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Planned decommissioning of coal-fired plants in Europe requires innovative technical and economic strategies to support coal regions on their path towards a climate-resilient future. The repurposing of open pit mines into hybrid pumped hydro power storage (HPHS) of excess energy from the electric grid, and renewable sources will contribute to the EU Green Deal, increase the economic value, stabilize the regional job market and contribute to the EU energy supply security. This study aims to present a preliminary phase of a geospatial workflow used to evaluate land suitability by implementing a multi-criteria decision making (MCDM) technique with an advanced geographic information system (GIS) in the context of an interdisciplinary feasibility study on HPHS in the Kardia lignite open pit mine (Western Macedonia, Greece). The introduced geospatial analysis is based on the utilization of the constraints and ranking criteria within the boundaries of the abandoned mine regarding specific topographic and proximity criteria. The applied criteria were selected from the literature, while for their weights, the experts' judgement was introduced by implementing the analytic hierarchy process (AHP), in the framework of the ATLANTIS research program. According to the results, seven regions were recognized as suitable, with a potential energy storage capacity from 1.09 to 5.16 GWh. Particularly, the present study's results reveal that 9.27% (212,884 m(2)) of the area had a very low suitability, 15.83% (363,599 m(2)) had a low suitability, 23.99% (550,998 m(2)) had a moderate suitability, 24.99% (573,813 m(2)) had a high suitability, and 25.92% (595,125 m(2)) had a very high suitability for the construction of the upper reservoir. The proposed semi-automatic geospatial workflow introduces an innovative tool that can be applied to open pit mines globally to identify the optimum design for an HPHS system depending on the existing lower reservoir.
Dissolved CO2 storage in geological formations with low pressure, low risk and large capacities
(2017)
Geological CO2 storage is a mitigation technology to reduce CO2 emissions from fossil fuel combustion. However, major concerns are the pressure increase and saltwater displacement in the mainly targeted deep groundwater aquifers due to injection of supercritical CO2. The suggested solution is storage of CO2 exclusively in the dissolved state. In our exemplary regional case study of the North East German Basin based on a highly resolved temperature and pressure distribution model and a newly developed reactive transport coupling, we have quantified that 4.7 Gt of CO2 can be stored in solution compared to 1.5 Gt in the supercritical state.
Integration and development of the energy supply in China and worldwide is a challenge for the years to come. The innovative idea presented here is based on an extension of the “power-to-gas-to-power” technology by establishing a closed carbon cycle. It is an implementation of a low-carbon energy system based on carbon dioxide capture and storage (CCS) to store and reuse wind and solar energy. The Chenjiacun storage project in China compares well with the German case study for the towns Potsdam and Brandenburg/Havel in the Federal State of Brandenburg based on the Ketzin pilot site for CCS.
The LArge-scale Reservoir Simulator (LARS) has been previously developed to study hydrate dissociation in hydrate-bearing systems under in-situ conditions. In the present study, a numerical framework of equations of state describing hydrate formation at equilibrium conditions has been elaborated and integrated with a numerical flow and transport simulator to investigate a multi-stage hydrate formation experiment undertaken in LARS. A verification of the implemented modeling framework has been carried out by benchmarking it against another established numerical code. Three-dimensional (3D) model calibration has been performed based on laboratory data available from temperature sensors, fluid sampling, and electrical resistivity tomography. The simulation results demonstrate that temperature profiles, spatial hydrate distribution, and bulk hydrate saturation are consistent with the observations. Furthermore, our numerical framework can be applied to calibrate geophysical measurements, optimize post-processing workflows for monitoring data, improve the design of hydrate formation experiments, and investigate the temporal evolution of sub-permafrost methane hydrate reservoirs.
The Mackenzie Delta (MD) is a permafrost-bearing region along the coasts of the Canadian Arctic which exhibits high sub-permafrost gas hydrate (GH) reserves. The GH occurring at the Mallik site in the MD is dominated by thermogenic methane (CH4), which migrated from deep conventional hydrocarbon reservoirs, very likely through the present fault systems. Therefore, it is assumed that fluid flow transports dissolved CH4 upward and out of the deeper overpressurized reservoirs via the existing polygonal fault system and then forms the GH accumulations in the Kugmallit-Mackenzie Bay Sequences. We investigate the feasibility of this mechanism with a thermo-hydraulic-chemical numerical model, representing a cross section of the Mallik site. We present the first simulations that consider permafrost formation and thawing, as well as the formation of GH accumulations sourced from the upward migrating CH4-rich formation fluid. The simulation results show that temperature distribution, as well as the thickness and base of the ice-bearing permafrost are consistent with corresponding field observations. The primary driver for the spatial GH distribution is the permeability of the host sediments. Thus, the hypothesis on GH formation by dissolved CH4 originating from deeper geological reservoirs is successfully validated. Furthermore, our results demonstrate that the permafrost has been substantially heated to 0.8-1.3 degrees C, triggered by the global temperature increase of about 0.44 degrees C and further enhanced by the Arctic Amplification effect at the Mallik site from the early 1970s to the mid-2000s.
Power-to-gas (PtG) stores chemical energy by converting excess electrical energy from renewable sources into an energy-dense gas. Due to its higher available capacity compared to surface-based storage technologies, subsurface storage in geological systems is the most promising approach for efficient and economic realization of the PtG system’s storage component. For this purpose, methane (CH4) produced by methanation by means of hydrogen (H2) and carbon dioxide (CO2) is stored in a geological reservoir until required for further use. In this context, CO2 is used as the cushion gas to maintain reservoir pressure and limiting working gas, i.e., (CH4) losses during withdrawal periods. Consequently, mixing of both gases in the reservoir is inevitable. Therefore, it is necessary to minimize the gas mixing region to optimize the efficiency of the PtG system’s storage component. In the present study, the physical properties of CH4, CO2 and their mixtures are reviewed. Then, a multicomponent flow model is implemented and validated against published data. Next, a hydromechanically coupled model is established, considering fluid flow through porous media and effective stresses to investigate the mixing behavior of both gases and the mechanical reservoir stability. The simulation results show that, with increasing reservoir thickness and dip angle, the mixing region is reduced during gas injection if CO2 is employed as the cushion gas. In addition, the degree of mixing is lower at higher temperatures. Feasible injection rates and injection schedules can be derived from the integrated reservoir stability analysis. The methodology developed in the present study allows the determination of optimum strategies for storage reservoir selection and gas injection scheduling by minimizing the gas mixing region.
Underground coal gasification (UCG) enables utilization of coal reserves, currently not economically exploitable due to complex geological boundary conditions. Hereby, UCG produces a high-calorific synthesis gas that can be used for generation of electricity, fuels, and chemical feedstock. The present study aims to identify economically-competitive, site-specific end-use options for onshore- and offshore-produced UCG synthesis gas, taking into account the capture and storage (CCS) and/or utilization (CCU) of produced CO2. Modeling results show that boundary conditions favoring electricity, methanol, and ammonia production expose low costs for air separation, low compression power requirements, and appropriate shares of H-2/N-2. Hereby, a gasification agent ratio of more than 30% oxygen by volume is not favorable from the economic and CO2 mitigation viewpoints. Compared to the costs of an offshore platform with its technical equipment, offshore drilling costs are marginal. Thus, uncertainties related to parameters influenced by drilling costs are negligible. In summary, techno-economic process modeling results reveal that air-blown gasification scenarios are the most cost-effective ones, while offshore UCG-CCS/CCU scenarios are up to 1.7 times more expensive than the related onshore processes. Hereby, all investigated onshore scenarios except from ammonia production under the assumed worst-case conditions are competitive on the European market.
Underground coal gasification (UCG) is an in situ conversion technique that enables the production of high-calorific synthesis gas from resources that are economically not minable by conventional methods. A broad range of end-use options is available for the synthesis gas, including fuels and chemical feedstock production. Furthermore, UCG also offers a high potential for integration with Carbon Capture and Storage (CCS) to mitigate greenhouse gas emissions. In the present study, a stoichiometric equilibrium model, based on minimization of the Gibbs function has been used to estimate the equilibrium composition of the synthesis gas. Thereto, we further developed and applied a proven thermodynamic equilibrium model to simulate the relevant thermochemical coal conversion processes (pyrolysis and gasification). Our modeling approach has been validated against thermodynamic models, laboratory gasification experiments and UCG field trial data reported in the literature. The synthesis gas compositions have been found to be in good agreement under a wide range of different operating conditions. Consequently, the presented modeling approach enables an efficient quantification of synthesis gas quality resulting from UCG, considering varying coal and oxidizer compositions at deposit-specific pressures and temperatures.
How insoluble inclusions and intersecting layers affect the leaching process within potash seams
(2021)
Potash seams are a valuable resource containing several economically interesting, but also highly soluble minerals. In the presence of water, uncontrolled leaching can occur, endangering subsurface mining operations. In the present study, the influence of insoluble inclusions and intersecting layers on leaching zone evolution was examined by means of a reactive transport model. For that purpose, a scenario analysis was carried out, considering different rock distributions within a carnallite-bearing potash seam. The results show that reaction-dominated systems are not affected by heterogeneities at all, whereas transport-dominated systems exhibit a faster advance in homogeneous rock compositions. In return, the ratio of permeated rock in vertical direction is higher in heterogeneous systems. Literature data indicate that most natural potash systems are transport-dominated. Accordingly, insoluble inclusions and intersecting layers can usually be seen as beneficial with regard to reducing hazard potential as long as the mechanical stability of leaching zones is maintained. Thereby, the distribution of insoluble areas is of minor impact unless an inclined, intersecting layer occurs that accelerates leaching zone growth in one direction. Moreover, it is found that the saturation dependency of dissolution rates increases the growth rate in the long term, and therefore must be considered in risk assessments.