in deeper areas of central Illinois and 6.0 × 10 −10 Pa −1 in shallower areas of southeastern Wisconsin (Birkholzer et al 2008). These calculated values of large‐scale pore compressibility are within the range of pore compressibility reported for well‐consolidated sandstones (Yale et al 1993, Figure 3) at in situ effective stresses representative of Mt.…”

Section: Site Description Of the Illinois Basinmentioning

confidence: 99%

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Modeling Basin‐ and Plume‐Scale Processes of CO₂ Storage for Full‐Scale Deployment

Zhou¹,

Birkhölzer²,

et al. 2010

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Integrated modeling of basin-and plume-scale processes induced by full-scale deployment of CO 2 storage was applied to the Mt. Simon aquifer in the Illinois Basin. A 3D mesh was generated with local refinement around 20 injection sites, with ~30 km spacing. A total annual injection rate of 100 Mt CO 2 over 50 years was employed. The CO 2 -brine flow at the plume scale and the single-phase flow at the basin scale were simulated. Simulation results show the overall shape of a CO 2 plume consisting of a typical gravity-override subplume in the bottom injection zone of high injectivity and a pyramid-shaped subplume in the overlying multilayered Mt. Simon, indicating the important role of a secondary seal with relatively low permeability and high entry capillary pressure. The secondary seal effect is manifested by retarded upward CO 2 migration as a result of multiple secondary seals, coupled with lateral preferential CO 2 viscous fingering through high-permeability layers. The plume width varies from 9.0 to 13.5 km at 200 years, indicating the slow CO 2 migration and no plume interference between storage sites. On the basin scale, pressure perturbations propagate quickly away from injection centers, interfere after less than a year, and eventually reach basin margins.The simulated pressure buildup of 35 bar in the injection area is not expected to affect caprock geomechanical integrity. Moderate pressure buildup is observed in Mt. Simon in northern Illinois. However, its impact on groundwater resources is less than the hydraulic drawdown induced by long-term extensive pumping from overlying freshwater aquifers.

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Section: Site Description Of the Illinois Basinmentioning

confidence: 99%

Section: Site Description Of the Illinois Basinmentioning

confidence: 99%

Modeling Basin‐ and Plume‐Scale Processes of CO₂ Storage for Full‐Scale Deployment

Zhou¹,

Birkhölzer²,

et al. 2010

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“…Depending on the proposed storage several factors must be accounted for. Some may be specific as indicated in some studies (Blunt, Fayers et al 1993;Tsang, Benson et al 2002;Bossie-Codreanu, Le-Gallo et al 2003;Gale 2004;Xu, Sonnenthal et al 2006;Andre, Audigane et al 2007;Audigane, Gaus et al 2007;Ambrose, Lakshminarasimhan et al 2008;Zhou, Birkholzer et al 2008;Birkholzer, Zhang et al 2008b;Birkholzer, Zhou et al 2009) pertaining to individual storage candidate, or aspect under consideration such as the influence on the hydrology (Ennis- King and Paterson 2003a;Ennis-King and Paterson 2005;Tsang, Birkholzer et al 2008;Yamamoto, Zhang et al 2009); while other studies are more general (Gibson-Poole, R.S. et al 2005;Bachu, Bonijoly et al 2007;Bradshaw, Bachu et al 2007;Bachu 2008;Birkholzer and Tsang 2008).…”

Section: Literature Reviewmentioning

confidence: 99%

Investigation of Geomechanical Responses of Reservoirs Induced by Carbon Dioxide Storage

Eshiet

Sheng

2011

All Days

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Assessment of the suitability of potential sub-surface storage sites for CO 2 storage cuts across several issues, a dominant part being the sustainability in terms of the retention capacity of prospective reservoirs. Questions often raised but not properly investigated border on the stability of underground reservoirs during the injection process and the protracted effect after injection is fully completed. A review of studies on CO 2 sequestration reveal several uncovered areas with one significant aspect being the geo-mechanical effect of CO 2 injection and storage within the underground formation. A computational framework has been built as part of a series of ongoing investigations to ascertain the susceptibility of underground formations during and after CO 2 is introduced. This is made possible by adopting a discrete element modelling (DEM) methodology as a first step in the sequence of a designed procedure. By applying this technique the formation materials are idealized as an assembly of discrete particles interacting in a manner which allow for specific descriptions of the morphology and fracturing events. Computational tests conducted on several types of models representative of reservoir formations reveal reservoir geomechanical responses highly dependent on factors such as material property of rocks, pressure build-up, and injection pressure. An example of this is observed in the mode of fracturing events which is significantly influenced by the rate of fluid injection. The outcome of this study forms a strong basis towards a better understanding of behaviour of reservoir formations subjected to CO 2 injection and storage. In addition, information from these studies could serve as a reference for Enhanced Oil Recovery processes (EOR) and Enhanced Coal Bed Methane (ECBM) productions.

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“…Shale permeabilities have been reported to range from 0.1 to 10 -8 md. 12 Hart et al 13 The use of a power-law model for estimating permeability in shaley-sands using porosity and shale volume has been suggested. This exercise is somewhat similar to that of Timur, in that ultimately a power law (or in some cases, a modified power law) relation is obtained.…”

Section: Well Log Analysismentioning

confidence: 99%

Integrated Reflection Seismic Monitoring and Reservoir Modeling for Geologic CO2 Sequestration

Cabrera¹,

Huffman²,

Villarreal³

et al. 2011

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Research project on CO2 geological storage and groundwaterresources: Large-scale hydrological evaluation and modeling of impact ongroundwater systems

Cited by 14 publications

References 20 publications

Modeling Basin‐ and Plume‐Scale Processes of CO₂ Storage for Full‐Scale Deployment

Modeling Basin‐ and Plume‐Scale Processes of CO₂ Storage for Full‐Scale Deployment

Investigation of Geomechanical Responses of Reservoirs Induced by Carbon Dioxide Storage

Integrated Reflection Seismic Monitoring and Reservoir Modeling for Geologic CO2 Sequestration

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Research project on CO2 geological storage and groundwaterresources: Large-scale hydrological evaluation and modeling of impact ongroundwater systems

Cited by 14 publications

References 20 publications

Modeling Basin‐ and Plume‐Scale Processes of CO2 Storage for Full‐Scale Deployment

Modeling Basin‐ and Plume‐Scale Processes of CO2 Storage for Full‐Scale Deployment

Investigation of Geomechanical Responses of Reservoirs Induced by Carbon Dioxide Storage

Integrated Reflection Seismic Monitoring and Reservoir Modeling for Geologic CO2 Sequestration

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Product

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Modeling Basin‐ and Plume‐Scale Processes of CO₂ Storage for Full‐Scale Deployment

Modeling Basin‐ and Plume‐Scale Processes of CO₂ Storage for Full‐Scale Deployment