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Rasmusson, Kristina
Publications (10 of 12) Show all publications
Rasmusson, K., Rasmusson, M., Tsang, Y., Benson, S., Hingerl, F., Fagerlund, F. & Niemi, A. (2018). Residual trapping of carbon dioxide during geological storage: insight gained through a pore-network modeling approach. International Journal of Greenhouse Gas Control, 74, 62-78
Open this publication in new window or tab >>Residual trapping of carbon dioxide during geological storage: insight gained through a pore-network modeling approach
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2018 (English)In: International Journal of Greenhouse Gas Control, ISSN 1750-5836, E-ISSN 1878-0148, Vol. 74, p. 62-78Article in journal (Refereed) Published
Abstract [en]

To reduce emissions of the greenhouse gas CO2 to the atmosphere, sequestration in deep saline aquifers is a viable strategy. Residual trapping is a key containment process important to the success of CO2 storage operations. While residual trapping affects CO2 migration over large scales, it is inherently a pore-scale process. Pore-network models (PNMs), capturing such processes, are useful for our understanding of residual trapping, and for upscaling trapping parameters for larger scale models. A PNM for simulation of quasi-static two-phase flow; CO2 intrusion (drainage) followed by water flooding (imbibition) was developed. It accounts for pore-scale displacement mechanisms, and was used to investigate residual CO2 trapping. The sensitivity of the residual CO2 saturation to several parameters was studied, to validate a trapping behavior in agreement with earlier studies. Then the PNM was calibrated to core sample data and used to simulate drainage-imbibition scenarios with different turning point saturations. From these the initial-residual saturation curves of CO2 in Heletz sandstone were estimated, essential for future macroscopic-scale simulations. Further, the occurrence of different pore-scale mechanisms were quantified and the size distribution of the residual clusters was shown to exhibit a bimodal appearance. The findings improve the understanding of residual trapping in Heletz sandstone.

National Category
Earth and Related Environmental Sciences
Identifiers
urn:nbn:se:uu:diva-327991 (URN)10.1016/j.ijggc.2018.04.021 (DOI)000434428100007 ()
Funder
EU, FP7, Seventh Framework Programme, 309067Swedish Energy Agency, 43526-1
Available from: 2017-08-15 Created: 2017-08-15 Last updated: 2018-08-30Bibliographically approved
Rasmusson, M., Rasmusson, K., Fagerlund, F., Tsang, Y. & Niemi, A. (2018). The impact of co-contaminant SO2, versus salinity and thermodynamic conditions, on residual CO2 trapping during geological storage. Greenhouse Gases: Science and Technology, 8(6), 1053-1065
Open this publication in new window or tab >>The impact of co-contaminant SO2, versus salinity and thermodynamic conditions, on residual CO2 trapping during geological storage
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2018 (English)In: Greenhouse Gases: Science and Technology, E-ISSN 2152-3878, Vol. 8, no 6, p. 1053-1065Article in journal (Refereed) Published
Abstract [en]

During geological storage in deep saline aquifers, immobilization of CO2 in reservoir rock determines both storage safety and capacity. Assessment of the sensitivity of residual trapping to different parameters (interfacial tension and contact angles) and the storage conditions affecting these is therefore of great importance. One aspect of concern is the presence of co-contaminants such as SO2 in the injected gas. Using experimentally measured values of interfacial tensions and contact angles, we apply pore-network modelling (which accounts for pore-scale mechanisms such as snap-off, cooperative pore body filling and piston-type displacement) to a generic sandstone network to quantify the impact of SO2 co-injection on residual CO2 trapping, and its relative importance as compared to the influences of thermodynamic conditions and salinity. We show that the presence of small amounts of SO2 in the injected CO2 has a notable positive effect on the amount of CO2 becoming residually trapped (similar to 3% increase at 1 wt% SO2). However, this effect is small compared to that of the brine salinity (similar to 20% decrease in residually trapped CO2 over the salinity range 0.2 to 5 M NaCl). Still, co-injection of SO2 could potentially favour the residual trapping of CO2 in reservoir rocks, especially at storage sites with inclined aquifers where the CO2 is set to migrate hydro-dynamically over long distances. The salinity of the resident brine is of primary importance during storage site selection. Furthermore, sensitivity analysis shows that the advancing contact angle strongly impacts residual CO2 trapping. 

Place, publisher, year, edition, pages
WILEY PERIODICALS, INC, 2018
Keywords
capillary trapping, carbon dioxide, co-injection, impurities, pore-network model, sulfur dioxide
National Category
Oceanography, Hydrology and Water Resources
Identifiers
urn:nbn:se:uu:diva-371116 (URN)10.1002/ghg.1816 (DOI)000451042600006 ()
Funder
Swedish Research Council, 2010-3657EU, FP7, Seventh Framework Programme, 282900EU, FP7, Seventh Framework Programme, 309102
Available from: 2018-12-28 Created: 2018-12-28 Last updated: 2018-12-28Bibliographically approved
Rasmusson, K. (2017). Modeling of geohydrological processes in geological CO2 storage – with focus on residual trapping. (Doctoral dissertation). Uppsala: Acta Universitatis Upsaliensis
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. p. 96
Series
Digital Comprehensive Summaries of Uppsala Dissertations from the Faculty of Science and Technology, ISSN 1651-6214 ; 1540
Keywords
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
Rasmusson, M., Fagerlund, F., Rasmusson, K., Tsang, Y. & Niemi, A. (2017). Refractive-Light-Transmission Technique Applied to Density-Driven Convective Mixing in Porous Media With Implications for Geological CO2 Storage. Water resources research, 53(11), 8760-8780
Open this publication in new window or tab >>Refractive-Light-Transmission Technique Applied to Density-Driven Convective Mixing in Porous Media With Implications for Geological CO2 Storage
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2017 (English)In: Water resources research, ISSN 0043-1397, E-ISSN 1944-7973, Vol. 53, no 11, p. 8760-8780Article in journal (Refereed) Published
Abstract [en]

Density-driven convection has been identified to accelerate the rate of CO2 solubility trapping during geological CO2 storage in deep saline aquifers. In this paper, we present an experimental method using the refractive properties of fluids (their impact on light transmission), and an analogous system design, which enables the study of transport mechanisms in saturated porous media. The method is used to investigate solutally induced density-driven convective mixing under conditions relevant to geological CO2 storage. The analogous system design allows us by choice of initial solute concentration and bead size to duplicate a wide range of conditions (Ra-values), making it possible to study the convective process in general, and as a laboratory analogue for systems found in the field. We show that the method accurately determines the solute concentration in the system with high spatial and temporal resolution. The onset time of convection (t(c)), mass flux (F), and flow dynamics are quantified and compared with experimental and numerical findings in the literature. Our data yield a scaling law for tc which gives new insight into its dependence on Ra, indicating t(c) to be more sensitive to large Ra than previously thought. Furthermore, our data show and explain why F is described equally well by a Ra-dependent or a Ra-independent scaling law. These findings improve the understanding of the physical process of convective mixing in saturated porous media in general and help to assess the CO2 solubility trapping rate under certain field conditions.

Place, publisher, year, edition, pages
American Geophysical Union (AGU), 2017
Keywords
carbon dioxide, CCS, density-driven convection, experiment, refraction, solubility trapping
National Category
Environmental Sciences Oceanography, Hydrology and Water Resources
Identifiers
urn:nbn:se:uu:diva-339703 (URN)10.1002/2017WR020730 (DOI)000418736700007 ()
Available from: 2018-01-26 Created: 2018-01-26 Last updated: 2018-03-03Bibliographically approved
Niemi, A., Bensabat, J., Shtivelman, V., Edlmann, K., Gouze, P., Luquot, L., . . . Freifeld, B. (2016). Heletz experimental site overview, characterization and data analysis for CO2 injection and geological storage. International Journal of Greenhouse Gas Control, 48, 3-23
Open this publication in new window or tab >>Heletz experimental site overview, characterization and data analysis for CO2 injection and geological storage
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2016 (English)In: International Journal of Greenhouse Gas Control, ISSN 1750-5836, E-ISSN 1878-0148, Vol. 48, p. 3-23Article in journal (Refereed) Published
Abstract [en]

This paper provides an overview of the site characterization work at the Heletz site, in preparation to scientifically motivated CO2 injection experiments. The outcomes are geological and hydrogeological models with associated medium properties and baseline conditions. The work has consisted on first re-analyzing the existing data base from similar to 40 wells from the previous oil exploration studies, based on which a 3-dimensional structural model was constructed along with first estimates of the properties. The CO2 injection site is located on the saline edges of the Heletz depleted oil field. Two new deep (> 1600 m) wells were drilled within the injection site and from these wells a detailed characterization program was carried out, including coring, core analyses, fluid sampling, geophysical logging, seismic survey, in situ hydraulic testing and measurement of the baseline pressure and temperature. The results are presented and discussed in terms of characteristics of the reservoir and cap-rock, the mineralogy, water composition and other baseline conditions, porosity, permeability, capillary pressure and relative permeability. Special emphasis is given to petrophysical properties of the reservoir and the seal, such as comparing the estimates determined by different methods, looking at their geostatistical distributions as well as changes in them when exposed to CO2.

Keywords
Deep geologic storage of CO2, Site characterization, Site properties, CO2 injection
National Category
Geosciences, Multidisciplinary
Identifiers
urn:nbn:se:uu:diva-299606 (URN)10.1016/j.ijggc.2015.12.030 (DOI)000378004200002 ()
Funder
EU, FP7, Seventh Framework Programme, 227286 309067Swedish Research Council
Available from: 2016-07-25 Created: 2016-07-25 Last updated: 2017-11-28Bibliographically approved
Rasmusson, K., Tsang, C.-F., Tsang, Y., Rasmusson, M., Pan, L., Fagerlund, F., . . . Niemi, A. (2015). Distribution of injected CO2 in a stratified saline reservoir accounting for coupled wellbore-reservoir flow. Greenhouse Gases: Science and Technology, 5(4), 419-436
Open this publication in new window or tab >>Distribution of injected CO2 in a stratified saline reservoir accounting for coupled wellbore-reservoir flow
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2015 (English)In: Greenhouse Gases: Science and Technology, E-ISSN 2152-3878, Vol. 5, no 4, p. 419-436Article 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.

Keywords
CCS, flow distribution, geological storage, layered formation, wellbore model
National Category
Oceanography, Hydrology and Water Resources
Identifiers
urn:nbn:se:uu:diva-263036 (URN)10.1002/ghg.1477 (DOI)000360356800007 ()
Funder
EU, FP7, Seventh Framework Programme, 227286EU, FP7, Seventh Framework Programme, 309067
Available from: 2015-09-30 Created: 2015-09-24 Last updated: 2018-01-11Bibliographically approved
Rasmusson, M., Fagerlund, F., Tsang, Y., Rasmusson, K. & Niemi, A. (2015). Prerequisites for density-driven instabilities and convective mixing under broad geological CO2 storage conditions. Advances in Water Resources, 84, 136-151
Open this publication in new window or tab >>Prerequisites for density-driven instabilities and convective mixing under broad geological CO2 storage conditions
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2015 (English)In: Advances in Water Resources, ISSN 0309-1708, E-ISSN 1872-9657, Vol. 84, p. 136-151Article in journal (Refereed) Published
Abstract [en]

Direct atmospheric greenhouse gas emissions can be greatly reduced by CO2 sequestration in deep saline aquifers. One of the most secure and important mechanisms of CO2 trapping over large time scales is solubility trapping. In addition, the CO2 dissolution rate is greatly enhanced if density-driven convective mixing occurs. We present a systematic analysis of the prerequisites for density-driven instability and convective mixing over the broad temperature, pressure, salinity and permeability conditions that are found in geological CO2 storage. The onset of instability (Rayleigh-Darcy number, Ra), the onset time of instability and the steady convective flux are comprehensively calculated using a newly developed analysis tool that accounts for the thermodynamic and salinity dependence on solutally and thermally induced density change, viscosity, molecular and thermal diffusivity. Additionally, the relative influences of field characteristics are analysed through local and global sensitivity analyses. The results help to elucidate the trends of the Ra, onset time of instability and steady convective flux under field conditions. The impacts of storage depth and basin type (geothermal gradient) are also explored and the conditions that favour or hinder enhanced solubility trapping are identified. Contrary to previous studies, we conclude that the geothermal gradient has a non-negligible effect on density-driven instability and convective mixing when considering both direct and indirect thermal effects because cold basin conditions, for instance, render higher Ra compared to warm basin conditions. We also show that the largest Ra is obtained for conditions that correspond to relatively shallow depths, measuring approximately 800 m, indicating that CO2 storage at such depths favours the onset of density-driven instability and reduces onset times. However, shallow depths do not necessarily provide conditions that generate the largest steady convective fluxes; the salinity determines the storage depth at which the largest steady convective fluxes occur. Furthermore, we present a straight-forward and efficient procedure to estimate site-specific solutal Ra that accounts for thermodynamic and salinity dependence.

Keywords
Carbon dioxide, CCS, Density-driven flow, Density instability, Double-diffusive convection, Porous media
National Category
Oceanography, Hydrology and Water Resources
Identifiers
urn:nbn:se:uu:diva-265827 (URN)10.1016/j.advwatres.2015.08.009 (DOI)000362305900012 ()
Funder
Swedish Research Council
Available from: 2015-11-03 Created: 2015-11-03 Last updated: 2018-03-03Bibliographically approved
Rasmusson, K., Rasmusson, M., Fagerlund, F., Bensabat, J., Tsang, Y. & Niemi, A. (2014). Analysis of alternative push-pull-test-designs for determining in situ residual trapping of carbon dioxide. International Journal of Greenhouse Gas Control, 27, 155-168
Open this publication in new window or tab >>Analysis of alternative push-pull-test-designs for determining in situ residual trapping of carbon dioxide
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2014 (English)In: International Journal of Greenhouse Gas Control, ISSN 1750-5836, E-ISSN 1878-0148, Vol. 27, p. 155-168Article in journal (Refereed) Published
Abstract [en]

Carbon dioxide storage in deep saline aquifers is a promising technique to reduce direct emissions of greenhouse gas to the atmosphere. To ensure safe storage the in situ trapping mechanisms, residual trapping being one of them, need to be characterized. This study aims to compare three alternative single-well carbon dioxide push-pull test sequences for their ability to quantify residual gas trapping. The three tests are based on the proposed test sequence by Zhang et al. (2011) for estimating residual gas saturation. A new alternative way to create residual gas conditions in situ incorporating withdrawal and a novel indicator-tracer approach has been investigated. Further the value of additional pressure measurements from a nearby passive observation well was evaluated. The iTOUGH2 simulator with the EOS7C module was used for sensitivity analysis and parameter estimation. Results show that the indicator-tracer approach could be used to create residual conditions without increasing estimation uncertainty of S-gr. Additional pressure measurements from a passive observation well would reduce the uncertainty in the S-gr estimate. The findings of the study can be used to develop field experiments for site characterization.

Keywords
CO2, CCS, Site characterization, Field test, Residual saturation, Single-well test
National Category
Energy Systems
Identifiers
urn:nbn:se:uu:diva-232013 (URN)10.1016/j.ijggc.2014.05.008 (DOI)000340319600012 ()
Available from: 2014-09-12 Created: 2014-09-12 Last updated: 2018-03-03Bibliographically approved
Niemi, A., Bensabat, J., Fagerlund, F., Sauter, M., Ghergut, J., Licha, T., . . . Gendler, M. (2012). Small-Scale CO2 Injection into a Deep Geological Formation at Heletz, Israel. Paper presented at The 6th Trondheim Conference on CO2 Capture, Transport and Storage, 14-16 jun, 2011, Trondheim, NORWAY. Energy Procedia, 23, 504-511
Open this publication in new window or tab >>Small-Scale CO2 Injection into a Deep Geological Formation at Heletz, Israel
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2012 (English)In: Energy Procedia, ISSN 1876-6102, E-ISSN 1876-6102, Vol. 23, p. 504-511Article in journal (Refereed) Published
Abstract [en]

This paper presents the experimental plans and designs as well as examples of predictive modeling of a pilot-scale CO2 injection experiment at the Heletz site (Israel). The overall objective of the experiment is to find optimal ways to characterize CO2 -relevant in-situ medium properties, including field-scale residual and dissolution trapping, to explore ways of characterizing heterogeneity through joint analysis of different types of data, and to detect leakage. The experiment will involve two wells, an injection well and a monitoring well. Prior to the actual CO2 injection, hydraulic, thermal and tracer tests will be carried out for standard site characterization. The actual CO2 injection experiments will include (i) a single well injection-withdrawal experiment, with the main objective to estimate in-situ residual trapping and (ii) a two-well injection-withdrawal test with injection of CO2 in a dipole mode (injection of CO2 in one well with simultaneous withdrawal of water in the monitoring well), with the objective to understand the CO2 transport in heterogeneous geology as well as the associated dissolution and residual trapping. Tracers will be introduced in both experiments to further aid in detecting the development of the phase composition during CO2 transport. Geophysical monitoring will also be implemented. By means of modeling, different experimental sequences and injection/withdrawal patterns have been analyzed, as have parameter uncertainties. The objectives have been to (i) evaluate key aspects of the experimental design, (ii) to identify key parameters affecting the fate of the CO2 and (iii) to evaluate the relationships between measurable quantities and parameters of interest.

Keywords
CO2, injection experiment, modeling, instrumention
National Category
Natural Sciences
Identifiers
urn:nbn:se:uu:diva-191849 (URN)10.1016/j.egypro.2012.06.048 (DOI)
Conference
The 6th Trondheim Conference on CO2 Capture, Transport and Storage, 14-16 jun, 2011, Trondheim, NORWAY
Funder
EU, FP7, Seventh Framework Programme
Available from: 2013-01-14 Created: 2013-01-14 Last updated: 2017-12-06
Bensabat, J., Kitron-Belinkov, M., Rasmusson, K., Rasmusson, M., Niemi, A. & Bear, J. (2011). Model for the dependence of conditions at the injection well head and the reservoir during CO2 injection. In: : . Paper presented at European Geosciences Union (EGU), 2011, 3-8 April, Vienna, Austria.
Open this publication in new window or tab >>Model for the dependence of conditions at the injection well head and the reservoir during CO2 injection
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2011 (English)Conference paper, Published paper (Refereed)
Abstract [en]

Highly controlled field injection experiments are necessary for demonstration, for scientific understanding and for quantification of the relevant processes of CO2 geological storage.

The preparation of such an experiment requires reliable information on both the hydraulic, thermal and chemical properties of the target layer and the formation fluid as well as on the injection discharges and their associated pressure build-up in the reservoir. For this, there is a need to determine the state variables of CO2 in the injection tube near the well head, which can produce the desired mass flow rates given the condition at the reservoir, while respecting pressure buildup constraints.

 

A model connecting the multiphase flow and transport processes in the target layer (based on the well-known TOUGH2/ECO2N model) at the vicinity of the injection well with those occurring in the injection tube (solving the one dimensional equations mass, momentum and energy conservation) has been developed. To this model the injection tube is a boundary condition. Once the reservoir pressure build-up resulting from the injection discharge is known, there is a need to determine the necessary injection conditions at the wellhead. For this purpose we apply the 1-D tube model, which provides the solution of the conditions in the injection pipe, given the injection rate and the pressure at the reservoir.

 

These two linked models, the porous medium model and the pipe model, are applied to the planning of the Heletz injection experiment to be carried out in the frame of the EU-FP7 funded MUSTANG project. Sensitivity analyses are carried out with regard to uncertainty in the target layer permeability and the temperature of the injected CO2, which depends on the thermal heat transfer coefficient in the injection tube.

Keywords
CO2, injection, model, pipe flow, TOUGH2/ECO2N, well, reservoir, MUSTANG, CO2, injektion, modell, TOUGH2/ECO2N, brunn, reservoar, MUSTANG
National Category
Earth and Related Environmental Sciences
Research subject
Hydrology
Identifiers
urn:nbn:se:uu:diva-152095 (URN)
Conference
European Geosciences Union (EGU), 2011, 3-8 April, Vienna, Austria
Projects
MUSTANG
Funder
EU, FP7, Seventh Framework Programme, 227286
Note

Geophysical Research Abstracts, Vol. 13, EGU2011-6101, 2011

Available from: 2011-04-23 Created: 2011-04-23 Last updated: 2013-10-14Bibliographically approved
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