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Distribution of injected CO2 in a stratified saline reservoir accounting for coupled wellbore-reservoir flow
Uppsala University, Disciplinary Domain of Science and Technology, Earth Sciences, Department of Earth Sciences, LUVAL.
Uppsala University, Disciplinary Domain of Science and Technology, Earth Sciences, Department of Earth Sciences, LUVAL.
Uppsala University, Disciplinary Domain of Science and Technology, Earth Sciences, Department of Earth Sciences, LUVAL.
Uppsala University, Disciplinary Domain of Science and Technology, Earth Sciences, Department of Earth Sciences, LUVAL.
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2015 (English)In: Greenhouse Gases: Science and Technology, E-ISSN 2152-3878, Vol. 5, no 4, 419-436 p.Article in journal (Refereed) Published
Abstract [en]

Geological storage in sedimentary basins is considered a viable technology in mitigating atmospheric CO2 emissions. Alternating high and low permeability strata are common in these basins. The distribution of injected CO2 among such layers affects e.g. CO2 storage efficiency, capacity and plume footprint. A numerical study on the distribution of injected CO2 into a multi-layered reservoir, accounting for coupled wellbore-reservoir flow, was carried out using the T2Well/ECO2N code. A site-specific case as well as a more general case were considered. Properties and processes governing the distribution of sequestrated CO2 were identified and the potential to operationally modify the distribution was investigated. The distribution of CO2 was seen to differ from that of injected water, i.e. it was not proportional to the transmissivity of the layers. The results indicate that caution should be taken when performing numerical simulations of CO2 injection into layered formations. Ignoring coupled wellbore-reservoir flow and instead adopting a simple boundary condition at the injection well, such as an inflow rate proportional to the transmissivity of each layer, may result in significant underestimation of the proportion of CO2 ending up in the shallower layers, as not all relevant processes are accounted for. This discrepancy has been thoroughly investigated and quantified for several CO2 sequestration scenarios.

Place, publisher, year, edition, pages
2015. Vol. 5, no 4, 419-436 p.
Keyword [en]
CCS, flow distribution, geological storage, layered formation, wellbore model
National Category
Oceanography, Hydrology, Water Resources
Identifiers
URN: urn:nbn:se:uu:diva-263036DOI: 10.1002/ghg.1477ISI: 000360356800007OAI: oai:DiVA.org:uu-263036DiVA: diva2:857940
Funder
EU, FP7, Seventh Framework Programme, 227286EU, FP7, Seventh Framework Programme, 309067
Available from: 2015-09-30 Created: 2015-09-24 Last updated: 2017-12-01Bibliographically approved
In thesis
1. Modeling of geohydrological processes in geological CO2 storage – with focus on residual trapping
Open this publication in new window or tab >>Modeling of geohydrological processes in geological CO2 storage – with focus on residual trapping
2017 (English)Doctoral thesis, comprehensive summary (Other academic)
Abstract [en]

Geological storage of carbon dioxide (CO2) in deep saline aquifers is one approach to mitigate release from large point sources to the atmosphere. Understanding of in-situ processes providing trapping is important to the development of realistic models and the planning of future storage projects. This thesis covers both field- and pore-scale numerical modeling studies of such geohydrological processes, with focus on residual trapping. The setting is a CO2-injection experiment at the Heletz test site, conducted within the frame of the EU FP7 MUSTANG and TRUST projects.

The objectives of the thesis are to develop and analyze alternative experimental characterization test sequences for determining in-situ residual CO2 saturation (Sgr), as well as to analyze the impact of the injection strategy on trapping, the effect of model assumptions (coupled wellbore-reservoir flow, geological heterogeneity, trapping model) on the predicted trapping, and to develop a pore-network model (PNM) for simulating and analyzing pore-scale mechanisms.

The results include a comparison of alternative characterization test sequences for estimating Sgr. The estimates were retrieved through parameter estimation. The effect on the estimate of including various data sets was determined. A new method, using withdrawal and an indicator-tracer, for obtaining a residual zone in-situ was also introduced.

Simulations were made of the CO2 partitioning between layers in a multi-layered formation, and parameters influencing this were identified. The results showed the importance of accounting for coupled wellbore-reservoir flow in simulations of such scenarios.

Simulations also showed that adding chase-fluid stages after a conventional CO2 injection enhances the (residual and dissolution) trapping. Including geological heterogeneity generally decreased the estimated trapping. The choice of trapping model may largely effect the quantity of the predicted residual trapping (although most of them produced similar results). The use of an appropriate trapping model and description of geological heterogeneity for a site when simulating CO2 sequestration is vital, as different assumptions may give significant discrepancies in predicted trapping.

The result also includes a PNM code, for multiphase quasi-static flow and trapping in porous materials. It was used to investigate trapping and obtain an estimated trapping (IR) curve for Heletz sandstone.

Place, publisher, year, edition, pages
Uppsala: Acta Universitatis Upsaliensis, 2017. 96 p.
Series
Digital Comprehensive Summaries of Uppsala Dissertations from the Faculty of Science and Technology, ISSN 1651-6214 ; 1540
Keyword
capillary trapping, CCS, characterization test, CO2, injection design, pore-network model
National Category
Earth and Related Environmental Sciences
Research subject
Hydrology
Identifiers
urn:nbn:se:uu:diva-327994 (URN)978-91-513-0031-3 (ISBN)
Public defence
2017-09-29, Hambergsalen, Geocentrum, Villavägen 16, Uppsala, 10:00 (English)
Opponent
Supervisors
Available from: 2017-09-06 Created: 2017-08-15 Last updated: 2017-09-08

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Rasmusson, KristinaTsang, Chin-FuTsang, YvonneRasmusson, MariaFagerlund, FritjofNiemi, Auli

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