Geological CO2 Storage Supports Geothermal Energy Exploitation: 3D Numerical Models Emphasize Feasibility of Synergetic Use

Tillner, Elena; Kempka, Thomas; Nakaten, Benjamin; Kühn, Michael

doi:10.1016/j.egypro.2013.06.593

Cited by 11 publications

(4 citation statements)

References 9 publications

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“…For this purpose, coupled hydro-mechanical simulations are applied to account for the interaction between hydraulic and mechanical processes, potentially triggering fault slip and dilation resulting in, e.g., new or enhanced leakage pathways for formation fluids. To minimise pressure perturbation due to fluid injection, and thus fault fluid flow, simultaneous fluid injection and production from storage reservoirs is discussed as one efficient mitigation measure to be applied in geological underground utilisation (Kempka et al, 2015b;Tillner et al, 2013b;Court et al, 2012;Bergmo et al, 2011;Buscheck et al, 2011).…”

Section: Discussionmentioning

confidence: 99%

Fault damage zone volume and initial salinity distribution determine intensity of shallow aquifer salinisation in subsurface storage

Tillner

Langer

Kempka

et al. 2016

Hydrol. Earth Syst. Sci.

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Abstract. Injection of fluids into deep saline aquifers causes a pore pressure increase in the storage formation, and thus displacement of resident brine. Via hydraulically conductive faults, brine may migrate upwards into shallower aquifers and lead to unwanted salinisation of potable groundwater resources. In the present study, we investigated different scenarios for a potential storage site in the Northeast German Basin using a three-dimensional (3-D) regional-scale model that includes four major fault zones. The focus was on assessing the impact of fault length and the effect of a secondary reservoir above the storage formation, as well as model boundary conditions and initial salinity distribution on the potential salinisation of shallow groundwater resources. We employed numerical simulations of brine injection as a representative fluid.Our simulation results demonstrate that the lateral model boundary settings and the effective fault damage zone volume have the greatest influence on pressure build-up and development within the reservoir, and thus intensity and duration of fluid flow through the faults. Higher vertical pressure gradients for short fault segments or a small effective fault damage zone volume result in the highest salinisation potential due to a larger vertical fault height affected by fluid displacement. Consequently, it has a strong impact on the degree of shallow aquifer salinisation, whether a gradient in salinity exists or the saltwater-freshwater interface lies below the fluid displacement depth in the faults. A small effective fault damage zone volume or low fault permeability further extend the duration of fluid flow, which can persist for several tens to hundreds of years, if the reservoir is laterally confined. Laterally open reservoir boundaries, large effective fault damage zone volumes and intermediate reservoirs significantly reduce vertical brine migration and the potential of freshwater salinisation because the origin depth of displaced brine is located only a few decametres below the shallow aquifer in maximum.The present study demonstrates that the existence of hydraulically conductive faults is not necessarily an exclusion criterion for potential injection sites, because salinisation of shallower aquifers strongly depends on initial salinity distribution, location of hydraulically conductive faults and their effective damage zone volumes as well as geological boundary conditions.

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Section: Discussionmentioning

confidence: 99%

Fault damage zone volume and initial salinity distribution determine intensity of shallow aquifer salinisation in subsurface storage

Tillner

Langer

Kempka

et al. 2016

Hydrol. Earth Syst. Sci.

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“…More recently, Buscheck et al (2013), Tillner et al, 2013 andKempka et al, 2015 investigated the synergetic use of geological CO 2 storage and geothermal energy exploitation using formation water as the geothermal fluid. In this configuration, CO 2 injection acts as a pressure-support fluid to the geothermal production.…”

Section: Coupling Geological Carbon Storage and Geothermal Energy Extmentioning

confidence: 99%

Reducing operational costs of CO2 sequestration through geothermal energy integration

Ricard

Underschultz

et al. 2016

International Journal of Greenhouse Gas Control

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“…Modélisation des phénomènes de transferts de masse dans les milieux poreux soumis à une réaction de surface : de l'échelle du pore à l'échelle de la carotte S. Bekri, S. Renard and F. Delprat-Jannaud (Bergmo et al, 2011;Court et al, 2012;Tillner et al, 2013a;Nielsen et al, 2013) demonstrated that formation fluid extraction supports geological CO 2 storage by increasing storage efficiency and reducing reservoir pressure elevation. Depending on the target formation depth, extracted fluids may be used for geothermal heat recovery or disposed according to national environmental regulations.…”

Section: > Pore To Core Scale Simulation Of the Mass Transfer With MIunclassified

Coupled Hydro-Mechanical Simulations of CO₂Storage Supported by Pressure Management Demonstrate Synergy Benefits from Simultaneous Formation Fluid Extraction

Kempka

Nielsen

Frykman

et al. 2014

Oil Gas Sci. Technol. – Rev. IFP Energies nouvelles

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-We assessed the synergetic benefits of simultaneous formation fluid extraction during CO 2 injection for reservoir pressure management by coupled hydro-mechanical simulations at the prospective Vedsted storage site located in northern Denmark. Effectiveness of reservoir pressure management was investigated by simulation of CO 2 storage without any fluid extraction as well as with 66% and 100% equivalent volume formation fluid extraction from four wells positioned for geothermal heat recovery. Simulation results demonstrate that a total pressure reduction of up to about 1.1 MPa can be achieved at the injection well. Furthermore, the areal pressure perturbation in the storage reservoir can be significantly decreased compared to the simulation scenario without any formation fluid extraction. Following a stress regime analysis, two stress regimes were considered in the coupled hydro-mechanical simulations indicating that the maximum ground surface uplift is about 0.24 m in the absence of any reservoir pressure management. However, a ground uplift mitigation of up to 37.3% (from 0.24 m to 0.15 m) can be achieved at the injection well by 100% equivalent volume formation fluid extraction. Wellbased adaptation of fluid extraction rates can support achieving zero displacements at the proposed formation fluid extraction wells located close to urban infrastructure. Since shear and tensile failure do not occur under both stress regimes for all investigated scenarios, it is concluded that a safe operation of CO 2 injection with simultaneous formation fluid extraction for geothermal heat recovery can be implemented at the Vedsted site.Re´sume´-Des simulations du comportement hydrome´canique d'un re´servoir ge´ologique de stockage de CO 2 dans un contexte de gestion de la pression de´montrent les avantages de l'extraction de fluide de la formation au cours de l'injection du CO 2 -Au moyen de simulations hydrome´caniques couple´es mene´es sur le site de stockage prospectif Vedsted situe´au nord du Danemark, nous avons e´value´les avantages de l'extraction du fluide de la formation au cours de l'injection de CO 2 dans un but de gestion de la pression dans le re´servoir. L'efficacite´de la gestion de la Oil & Gas Science and Technology -Rev. IFP Energies nouvelles, Vol. 70 (2015), No. 4, pp. 599-613 Ó T. Kempka et al., published by IFP Energies nouvelles, 2014 DOI: 10.2516 This is an Open Access article distributed under the terms of the Creative Commons Attribution License (http://creativecommons.org/licenses/by/4.0), which permits unrestricted use, distribution, and reproduction in any medium, provided the original work is properly cited.pression du re´servoir a e´te´e´tudie´e par comparaison des simulations du stockage de CO 2 sans extraction de fluide avec celles associe´es a`une extraction d'un volume e´quivalent de fluide de la formation de 66 % et 100 % a`partir de quatre puits de´die´s a`la re´cupe´ration ge´othermique de chaleur. Les re´sultats des simulations montrent qu'une re´duction de la pression totale ...

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Geological CO2 Storage Supports Geothermal Energy Exploitation: 3D Numerical Models Emphasize Feasibility of Synergetic Use

Cited by 11 publications

References 9 publications

Fault damage zone volume and initial salinity distribution determine intensity of shallow aquifer salinisation in subsurface storage

Fault damage zone volume and initial salinity distribution determine intensity of shallow aquifer salinisation in subsurface storage

Reducing operational costs of CO2 sequestration through geothermal energy integration

Coupled Hydro-Mechanical Simulations of CO₂Storage Supported by Pressure Management Demonstrate Synergy Benefits from Simultaneous Formation Fluid Extraction

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Geological CO2 Storage Supports Geothermal Energy Exploitation: 3D Numerical Models Emphasize Feasibility of Synergetic Use

Cited by 11 publications

References 9 publications

Fault damage zone volume and initial salinity distribution determine intensity of shallow aquifer salinisation in subsurface storage

Fault damage zone volume and initial salinity distribution determine intensity of shallow aquifer salinisation in subsurface storage

Reducing operational costs of CO2 sequestration through geothermal energy integration

Coupled Hydro-Mechanical Simulations of CO2Storage Supported by Pressure Management Demonstrate Synergy Benefits from Simultaneous Formation Fluid Extraction

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Coupled Hydro-Mechanical Simulations of CO₂Storage Supported by Pressure Management Demonstrate Synergy Benefits from Simultaneous Formation Fluid Extraction