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Understanding the mechanical behaviors of granite after thermal treatment under loading and unloading conditions is of utmost relevance to deep geothermal energy recovery. In the present study, a series of loading and unloading triaxial compression tests (20, 40 and 60 MPa) on granite specimens after exposure to different temperatures (20, 200, 300, 400, 500 and 600 °C) was carried out to quantify the combined effects of thermal treatment and loading/unloading stress conditions on granite strength and deformation. Changes in the microstructure of granite exposed to high temperatures were revealed by optical microscopy. The experimental results indicate that both, thermal treatment and loading/unloading stress conditions, degrade the mechanical behaviors and further decrease the carrying capacity of granite. The gradual degradation of the mechanical characteristics of granite after thermal treatment is mainly associated with the evolution of thermal micro-cracks based on optical microscopy observations. The unloading stress state induces the extension of tension cracks parallel to the axial direction, and thus, the mechanical properties are degraded. Temperatures above 400 °C have a more significant influence on the mechanical characteristics of granite than the unloading treatment, whereby 400 °C can be treated as a threshold temperature for the delineation of significant deterioration. This study is expected to support feasibility and risk assessments by means of providing data for analytical calculations and numerical simulations on granite exposed to high temperatures during geothermal energy extraction.

In the present study, we apply our validated stoichiometric equilibrium model [1], based on direct minimisation of Gibbs free energy, to predict the synthesis gas compositions produced by in-situ coal conversion at three European coal deposits. The applied modelling approach is computationally efficient and allows to predict synthesis gas compositions and calorific values under various operating and geological boundary conditions, including varying oxidant and coal compositions. Three European coal deposits are assessed, comprising the South Wales Coalfield (United Kingdom), the Upper Silesian Coal Basin (Poland) and the Ruhr District (Germany). The stoichiometric equilibrium models were first validated on the basis of laboratory experiments undertaken at two different operating pressures by [2] and available literature data [3]. Then, the models were adapted to site-specific hydrostatic pressure conditions to enable an extrapolation of the synthesis gas composition to in-situ pressure conditions. Our simulation results demonstrate that changes in the synthesis gas composition follow the expected trends for preferential production of specific gas components at increased pressures, known from the literature, emphasising that a reliable methodology for estimations of synthesis gas compositions for different in-situ conditions has been established. The presented predictive approach can be integrated with techno-economic models [4] to assess the technical and economic feasibility of in-situ coal conversion at selected study areas as well as of biomass and waste to synthesis gas conversion projects.[1] Otto, C.; Kempka, T. Synthesis Gas Composition Prediction for Underground Coal Gasification Using a Thermochemical Equilibrium Modeling Approach. Energies 2020, 13, 1171.[2] Kapusta et al., 2020[3] Kempka et al., 2011[4] Nakaten and Kempka, 2019

Water has been used as a working fluid injected into the hot reservoirs during the exploitation of deep geothermal energy, therefore, understanding the thermomechanical properties of reservoir rocks after water cooling is essential. For that reason, we have conducted a series of laboratory tests on air and water cooled granites from normal temperature to 600 °C, to reveal the changes in their thermomechanical properties. At 600 °C, the average values of uniaxial compressive strength, elastic modulus and P-wave velocity of water cooled granite decrease by 84.9%, 73.1% and 66.2%, which are 11.0%, 17.0% and 17.7% larger than those of air cooled granite. Through optical microscopic analysis, the microcrack density and average width of water cooled granite increase with thermal temperature and are 4.18 mm/mm2 and 54.62 μm at 600 °C, while the values of air cooled granite are only 1.97 mm/mm2 and 25.16 μm. We thus combined the deterioration of the macroscopic mechanical characteristics of air and water cooled granites with the propagation and development of microcracks. Supported by data from international literature, the changes in the thermomechanical characteristics of granite has been systematically compared to international literature, which is hoped to provide technical support for the geothermal energy exploitation.

In the present study, a pre-existing stoichiometric equilibrium model based on direct minimization of Gibbs free energy has been further developed and applied to estimate the equilibrium composition of synthesis gases produced by the gasification of carbon-rich feedstock (e.g., coal, municipal waste or biomass) in a fixed-bed reactor [1]. Our modeling approach is validated against thermodynamic models, laboratory gasification and demonstration-scale experiments reported in the literature. The simulated 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 compositions derived from feedstock gasification, considering varying feedstock and oxidizer compositions as well as pressures and temperatures. Furthermore, the developed model can be easily integrated with numerical flow and transport simulators to simulate reactive transport of a multi-componentgas phase.[1] Otto and Kempka, Synthesis gas composition prediction for underground coal gasification using a thermochemical equilibrium modeling approach, Energies (in review)

Increasing global energy demand is a central challenge of the 21st century. Apart from renewable energy concepts, sustainable bridging and buffering technologies are needed which simultaneously offer long-term energy supply guarantees. Underground coal gasification (UCG) shows a promising potential to meet these requirements of future energy markets by in situ conversion of coal to a valuable synthesis gas that can be used in various industrial applications. Currently conducted in more than 14 countries worldwide, a main focus of international UCG efforts lies in improved technical control to reach the desired high gas qualities and simultaneously reduce the tar by-product yield as a potential source of groundwater contamination. Referring to an innovative thermodynamic UCG model parameterized with exemplary base-case data from the UCG field trials Hanna-I, Centralia-Partial Seam CRIP (PSC) and Pricetown, we investigated pyrolysis temperature, operating pressure, water influx and gasification agent injection, optimizing synthesis gas heating values and reduced tar production. General best-fit scenarios were performed assuming an idealized UCG reactor. Besides these best-fit simulations, selected worst-case scenarios considering gas losses were tested. Overall, the model results indicate that operational process improvement potentials vary over wide ranges in the order of few percent to more than 50% compared to the examined base cases. In view of selected available literature data, near-zero tar production rates and simultaneous Lower Heating Value (LHV) improvements in the range of ∼2–40% are feasible.

We showcase a flexible, extensible yet efficient framework for reactive transport modelling, including the ability to replace “full physics” geochemical simulations with surrogate models for speedup. Surrogates are data-driven models trained on a set of pre-calculated simulations by means of machine-learning methods. We offer also an input-output-error visualization component for interactive assessment and tuning of their accuracy. Our framework, based on open source or freely available software, makes possible complex reactive transport simulations and ease further research on optimized algorithms to tackle many geoscientific problems.

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.

Utilization of the geological subsurface for production and storage of hydrocarbons, chemical energy and heat as well as for waste disposal requires the quantification and mitigation of environmental impacts as well as the improvement of georesources utilization in terms of efficiency and sustainability. The development of tools for coupled process simulations is essential to tackle these challenges, since reliable assessments are only feasible by integrative numerical computations. We have been developing a flexible numerical simulation framework, providing efficient workflows for integration of data and software packages for coupled process simulations and introduce three case studies to demonstrate its capabilities.

A benchmark study is presented comparing the outcome of two different simulators, the established TOUGH and the modern, more efficient MUFITS, with the purpose to evaluate the coupling of geochemical processes to multiphase flow in the context of subsurface CO2 storage. The results of the two simulators are in excellent agreement. The implemented simplified one-way coupling is a computationally efficient alternative to fully coupled reactive transport simulations. Every coupled process simulation framework benefits from the inclusion of different tools, which is the only way to enable validation and control of numerical results.

At the Ketzin pilot site 67,000 tonnes of CO2 were injected between 2008 and 2013 into a sandstone formation. Pressure monitor- ing and observation of CO2 arrival in two observation wells provide valuable field measurements for history matching. Modelling of the CO2 injection faces several challenges and uncertainties as discussed in this study. Different approaches towards matching the observed data are presented. It can be shown that a calibration of the simulation models (ECLIPSE E100 and Dumux) to the data is possible with good accuracy, while considerable uncertainties in the model parameters remain, to a large amount resulting from strong correlations between permeability and porosity.

In order to simulate the 3D time-lapse seismic response from real data in a consistent manner detailed 3D property models at the Ketzin pilot site were constructed by robustly integrating borehole and 3D reflection seismic data. The spatial CO 2 distribution and the detailed CO 2 density in the reservoir were derived from dynamic flow simulations that had been history-matched to the site monitoring data. Changes in velocity and density after CO 2 injection were estimated utilizing the CO 2 saturation distributions at two repeat times and fluid substitution models. 4D seismic data were generated by convolving the property models at different times with an extracted wavelet. Time-lapse analysis was performed to qualitatively and quantitatively investigate the changes in reflection amplitude after CO 2 injection. Comparison between the synthetic and real data at the corresponding time indicates that the 3D property models were built successfully and model the 3D time-lapse seismic response induced by CO 2 injection. A synthetic experiment with two different source wavelets was implemented to investigate the impact of source non-repeatability on the seismic amplitude anomaly. Analysis shows that the same or similar sources should be used in time-lapse seismic monitoring to minimize the impact of source non-repeatability on the monitoring.

Natural gas from the Zalecze gas field located in the Fore-Sudetic Monocline of the Southern Permian Basin has been produced since November 1973, and continuous gas production led to a decrease in the initial reservoir pressure from 151 bar to about 22 bar until 2010. We investigated a prospective enhanced gas recovery operation at the Zalecze gas field by coupled numerical hydro-mechanical simulations to account for the CO 2 storage capacity, trapping efficiency and mechanical integrity of the reservoir, caprock and regional faults. Dynamic flow simulations carried out indicate a CO 2 storage capacity of 106.6 Mt with a trapping efficiency of about 43% (45.8 Mt CO 2 ) established after 500 years of simulation. Two independent strategies on the assessment of mechanical integrity were followed by two different modeling groups resulting in the implementation of field-to regional-scale hydro-mechanical simulation models. The simulation results based on application of different constitutive laws for the lithological units show deviations of 31% to 93% for the calculated maximum vertical displacements at the reservoir top. Nevertheless, results of both simulation strategies indicate that fault reactivation generating potential leakage pathways from the reservoir to shallower units is very unlikely due to the low fault slip tendency (close to zero) in the Zechstein caprocks. Consequently, our simulation results also emphasise that the supra-and subsaliniferous fault systems at the Zalecze gas field are independent and very likely not hydraulically connected. Based on our simulation results derived from two independent modeling strategies with similar simulation results on fault and caprock integrity, we conclude that the investigated enhanced gas recovery scheme is feasible, with a negligibly low risk of relevant fault reactivation or formation fluid leakage through the Zechstein caprocks. © Ł. Klimkowski et al.

Pilot-scale CO 2 storage has been performed at the Ketzin pilot site in Germany from 2007 to 2013 with about 67 kt of CO 2 injected into the Upper Triassic Stuttgart Formation, focussing on efficient monitoring and long-term prediction strategies. We employed inverse modelling to revise the latest static geological reservoir model, considering bottomhole well pressures observed during hydraulic testing. Simulation results exhibit very good agreement with the observations, providing one reasonable permeability realization for the Ketzin pilot site near-well area. Furthermore, an existing hypothesis on the presence of a low-thickness sandstone channel between two wells is supported by our findings.

At the Ketzin pilot site for geological CO2 storage, about 67,000 tons of CO2 were injected during the period June 2008 – August 2013. Since August 2013, the site is in its post-closure phase. Before and during the injection phase, a comprehensive monitoring programme was established. In the early post-injection phase, a majority of the monitoring activities have continued. The stepwise abandonment of the pilot site, which is planned to be accomplished in 2018, marks also the termination of most monitoring activities. Four 3D seismic surveys were acquired between 2005 and 2015 for characterizing the reservoir structure and its overburden and for monitoring the propagation of the injected CO2 in the storage formation. The first and second repeat surveys revealed the lateral extension of the CO2 plume after injecting 22 and 61 ktons, respectively. In autumn 2015, the third 3D repeat seismic survey, serving as the first post-injection survey, was acquired. The survey was acquired using the same acquisition geometry as for previous surveys, consisting of 33 templates with five receiver lines and twelve source profiles perpendicular to the receiver lines. Seismic processing of the recently acquired data has resulted in preliminary observations which can be summarized as follows: As in previous seismic repeat surveys, a clear CO2 signature is observed at the top of the storage formation. No systematic amplitude changes are observed above the reservoir which might indicate leakage. Compared to the second repeat survey acquired in 2012, the lateral extent of the CO2 plume seems to have been reduced, which may be an indication for ongoing (and relatively fast) dissolution of the CO2 in the formation brine and diffusion into very thin layers indicating pressure release.

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.

UCG facilitates deep-seated coal seam utilization in the Jamalganj deposit (Bangladesh) by producing synthesis gas for electricity and fertilizer production. Based on previous studies which assessed UCG combined with carbon utilization in a urea process, we further investigated excess CO 2 utilization by means of enhanced gas recovery (EGR) at the Bahkrabad gas field. Our techno-economic modeling results demonstrate that an economic and carbon neutral UCG operation with urea production and EGR is feasible. Thus, this approach introduces a bridging technology that can tackle Bangladesh's fertilizer and power supply shortages in addition to increasing gas recovery from Bangladesh's depleting natural gas deposits.

Comprehensive knowledge gained through the application of a unique and multidisciplinary monitoring program at the Ketzin pilot site has been largely integrated into the development of a site-specific static geological model. Although dynamic modelling results have demonstrated good conformity with the field observations thus far, the long-term fate of CO2 remains uncertain. This is due to the lack of sufficient data regarding the geological characteristics of the far-field region in the reservoir. In this paper, the authors describe a methodology to quantify these uncertainties in order to perform a site-specific risk assessment for the post- closure period.

The TOPS project takes a radical and holistic approach to coupled UCG-CCS, and thus the site selection criteria for the coupled processes, considering both geological, reservoir and process engineering aspects and different end-uses of the produced synthetic gas in order to optimise the whole value chain. In particular, the experimental research carried out utilises a newly constructed high pressure gasification reactor investigating several prospective options of UCG technology implementations. Integrated research addresses field based technology knowledge gaps, such as cavity progression and geomechanics, potential groundwater contamination and subsidence impacts, together with research into process engineering solutions in order to assess the role/impact of site specific factors and selected reagents on the operability of given CO2 emission mitigation options. Ultimately, research aims to minimise the need for on-site CO2 storage capacity as well as maximising the economic yield of UCG through value added end products.

This paper presents the outcome of a feasibility study on underground coal gasification (UCG) combined with direct carbon dioxide (CO2)capture and storage (CCS) at a selected site in Bulgaria with deep coal seams (>1,200 m). A series of state-of-the-art geological,geomechanical, hydrogeological and computational models supported by experimental tests and techno-economical assessments have been developed for the evaluation of UCG-CCS schemes. Research efforts have been focused on the development of site selection requirements for UCG-CCS, estimation of CO2 storage volumes, review of the practical engineering requirements for developing a commercial UCG-CCS storage site, consideration of drilling and completion issues, and assessments of economic feasibility and environmental impacts of the scheme. In addition, the risks of subsidence and groundwater contamination have been assessed in order to pave the way for a full-scale trial and commercial applications. The current research confirms that cleaner and cheaper energy with reduced emissions can be achieved and the economics are competitive in the future European energy market. However the current research has established that rigorous design and monitor schemes are essential for productivity and safety and the minimisation of the potential environmental impacts. A platform has been established serving to inform policy-makers and aiding strategies devised to alleviate local and global impacts on climate change, while ensuring that energy resources are optimally harnessed.

Underground Coal Gasification (UCG) technology is steadily improving due to high scientific and industrial efforts in currently over 14 countries worldwide. A fundamental UCG objective refers to syngas production for multiple end-uses, accompanied by environmental impact mitigation focusing contaminant reduction. In terms of this topic, the control of groundwater quality endangering tars has been a key problem rarely addressed in UCG publications so far. Considering UCG main sub-processes, operating parameters and tar spectrum knowledge grounded upon established thermodynamic equilibrium principles, an innovative and flexible model approach for coupled gas quality-tar production balances is presented here. The model is validated against literature data of the Hanna-I and Centralia-Partial Seam CRIP (PSC) field trials. For both trials good matching results were found. Main gas compounds and Lower Heating Values (LHVs) results are close to reported data partly reaching less than 10% deviation (relative error range for main compounds 4.32–18.6%, LHV 6.60–21.7%). Tar literature trend-modeling comparisons down to the single pollutant scale are addressed for the first time considering published data. Results here successfully reflect main qualitative tar tendencies, while current quantitative prognoses are on a satisfactory level, and expected to be further improved with the availability of more comprehensive in-situ data.

The Division Energy, Resources & the Environment (ERE) of the European Geosciences Union (EGU) provides an international platform for scientists from a wide range of fields with the common denominator that their research topics have high societal relevance. The ERE community develops approaches for the solution of global economic prosperity, environmental quality and political stability based on interdisciplinary research on adequate and reliable supplies of affordable energy and other resources in environmentally sustainable ways. This special issue presents contributions of the ERE division at the EGU General Assembly in 2016. Konferensartikel i tidskrift

We give an overview of the MUFITS reservoir simulator capabilities for modelling subsurface carbon dioxide storage using the EOS-modules GASSTORE and BLACKOIL. The GASSTORE module covers solid-liquid-gas flows of water, carbon dioxide and salt components, and includes an option for automatic generation of the BLACKOIL PVT tables. We test the simulator against several benchmarking studies and then consider an application case of CO 2 storage at the Ketzin pilot site, Germany. The modelling results are in excellent agreement with those produced with common scientific and standard industrial simulators.

The Ketzin pilot site, led by the GFZ German Research Centre for Geosciences, is Europe’s longest-operating on-shore CO2 storage site with the aim of increasing the understanding of geological storage of CO2 in saline aquifers. Located near Berlin, the Ketzin pilot site is an in situ laboratory for CO2 storage in an anticlinal structure in the Northeast German Basin. Starting research within the framework of the EU project CO2SINK in 2004, Ketzin is Germany’s first CO2 storage site and fully in use since the injection began in June 2008. After 39 months of operation, about 53,000 tonnes of CO2 have been stored in 630–650 m deep sandstone units of the Upper Triassic Stuttgart Formation. An extensive monitoring program integrates geological, geophysical and geochemical investigations at Ketzin for a comprehensive characterization of the reservoir and the CO2 migration at various scales. Integrating a unique field and laboratory data set, both static geological modeling and dynamic simulations are regularly updated. The Ketzin project successfully demonstrates CO2 storage in a saline aquifer on a research scale. The results of monitoring and modeling can be summarized as follows: (1) Since the start of the CO2 injection in June 2008, the operation has been running reliably and safely. (2) Downhole pressure data prove correlation between the injection rate and the reservoir pressure and indicates the presence of an overall dynamic equilibrium within the reservoir. (3) The extensive geochemical and geophysical monitoring program is capable of detecting CO2 on different scales and gives no indication for any leakage. (4) Numerical simulations (history matching) are in good agreement with the monitoring results.

The injection of CO 2 at the Ketzin storage site and the chemical detection of its arrival in the observation well allowed testing of different numerical simulation codes. ECLIPSE 100 (E100, black-oil simulator), ECLIPSE 300 (E300, compositional CO 2 STORE) and MUFTE-UG were used for predictive modelling applying a constant injection rate of 1 kg s −1 CO 2 and for a history match applying the actual variable injection rate which ranged from 0 to 0.7 kg s −1 and averaged 0.23 kg s −1 . The geological model applied, is based on all available geophysical and geological information and has been the same for all programs. The results of the constant injection regime show a good agreement among the programs with a discrepancy of 21–33% for the CO 2 arrival times. However, it is determined from the comparison of the cumulative mass of CO 2 at the time of CO 2 arrival that the injection regime is an important factor for the accurate prediction of CO 2 migration within a saline aquifer. Comparing the actual variable injection regime with the simulations applying a constant injection rate the results are relatively inaccurate. Regarding the actual variable injection regime, which was evaluated using all three simulators, the computational results show a good agreement with the data actually measured at the first observation well. Here, the calculated arrival times exceeded the actual ones by 8.1% (E100), 9.2% (E300) and 17.7% (MUFTE-UG). It can be concluded that irrespective of the deviations of the simulations, due to combinations of different codes and slight differences in input parameters, all three programs are well equipped to give a reliable estimate of the arrival of CO 2 . Deviations in the results mainly occur due to different input data and grid size choices done by the different modelling teams working independently of each other. Deviations of the simulations results compared to the actual CO 2 arrival time result from uncertainties in the implementation of the geological model, which was set up based on well log data and analogue studies.

Underground mining causes costly subsidence damage world-wide. In the 1980s German mining research developed stowage techniques using mining wastes during longwall mining operations. These were applied successfully, but not continuously because of economic considerations at that time. A combined technique for subsidence reduction, mining waste disposal and CO 2 storage is being developed within the study presented. Oedometer tests conducted on pumpable mining waste suspensions with various moisture contents reveal useful compression characteristics making them suitable for stowing materials in excavated areas. Laboratory CO 2 adsorption experiments on these wastes show remarkable CO 2 sorption capacities in comparison with residual coal seams. The combination of CO 2 storage and subsequent stowage can lead to a cost-effective way of subsidence reduction determined by the growing prices of CO 2 emission certificates and restricting regulations with regard to CO 2 emissions.

Demonstrating conformity between observed and simulated plume behaviour is one of the main high-level requirements, which have to be fulfilled by an operator of a CO 2 storage site in order to assure safe storage operations and to be able to transfer liability to the public after site closure. The observed plume behaviour is derived from geophysical and/or geochemical monitoring. Repeated 3D seismic observations have proven to provide the most comprehensive image of a CO 2 plume in various projects such as Sleipner, Weyburn, or Ketzin. The simulated plume behaviour is derived from reservoir simulation using a model calibrated with monitoring results. Plume observations using any monitoring method are always affected by limited resolution and detection ability, and reservoir simulations will only be able to provide an approximated representation of the occurring reservoir processes. Therefore, full conformity between observed and simulated plume behaviour is difficult to achieve, if it is at all. It is therefore of crucial importance for each storage site to understand to what degree conformity can be achieved under realistic conditions, comprising noise affected monitoring data and reservoir models based on geological uncertainties. We applied performance criteria (plume footprint area, lateral migration distance, plume volume, and similarity index) for a comparison between monitoring results (4D seismic measurements) and reservoir simulations, considering a range of seismic amplitude values as noise threshold and a range of minimum thickness of the simulated CO 2 plume. Relating the performance criteria to the noise and thickness threshold values allows assessing the quality of conformance between simulated and observed behaviour of a CO 2 plume. The Ketzin site is provided with a comprehensive monitoring data set and a history-matched reservoir model. Considering the relatively high noise level, which is inherent for land geophysical monitoring data, a reasonable conformance between the observed and simulated plume behaviour is demonstrated.

In geological underground utilization, operating and abandoned wells have been identified as main potential leakage pathways for reservoir fluids. In the scope of the well abandonment procedure currently carried out at the Ketzin pilot site for CO2 storage in Germany, we implemented a hydro-mechanical wellbore model to assess the integrity of the entire wellbore system. Thereto, we investigated the impacts of stress changes associated with site operation and abandonment, including the final casing removal and cement backfill to be undertaken for well abandonment. Simulation results show a high unlikeliness of potential formation of fluid leakage pathways in the wellbore system.

Coupled thermo-mechanical simulations were carried out to quantify permeability changes in representative coal measure strata surrounding an underground coal gasification (UCG) reactor. Comparing temperature-dependent and -independent rock properties applied in our simulations, notable differences in rock failure behavior, but only insignificant differences in spatial permeability development are observed. Hence, temperature-dependent parameters are required for simulations of the close reactor vicinity, while far-field models can be sufficiently determined by temperature-independent parameters. Considering our findings in the large-scale assessment of potential environmental impacts of UCG, representative coupled simulations based on complex thermo-hydro-mechanical and regional-scale models become computationally feasible.

The joint project CO2MAN (CO2 Reservoir Management) was a scientific programme accompanying geological CO2 storage at the Ketzin pilot site in the German Federal State of Brandenburg. The project which was funded by the German Federal Ministry of Education and Research (BMBF) from 1 September 2010 to 31 December 2013 enclosed six scientific institutions and seven industry partners. The Ketzin pilot site is the longest-operating on-shore CO2 storage site in Europe. In advance of the CO2MAN project, CO2 injection had already started in June 2008 and storage operation had been accompanied by one of the world’s most extensive scientific research and development programmes. The CO2MAN project took advantage of this unique potential of the site in order to answer further technical and scientific questions on CO2 storage and to inform about this highly debated technology. The CO2MAN project demonstrates safe geological CO2 storage at the Ketzin site on a pilot scale.

CO2 storage is feasible and further demonstration projects are needed CO2 storage at the EGU general assembly 2012 Preface

Underground methane (CH4) gas storage offers capacity and state of the art technology to temporarily store and reuse wind and solar energy. Carbon dioxide (CO 2 ) for methanation can be readily provided in the same way and used in a closed cycle with CO 2 separation at the power plant. With enhanced gas recovery employed, CH4 and CO 2 could be placed in the same reservoir to be mutually working and cushion gas for each other. Selected gas storage sites of Germany show that they already have the potential to take up 20-60% of the 90-270 TWh excess energy estimated for 2050.

Underground coal gasification (UCG) facilitates the utilization of deep-seated coal seams that are economically not exploitable via conventional mining. A techno-economic model was developed to examine UCG cost effectiveness converting coal into a synthesis gas to fuel a combined cycle gas turbine power plant (CCGT) with subsequent CO2 capture and storage (CCS). Thereby, cost of electricity (COE) determination was exemplified based on a commercial-scale scenario developed for a selected target area in Bulgaria. Based on this approach, the present study discusses the results of one-at-a-time (OAT) and scenario based multivariate uncertainty analyses undertaken to assess COE sensitivity on 14 selected geological, market-dependent and technical model input parameters to quantify the uncertainties. The results show that geological model input parameters cause a COE variation of up to 2.8%, revealing a lower influence on COE than the technical components of the CCGT implementation with up to 14%, the synthesis gas composition with up to 9.8% and market-dependent parameters inducing a COE variation of up to 14.3% for CO2 emission charges.

Massive roll-out of renewable energy production units (wind turbines and solar panels) leads to date to excess energy which cannot be consumed at the time of production. So far, long-term storage is proposed via the so called “power-to-gas” technology. Energy is transferred to methane gas and subsequently combusted for power production – “power-to-gas-to-power” (PGP) - when needed. PGP profits from the existing infrastructure of the gas market and could be deployed immediately. However, major shortcoming is the production of carbon dioxide (CO2) from renewables and its emission into the atmosphere. We present an innovative idea which is a decarbonised extension of the PGP technology. The concept is based on a closed carbon cycle: (1) Hydrogen (H2) is generated from renewable energy by electrolysis and (2) transformed into methane (CH4) with CO2 taken from an underground geological storage. (3) CH4 produced is stored in a second storage underground until needed and (4) combusted in a combined-cycled power plant on site. (5) CO2 is separated during energy production and re-injected into the storage formation. We studied a show case for the cities Potsdam and Brandenburg/Havel in the Federal State of Brandenburg in Germany to determine the energy demand of the entire process chain and the costs of electricity (COE) using an integrated techno-economic modelling approach (Nakaten et al. 2014). Taking all of the individual process steps into account, the calculation shows an overall efficiency of 27.7 % (Streibel et al. 2013) with total COE of 20.43 euro-cents/kWh (Kühn et al. 2013). Although the level of efficiency is lower than for pump and compressed air storage, the resulting costs are similar in magnitude, and thus competitive on the energy storage market. The great advantage of the concept proposed here is that, in contrast to previous PGP approaches, this process is climate-neutral due to CO2 utilisation. For that purpose, process CO2 is temporally stored in an underground reservoir. If existing locations in Europe, where natural gas storage in porous formations is performed, were to be extended by CO2 storage sites, a significant quantity of wind and solar energy produced could be stored as methane. The overall process chain is in this case carbon neutral.

Excess electricity from wind and sun can be transformed into hydrogen and with carbon dioxide subsequently into methane. When needed, electricity is regained in a combined cycle plant burning the methane. To close the carbon cycle carbon dioxide is captured on site. Two subsurface storage formations for both gases are required for the technology. Our regional showcase of two German cities, Potsdam and Brandenburg/Havel, demonstrates that about 30% of their electricity demand can be provided in that way, using 17.2% of renewable electricity generated in the State of Brandenburg. The overall efficiency of the system is 27.7%.

Numerical simulations of CO2 migration for the period June 2008-December 2011 were performed based on a unique data set including a recently revised static geological 3D model of the reservoir formation of the Ketzin pilot site in Brandenburg, Germany. We applied the industrial standard ECLIPSE 100 and scientific TOUGH2-MP simulators for this task and implemented a workflow to allow for integration of complex model geometries from the Petrel software package into TOUGH2-MP. Definition of a near- and a far-field well area allowed us to apply suitable permeability modifiers, and thus to successfully match simulation results with pressure measurements and arrival times in observation wells. Coincidence was achieved for CO2 arrival times with deviations in the range of 5.5-15 % and pressure values in the injection well CO2 Ktzi 201/2007 and the observation well CO2 Ktzi 202/2007 with even smaller deviations. It is shown that the integration of unique operational and observation data in the workflow improves the setup of the geological model. Within such an iteration loop model uncertainties are reduced and enable advanced predictions for future reservoir behaviour with regard to pressure development and CO2 plume migration in the storage formation at the Ketzin pilot site supporting the implementation of monitoring campaigns and guiding site operation. © 2013 The Author(s).

At Ketzin, located west of Berlin, the GFZ German Research Centre for Geosciences operates Europe's longest- running on-shore CO 2 storage site. The Ketzin pilot site has been developed since 2004 and comprises three wells to depths of 750 m to 800 m and one shallow observation well, an injection facility and permanently installed monitoring devices. Since June 2008, CO 2 is injected into 630 m to 650 m deep sandstone units (Upper Triassic Stuttgart Formation) in an anticlinal structure of the Northeast German Basin. Until mid of May 2012, about 61,400 t of CO 2 have been stored safely. One of the most comprehensive monitoring concepts worldwide is applied and capable of detecting the behaviour of the CO 2 in the subsurface. The Ketzin project demonstrates safe CO 2 storage in a saline aquifer on a research scale and effective monitoring. This paper summarizes the key results obtained after four years of CO 2 injection.

The available static geological model of the Stuttgart Formation at the Ketzin pilot site was revised based on the re- interpretation of the available 3D seismic data. Using this model three independent modelling groups initiated an intercomparison study using the standard industrial (ECLIPSE 100) and scientific dynamic flow simulations codes (TOUGH2-MP/ECO2N, DuMuX and OpenGeoSys) to employ their strategies for matching of downhole pressure and CO2 arrival times. The current results demonstrate that the introduction of distinct near- and far-well areas with different permeability tensors is required to achieve a reasonable match with the data observed at the Ketzin pilot site.

The present study investigates the time dependency of a UCG (Underground Coal Gasification) reactor cool down process by comparing natural cool down with forced cooling driven by water flushing. The convective heat transport out of the UCG reactor was calculated using an analytical approach coupled to a numerical heat flow model of the geology surrounding the UCG reactor. Our results show that forced cooling by water flushing at flow velocities of 1 m/s can decrease the required time to retain initial in-situ temperature conditions by a factor of more than 300.

Underground coal gasification facilitates the utilization of deep-seated coals that are economically not exploitable via conventional mining. This study examines UCG as an approach for coal conversion into a synthesis gas as substitute for natural gas or to fuel a combined cycle gas turbine with CO2 capture and storage. Modelling results show that implementing UCG-CCS into the Bulgarian energy system depicts a low carbon alternative to coal fired power generation and can potentially decrease Bulgaria's gas import dependency. Both, UCG-CCS and CCS-PP, appear as auxiliary transition strategies to achieve the national and EU targets on CO2 emission mitigation.

CO2 storage in deep saline aquifers is one of the strategies used to reduce greenhouse gas emissions into the atmosphere. However, pressure buildup due to the CO2 injection process and subsequent pressure dissipation alter the recent stress field in and around the reservoir. These stress changes may lead to ground uplift, rock fracturing or fault reactivation. In order to study these phenomena by numerical simulations, flow and mechanical equations have to be solved together, requiring a hydro-mechanical coupling. In the present study, a prospective CO2 storage site located in the Northeast German Basin serves as 3D geological framework for a numerical evaluation of deformations and in situ stress changes induced by CO2 injection into the Middle Bunter sandstone. For that purpose, two open-source simulators are coupled: TOUGH2 (Pruess et al., 1999) is applied to calculate reservoir pore pressures which are subsequently transferred into the hydro-geomechanical simulator OpenGeoSys (Wang et al., 2009) to solve the hydro-mechanical equations. A scenario analysis was undertaken to evaluate the mechanical effects of CO2 injection on the reservoir and caprock stability. The results show that under specific assumptions the vertical movement of the top reservoir is negligible. Furthermore, the changes in the recent stress field predicted by geomechanical modeling are limited to the surrounding of the injection well and not significant enough to endanger the mechanical stability of the reservoir and caprock considering the geological boundary conditions of the study area and the proposed injection scheme The presented study demonstrates the hydro-mechanical effects of CO2 storage in a well-constrained 3D geological regional-scale model based on the characterization of residual rocks, and can therefore be representative for CO2 storage in the Northeast German Basin. References Pruess, K., C.M. Oldenburg, and G. Moridis, "TOUGH2 User's Guide, Version 2.0", Lawrence Berkeley National Laboratory, Berkeley, (1999), pp. 198. Wang W, Kosakowski G, Kolditz O (2009) A parallel finite element scheme for thermo-hydro-mechanical (THM) coupled problems in porous media. Comput Geosci 35(8):1631-1641

Underground coal gasification (UCG) has the potential to increase worldwide coal reserves by utilization of coal deposits not mineable by conventional methods. This involves combusting coal in situ to produce a synthesis gas, applicable for electricity generation and chemical feedstock production. Three-dimensional (3D) thermo-mechanical models already significantly contribute to UCG design by process optimization and mitigation of the environmental footprint. We developed the first 3D UCG model based on real structural geological data to investigate the impacts of using isothermal and non-isothermal simulations, two different pillar widths and four varying regional stress regimes on the spatial changes in temperature and permeability, ground surface subsidence and fault reactivation. Our simulation results demonstrate that non-isothermal processes have to be considered in these assessments due to thermally-induced stresses. Furthermore, we demonstrate that permeability increase is limited to the close reactor vicinity, although the presence of previously undetected faults can introduce formation of hydraulic short circuits between single UCG channels over large distances. This requires particular consideration of potentially present sub-seismic faults in the exploration and site selection stages, since the required pillar widths may be easily underestimated in presence of faults with different orientations with respect to the regional stress regime.

Underground coal gasification is currently being considered as an economically and environmentally sustainable option for development and utilization of coal deposits not mineable by conventional methods. This emerging technology in combination with carbon capture and sorptive CO2 storage on the residual coke as well as free-gas CO2 storage in the cavities generated in the coal seams after gasification could provide a relevant contribution to the development of Clean Coal Technologies. Three hard coals of different rank from German mining districts were gasified in a laboratory-scale reactor (200 g of coal at 800 °C subjected to 10 L/min air for 200 min). High-pressure CO2 excess sorption isotherms determined before and after gasification revealed an increase of sorption capacity by up to 42%. Thus, physical sorption represents a feasible option for CO2 storage in underground gasification cavities. ’INTRODUCTION Deep coal deposits that cannot be economically developed using conventional methods are being currently considered as carbon dioxide sinks in combination with enhanced coal bed methane recovery.1-3 Carbon dioxide storage capacities of these deep deposits mainly depend on their accessibility to carbon dioxide with respect to pore space for free gas storage and surface area for storage by sorption. However, unworked deep coal seams are relatively inaccessible to pore gases, as porosity and permeability of coals tend to decrease with increasing overburden pressure.4,5 Underground coal gasification (UCG) is discussed as an option to circumvent the limitations resulting from low accessibilities by generation of energy in combination with carbon capture and its geological storage (CCS). The general UCG-CCS concept is discussed by many authors, though studies generally have not considered experimental or field data taking into account carbon dioxide sorption capacities.5-12 However, there is an agreement on the suitability of gasified coal seams for carbon dioxide storage (reactor zone carbon storage). Even though this concept has been widely discussed,5,7,13 qualified data on carbon storage capacities in the former reactor zone are not yet available. Sorption capacities of the coal gasification residues and the reactor faces are required for quantitative assessment of total carbon storage potential in coal gasification cavities. The aim of the present study was the determination of carbon dioxide storage capacities of coal gasification residues. For that purpose, representative hard coals were retrieved from deep German hard coal deposits and gasified using a laboratory gasification reactor. Coal properties and carbon dioxide sorption capacities were determined before and after the gasification process to assess the impacts of gasification. As illustrated in Figure 1, the UCG reactor is represented by different zones: the void space (also involving accumulated ash and rubble) and the surrounding coal (char and tars) thermally influenced by the UCG process. By the methodology presented within this study, we investigated CO2 sorption capacities of the coal present close to the reactor wall and the virgin coal (raw coal) present outside the area influenced by the UCG process. These data can be applied for the assessment of CO2 storage potentials in coal seams gasified by the UCG method. ’EXPERIMENTAL SECTION Samples. Samples were taken from three German mines producing Upper Carboniferous coals (mainly of Westphalian age) in the paralic “foredeep” of the Variscan foldbelt. This sequence contains approximately 200 seams within a total sediment thickness of more than 3000 m of clastic rocks (sand-, silt-, and mudstone). The highest percentage of coal within this stratigraphical sequence is reached in the Lower Westphalian B with almost 5%.14 Due to the thickness of the stratigraphic column, the lateral extension, and the complex burial and tectonic history, the coal shows a wide range of ranks from high-volatile bituminous coal to anthracite (vitrinite reflectance from 0.95 to 3.22%). The Westphalian B strata of the Prosper-Haniel mine deliver high-volatile bituminous coal used for power generation (33-38% volatile matter).Here, seams are mined in workings down to 1200 m, while the samples were retrieved at a depth of 915 m. In the Lippe mine;abandoned in 2008; Westphalian C and D with up to 40% volatile matter (high-volatile Received: August

World-wide coal reserves can supply the global demand for primary energy for several centuries. However, low thickness and structural complexity may constrain the economic exploitation of many coal deposits. Taking into account these circumstances, underground coal gasification (UCG) can offer an economical and sustainable approach for coal exploitation and subsequent feedstock generation from the syngas. The UCG process produces a high-calorific synthesis gas mainly consisting of methane, hydrogen and carbon dioxide, which can be used for electricity generation or feedstock production at the surface. Considering the latter, the Urea process can be applied to establish the nitrogen based fertilizer carbamide (CH4N2O). The required feedstock for carbamide production in the Urea process can be supplied by UCG syngas. The aim of the present study was the development of an integrated carbon utilisation concept based on the coupled UCG-Urea process. A significant amount of carbon dioxide from the UCG synthesis gas is required for carbamide production in the Urea process, while the excessive carbon dioxide can be re-injected into the cavities resulting in the coal seams and surrounding strata after the gasification process. Thus, a new approach for utilisation of carbon dioxide resulting from coal combustion was developed to provide a coupled technology also comprising geological storage of excessive carbon dioxide. A theoretical feasibility study considering UCG-Urea process economics and potentials of UCG and carbon dioxide storage in the gasified strata was conducted for a selected study area in northern Bangladesh revealing the high competitiveness of the combined technology on the international feedstock markets.

At the Ketzin pilot site for CO 2 storage, 67 kt of CO 2 were injected between 2008 and 2013 in to a saline aquifer. In October 2014, part of the formerly injected CO 2 was retrieved from the reservoir. 240 t of CO 2 and 55 m 3 of brine were back-produced and an interdisciplinary monitoring accompanied the field experiment. It indicates that a safe CO 2 back-production is feasible and can be performed at both, stable reservoir and wellbore conditions.