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Purpose: In high-temperature geothermal fields, interpretation of the dynamic two-phase state inside the production wells under different wellhead conditions are important to effectively use the geothermal heat source. Therefore, the corresponding wellbore models must have the capability to simulate transient flow and energy state in geothermal wellbores, as well as advective and conductive heat and mass interactions with surrounding formation. Methods: In this study, a transient two-phase wellbore model is developed and implemented in the open source software OpenGeoSys, to simulate both flow and energy state in the wellbore, as well as advective and conductive heat and mass interactions with surrounding formation. The model is first verified against analytical solutions and numerical results from the open-source simulator FloWell. The model is then further validated with well logging data from the Yangyi geothermal field in Tibet, China. Results: Based on the simulation results of the parametric analysis, the conductive heat loss of the high-velocity geothermal production well in the Yangyi geothermal field is found to be limited and the influence can be safely neglected after 8 h of discharge. The flash point location in the wellbore moves upwards for 112 m along with the decrease in fluid enthalpy by 200 kJ/kg. In the wellbore shut-in process, the wellhead pressure decreases with decreasing velocity, while the location of the flash point does not change much. After wellbore shut-in, a two-phase state still exists in the closed wellbore, and the temperature profile is dominated by conductive heat exchange with the surrounding formation. Taking into account the impact of the feed zone, the mass flow rate of the ZK203 well in the Yangyi geothermal field increases from 122.87 to 126.26 t/h when the wellhead pressure decreases from 1.26 to 1.18 MPa. Conclusion: The open-source two-phase wellbore model developed and implemented in this work provides preliminary insights into the transition and evolution of the two-phase state in high-temperature production wells considering advective and conductive interactions with the surrounding formation. Highlights: A transient two-phase wellbore model is implemented in OpenGeoSys. The model is validated with well data from Yangyi geothermal field in Tibet, China. Conductive heat loss for high-velocity production geothermal wells can be neglected. The flash point in the wellbore moves upwards with the decreasing fluid enthalpy. Pressure difference between feed zones and the well determines well productivities. [ABSTRACT FROM AUTHOR]

This study investigates the feasibility to repurpose wells from gas production for geothermal closed-loop application in the North German Basin (NGB). The objective for this research topic is to extend the value-added chain of idle wells by re-completion as coaxial deep borehole heat exchangers as an efficient way to produce green energy without drilling new wells by saving the carbon emission and costs of building a new geothermal well. With numerical models of two typical geological settings of the NGB and two different completion schemes, it is possible to simulate the thermal performance over a lifetime of 30 years. The calculated heat extraction rates range from 200 to 400 kW, with maximum values of up to 600 kW. Sensitivity analyses demonstrate that re-completion depth and injection temperature are the most sensitive parameters of thermal output determination. The heat demand around the boreholes is mapped, and heat generation costs are calculated with heating network simulations. The initial production costs for heat are comparable to other renewable energy resources like biomass and competitive against gas prices in 2022. This study highlights available geothermal resources' environmental and economic potential in already installed wells. The application has almost no geological and no drilling risks and may be installed at any idle well location. [ABSTRACT FROM AUTHOR]

Deep borehole heat exchangers (DBHEs) with depths exceeding 500 m have been researched comprehensively in the literature, focusing on both applications and subsurface modelling. This review focuses on conventional (vertical) DBHEs and provides a critical literature survey to analyse (i) methodologies for modelling; (ii) results from heat extraction modelling; (iii) results from modelling deep borehole thermal energy storage; (iv) results from heating and cooling models; and (v) real case studies. Numerical models generally compare well to analytical models whilst maintaining more flexibility, but often with increased computational resources. Whilst in-situ geological parameters cannot be readily modified without resorting to well stimulation techniques (e.g. hydraulic or chemical stimulation), engineering system parameters (such as mass flow rate of the heat transfer fluid) can be optimised to increase thermal yield and overall system performance, and minimise pressure drops. In this active research area, gaps remain, such as limited detailed studies into the effects of geological heterogeneity on heat extraction. Other less studied areas include: DBHE arrays, boundary conditions and modes of operation. A small number of studies have been conducted to investigate the potential for deep borehole thermal energy storage (BTES) and an overview of storage efficiency metrics is provided herein to bring consistency to the reporting of thermal energy storage performance of such systems. The modifications required to accommodate cooling loads are also presented. Finally, the active field of DBHE research is generating a growing number of case studies, particularly in areas with low-cost drilling supply chains or abandoned hydrocarbon or geothermal wells suitable for repurposing. Existing and planned projects are thus presented for conventional (vertical) DBHEs. Despite growing interest in this area of research, further work is needed to explore DBHE systems for cooling and thermal energy storage. [ABSTRACT FROM AUTHOR]

Efficient exploration of geothermal resources is the basis of exploitation and utilization of geothermal resources. In recent years, Geographic Information System (GIS) has been increasingly used for the exploration owing to its power ability to integrate and analyze multiple sources of data related to the formation of geothermal resources, such as geology, geophysics, and geochemistry. Correctly understanding the control effect of evidence factors on geothermal resources is the premise and basis of whether the prediction results of evidence weight model are accurate. Traditionally, the conventional weight of evidence model assume that each evidence factor exerts a uniform controlling effect on the formation and distribution of geothermal resources. However, recent research indicates significant variations in the controlling ability of factors such as faults and granites, influenced by factors like activity levels and crystalline ages. Yet, studies addressing this differential control are lacking. To address this gap, we propose a series of weight of evidence models using abundant geological, geophysical, and geothermal data from the western Sichuan plateau, a high-temperature geothermal hotspot in China. This study aims to investigate the impact of varying controlling abilities of evidence factors on the evaluation model, with faults and granites as a case. Performance metrics include prediction rate, success rate index, receiver operating characteristic curve (ROC) and prediction rate of geothermal well. The findings of this research reveal that the weight of evidence model developed through the methodology outlined in this study exhibits superior performance compared to the conventional weight of evidence model. This superiority is evidenced by higher prediction rates, success indices, prediction rate of geothermal wells, and larger AUC values of ROC. Among these models, the weight of evidence model considering both fault and granite classification have the best performance in model evaluation indicators, with a prediction rate of 22.528 and a success index of 0.015408 in the very high potential area. The prediction rate and success index of the high potential area are 3.656 and 0.0025, respectively, and the prediction rate and success index of the middle potential area are 1.649 and 0.001128, respectively, and the AUC value is 0.808, indicating that the model has good accuracy. In terms of geothermal well prediction, the total prediction rate of geothermal favorable areas based on fault and granite classification evidence weight model is as high as 47.0526. Therefore, when constructing the weight of evidence model, the influence of the difference control of evidence factors on the formation of geothermal resources should be fully considered. These results underscore the effectiveness of the proposed methodology in enhancing the predictive accuracy and reliability of geothermal resource assessment in this study. Based on the prediction results of the weight of evidence model considering both fault and granite classification, four favorable geothermal areas with abundant surface heat display are identified in this paper, namely Kangding, Litang, Batang and Ganzi-Dege. In addition, the relatively weak surface heat display areas such as Jiulong, Daofu, Luhuo and Derong also show high geothermal potential. Some attention should be paid to geothermal exploration in the future. [ABSTRACT FROM AUTHOR]

The Upper Jurassic carbonate aquifer in the German Molasse Basin (S Germany) below Munich is the focus of exploitation of geothermal energy. To implement geothermal wells, meaningful prediction of reservoir quality (e.g., volume, temperature, location of aquifers, porosity, permeability) is required. However, permeability of this aquifer is often highly heterogeneous and anisotropic, as in other karst- and fracture systems. Based on geophysical well logs from six wells, a 3D porosity model, and side-wall cores, we provide a comprehensive characterisation of the reservoir. We investigate the correlation between rock porosity and matrix permeability, and the impact of hyper-facies on fractures and karstification. We locate and analyse hydraulic active zones and compare them with hydraulic inactive zones within equivalent depth ranges, to characterise promising exploration targets. We show that fracture system parameters vary strongly between wells and within a single well. However, we observe local trends between the fracture systems and rock properties. For instance, fracture intensities and compressional wave velocity increase, while porosity decreases, in dolomitic reefal build-ups (massive facies). We observed substantial karstification dominantly within the massive facies. The main indicators for hydraulic active zones in the reservoir seem to be karstification, fractures, and fault zones. Although matrix porosity has neglectable impact on permeability, the identified hydraulic active zones appear more frequently in sections with higher porosity. We conclude, similar to previous studies, that the massive facies is a suitable exploitation target. Despite the favourable conditions within the massive facies, the strongest hydraulic active zones are nevertheless in the bedded facies, often considered as aquitard, directly below the top of the reservoir within the lithostratigraphic group of the Purbeck, at the transition between the Jurassic and the Cretaceous. [ABSTRACT FROM AUTHOR]

In order to better understand the crustal shortening and orogenic uplift in the northeastern margin of the Tibetan Plateau, as well as the geothermal resource effects formed during this process, we used ModEM software to perform 3D MT imaging on broadband magnetotelluric survey points deployed at 710 points in the Gonghe Basin and its surrounding areas. The resistivity model suggests that the Gonghe Basin exhibits a low–high–low overall electrical structure, with high conductivity widely distributed in the middle and lower crust. The resistivity model also reveals a significant discontinuity between high and low resistivity blocks at various depths in the upper and middle crust. These discontinuities are align with the faults observed on the surface related to strong crustal fluctuations, which are connected to high conductors in the middle and upper crust. Using empirical formulas for high-temperature and high-pressure testing of granite, it is estimated that the melting volume of these high conductors ranges from 3 to 43%, demonstrating good "plasticity". These high conductors can act as detachment layers for crustal shortening and deformation during the expansion of the Tibetan Plateau towards the northeast edge and can continuously conduct heat energy upwards, creating a high thermal background in the Gonghe Basin. [ABSTRACT FROM AUTHOR]

The use of cement-based composites (CBC) with high thermal conductivity for geothermal well cementing is extremely important for the efficient development and use of geothermal energy. Accurate prediction of thermal conductivity can save a lot of experimental costs and time. At present, there is no specific calculation model for the thermal conductivity of CBC. In this study, the microstructure, thermal conductivity model and influencing factors of CBC were investigated by experimental tests, theoretical analysis and numerical simulation. The results showed that the cement-based material could be simplified into a two-layer structure of hydrated and unhydrated layers. Mathematical and numerical models based on the coupled Series model and the Maxwell–Eucken model were established to calculate the thermal conductivity for CBC. The mathematical and numerical models were found to be more accurate by comparison with the conventional models and experimental test results. The cubic packing was more favorable than the spherical packing to improve the thermal conductivity of CBC. The plate material had significant anisotropy. The thermal conductivity of CBC showed a rapid decrease followed by a slow decrease, a decrease followed by a slow increase and finally a rapid decrease, a rapid increase followed by an up and down fluctuation and finally a plateau, respectively, with the increase of filler particle diameter, spacing and curing temperature. Based on these results, the effective methods and future research directions were proposed to maximize the thermal conductivity of geothermal well cementing materials in actual engineering applications. The research findings can provide some technical references for the efficient development of geothermal energy and research on CBC with high thermal conductivity. [ABSTRACT FROM AUTHOR]

The Upper Jurassic carbonates are the prime target for deep geothermal exploration in the Molasse basin, South Germany. The carbonates have a thickness of over 500m (1640 ft) and consist of two major facies: (1) bedded marly limestone and (2) massive limestone and dolostone. The massive limestone facies is composed of sponge-microbial biohermal buildups It is considered the main geothermal reservoir facies. Only this facies type may be (1) karstified, (2) dolomitized, and/or (3) faulted and fractured, and therefore can yield very high flow rates of >100 l/sec = 26 gps. The main data source used in this study is the 3D seismic survey of the Freiham geothermal field in the western part of Munich/Germany. Blended in were cutting logs to describe the lithology from 2 wells and borehole image logs from the two geothermal wells. Lithologies derived from these wells were upscaled in support of the seismic interpretation. The study presents an integrated workflow of 3D seismic attribute analysis to analyze the distribution and quantification of reservoir facies (massive limestone) versus non-reservoir facies (bedded marly limestone) per time slice. The attribute "sum of magnitude" is mapped for 9-time slices based on the vertical resolution of the Freiham 3D cube. The seismic facies interpretation is compared with upscaled borehole image facies associations of two geothermal wells. BHI log data is calibrated with an interpretation of the depositional environment based on cutting analysis Reservoir geometries were derived from an outcrop analog study to better understand the 3D seismic facies interpretation and to construct the conceptual depositional model of the Upper Jurassic carbonates. This technique is commonly used in hydrocarbon exploration but is not yet adapted to geothermal projects, which are often based on little data, smaller company sizes, tight budgets, and limited access to specialized geomodelling software and experience. The approach of using 3D seismic attribute analysis presented in this study provides a quantitative subsurface model of geothermal reservoir facies in the Freiham geothermal field. It is quick and straightforward and can easily be applied in the exploration workflow for similar fields and reservoirs. [ABSTRACT FROM AUTHOR]

Fiber optic sensing has gained importance for wellbore monitoring and reservoir characterization in geothermal fields as it allows continuous, spatially highly resolved measurements. Distributed acoustic sensing (DAS) and distributed temperature sensing (DTS) technologies, among others, enable monitoring of flow regimes and heat transport inside the wellbore to describe the dynamical behavior of the reservoir. The technically challenging installation of a permanent fiber optic monitoring system in a geothermal production well over the entire wellbore length was conducted for the first time at the geothermal site Schäftlarnstraße in Munich, Germany. One cable with two DAS fibers, two DTS fibers, and one fiber for a downhole fiber optic pressure/temperature gauge were clamped to ¾-in. sucker rods and installed to 3.7 km measured depth to collect data from the wellbore after drilling, during testing, and during operations. We present DTS profiles during 3 months of well shut-in and show the results of two cold water injection tests conducted to localize inflow zones in the reservoir and to test the performance of the fiber optic setup. A vertical displacement in temperature peaks of approximately 1.5 m was observed during the injection tests, presumably resulting from thermal contraction of the sucker rod–cable setup. This was verified by analyzing the strain information from the DAS records over 1 h of warm-back after cold water injection with the calculated theoretical thermal contraction of DTS of the same period. We further verified the flowmeter measurements with a gradient velocity analysis of DTS profiles during injection. Intake to the major inflow zone was estimated to 93.5% for the first injection test, respective 94.0% for the second, intake of flowmeter was calculated to 92.0% for the same zone. Those values are confirmed by analyzing DTS profiles during the warm-back period after the well was shut. [ABSTRACT FROM AUTHOR]

The 3.1- and 3.7-km-deep FFC-1 and DGE-1 geothermal explorations wells drilled into the Precambrian crystalline basement on the southern margin of the Fennoscandian Shield are evaluated regarding experiences from drilling, geological conditions, and thermal properties. Both wells penetrate an approximately 2-km-thick succession of sedimentary strata before entering the crystalline basement, dominated by orthogneiss, metabasite and amphibolite of the (1.1–0.9 Ga) Eastern Interior Sveconorwegian Province. The upper c. 400 m of the basement is in FFC-1 severely fractured and water-bearing which disqualified the use of percussion air drilling and conventional rotary drilling was, therefore, performed for the rest of the borehole. The evaluation of the rotary drillings in FFC-1 and DGE-1 showed that the average bit life was very similar, 62 m and 68 m, respectively. Similarly, the average ROP varied between 2 and 4 m/h without any preferences regarding bit-type (PDC or TCI) or geology. A bottomhole temperature of 84.1 °C was measured in FFC-1 borehole with gradients varying between 17.4 and 23.5 °C/km for the main part of the borehole. The calculated heat flow varies between 51 and 66 mW/m2 and the average heat production is 3.0 µW/m3. The basement in FFC-1 is, overall, depleted in uranium and thorium in comparison to DGE-1 where the heat productivity is overall higher with an average of 5.8 µW/m3. The spatial distribution of fractures was successfully mapped using borehole imaging logs in FFC-1 and shows a dominance of N–S oriented open fractures, a fracture frequency varying between 0.85 and 2.49 frac/m and a fracture volumetric density between 1.68 and 3.39 m2/m3. The evaluation of the two boreholes provides insight and new empirical data on the thermal properties and fracturing of the concealed crystalline basement in the Fennoscandian Shield Border Zone that, previously, had only been assessed by assumptions and modelling. The outcome of the drilling operation has also provided insight regarding the drilling performance in the basement and statistical data on various drill bits used. The knowledge gained is important in feasibility studies of deep geothermal projects in the crystalline basement in south Sweden. [ABSTRACT FROM AUTHOR]

There are many successful geothermal projects that exploit the Upper Jurassic aquifer at 2–3 km depth in the German Molasse Basin. However, up to now, only P-wave seismic exploration has been carried out. In an experiment in the Greater Munich area, we recorded S-waves that were generated by the conventional P-wave seismic survey, using 3C receivers. From this, we built a 3D volume of P- to S-converted (PS) waves using the asymptotic conversion point approach. By combining the P-volume and the resulting PS-seismic volume, we were able to derive the spatial distribution of the vp/vs ratio of both the Molasse overburden and the Upper Jurassic reservoir. We found that the vp/vs ratios for the Molasse units range from 2.0 to 2.3 with a median of 2.15, which is much higher than previously assumed. This raises the depth of hypocenters of induced earthquakes in surrounding geothermal wells. The vp/vs ratios found in the Upper Jurassic vary laterally between 1.5 and 2.2. Since no boreholes are available for verification, we test our results against an independently derived facies classification of the conventional 3D seismic volume and found it correlates well. Furthermore, we see that low vp/vs ratios correlate with high vp and vs velocities. We interpret the latter as dolomitized rocks, which are connected with enhanced permeability in the reservoir. We conclude that 3C registration of conventional P-wave surveys is worthwhile. [ABSTRACT FROM AUTHOR]

There are many successful geothermal projects that exploit the Upper Jurassic aquifer at 2–3 km depth in the German Molasse Basin. However, up to now, only P-wave seismic exploration has been carried out. In an experiment in the Greater Munich area, we recorded S-waves that were generated by the conventional P-wave seismic survey, using 3C receivers. From this, we built a 3D volume of P- to S-converted (PS) waves using the asymptotic conversion point approach. By combining the P-volume and the resulting PS-seismic volume, we were able to derive the spatial distribution of the vp/vs ratio of both the Molasse overburden and the Upper Jurassic reservoir. We found that the vp/vs ratios for the Molasse units range from 2.0 to 2.3 with a median of 2.15, which is much higher than previously assumed. This raises the depth of hypocenters of induced earthquakes in surrounding geothermal wells. The vp/vs ratios found in the Upper Jurassic vary laterally between 1.5 and 2.2. Since no boreholes are available for verification, we test our results against an independently derived facies classification of the conventional 3D seismic volume and found it correlates well. Furthermore, we see that low vp/vs ratios correlate with high vp and vs velocities. We interpret the latter as dolomitized rocks, which are connected with enhanced permeability in the reservoir. We conclude that 3C registration of conventional P-wave surveys is worthwhile. [ABSTRACT FROM AUTHOR]

Cementing operations in wellbores, especially for long casings, are often challenging and prone to deficiencies when not properly planned and executed. While exploring for and exploiting of geothermal resources at temperatures above the critical point of water was attempted in different drilling projects in recent years, the well design, and especially the procedure to run and cement long production casings became a key challenge for drilling engineers. For the first time, a reverse cementing job for a 2.97 km long production casing in a high-temperature geothermal well could be monitored and analyzed using a combination of permanently installed distributed fiber optic and electronic sensors as well as conventional well logging equipment. Data from the permanently installed sensors were used to monitor and evaluate the cementation process as well as the onset of the cement hydration. Based on the data, the understanding of downhole fluid dynamics during cementation could be improved. Our analysis suggests that the cement was diluted during cement placement and partly lost into the formation. These findings can help to better prepare for future drilling ventures under similar downhole conditions. [ABSTRACT FROM AUTHOR]

Alternative (unconventional) deep geothermal designs are needed to provide a secure and efficient geothermal energy supply. An in-depth sensitivity analysis was investigated considering a deep borehole closed-loop heat exchanger (DBHE) to overcome the current limitations of deep EGS. A T2Well/EOS1 model previously calibrated on an experimental DBHE in Hawaii was adapted to the current NWG 55-29 well at the Newberry volcano site in Central Oregon. A sensitivity analysis was carried out, including parameters such as the working fluid mass flow rate, the casing and cement thermal properties, and the wellbore radii dimensions. The results conclude the highest energy flow rate to be 1.5 MW, after an annulus radii increase and an imposed mass flow rate of 5 kg/s. At 3 kg/s, the DBHE yielded an energy flow rate a factor of 3.5 lower than the NWG 55-29 conventional design. Despite this loss, the sensitivity analysis allows an assessment of the key thermodynamics within the wellbore and provides a valuable insight into how heat is lost/gained throughout the system. This analysis was performed under the assumption of subcritical conditions, and could aid the development of unconventional designs within future EGS work like the Newberry Deep Drilling Project (NDDP). Requirements for further software development are briefly discussed, which would facilitate the modelling of unconventional geothermal wells in supercritical systems to support EGS projects that could extend to deeper depths. [ABSTRACT FROM AUTHOR]

A new method to remove hydrogen sulfide from geothermal fluids during well operation was tested in situ at a geothermal site in Vienna (Austria). For this purpose, ferric iron was added either as granulated iron hydroxide or as FeCl3 solution into a reaction vessel containing the thermal water directly removed from the wells. From the container, the water would be pumped through a particle filter. Physicochemical parameters as well as sulfide were measured constantly over time before and after the filter. It was found that the sulfide was fully removed from the water by both iron additives. While the addition of FeCl3 led first to the formation of black iron(II) sulfide (FeS), which subsequently oxidized in presence of oxygen to Fe(III) hydroxide, no visible change of the granulated iron hydroxide was observed. The reaction time was longer when using the Fe(III) hydroxide additive as compared to the FeCl3 (completed in less than 20 min) but could be enhanced by increasing the amount of added particles. In all experiments the pH was constantly rising during the reaction from about 6.3 to 7.5, which was explained by loss of protons due to purging out of the gaseous H2S. The redox value, which was measured over time, remained rather constant after addition of granulated iron hydroxide (about −350 mV), but strongly increased from −350 mV to −50 mV after adding the FeCl3 suggesting a strong electron-consuming reaction. This can be explained by a two-step reaction: first, the Fe(III) was reduced to Fe(II) by oxidation of either sulfide or thiosulfate to sulfate. Afterward, the Fe(II) oxidized again by dissolved oxygen forming orange Fe(III) hydroxides. The application of the investigated method during operation of geothermal wells could prevent H2S-induced corrosion and would eliminate the toxic effects of this gas. [ABSTRACT FROM AUTHOR]

The North Alpine Foreland Basin in SE Germany is Germany's most active deep geothermal province. However, in its southern and eastern part the basin is considerably overpressured, which is a significant challenge for drilling deep geothermal wells. In this study, we combine drilling data and velocity-based pore pressure analyses with 3D basin modeling to assess the predictability and controlling factors of overpressure in the sub-regional context (area of 80 km × 50 km) around the Geretsried GEN-1 well, a deep geothermal exploration well in the southern part of the North Alpine Foreland Basin in SE Germany. Drilling data and velocity-based pore pressure analyses indicate overpressure maxima in the Lower Oligocene (Rupelian and Schoeneck Formation) and up to mild overpressure in the Upper Oligocene (Chattian) and Upper Cretaceous, except for the hydrostatically pressured northwestern part of the study area. 3D basin modeling calibrated to four hydrocarbon wells surrounding the Geretsried GEN-1 well demonstrates the dominating role of disequilibrium compaction and low permeability units related to overpressure generation in the North Alpine Foreland Basin. However, secondary overpressure generation mechanisms are likely contributing. Also, the impact of Upper Cretaceous shales, which are eroded in the northwestern part of the study area, on overpressure maintenance is investigated. The calibrated basin model is tested against the drilling history and velocity (VSP) data-based pore pressure estimate of the Geretsried GEN-1 well and reveals that pore pressure prediction is generally possible using 3D basin modeling in the North Alpine Foreland Basin, but should be improved with more detailed analysis of lateral drainage systems and facies variations in the future. The results of the study are of relevance to future well planning and drilling as well as to geomechanical modeling of subsurface stresses and deep geothermal production in the North Alpine Foreland Basin. [ABSTRACT FROM AUTHOR]

The beginnings of geothermal implementation research in Poland date back to 1989–1993 when the Mineral and Energy Economy Research Institute of the Polish Academy of Sciences (MEERI PAS) launched the first geothermal installation in the Podhale region, using the reconstructed Bańska IG-1 well. The knowledge acquired during these 30 years has highlighted the importance of geothermal energy—among other things, borehole reconstruction operations and the need for their further refinement. The technologies developed have been used in virtually all geothermal heating systems operating in Poland. Examples of successful reconstruction work include the Bańska IG-1 and Biały Dunajec PAN-1 wells operated by the PEC Geotermia Podhalańska S.A. geothermal company. The Mszczonów IG-1 well, which is operated by the Geotermia Mazowiecka S.A. heating company, has also undergone considerable work almost 24 years after its complete closure. Reconstruction processes can also be important in adapting existing wells for geothermal purposes. After World War II, more than 8000 boreholes deeper than 1000 m were drilled in Poland. They were primarily made for the purpose of geological surveys and hydrocarbon exploration. Some of these boreholes can be adapted for operation in geothermal systems. The paper presents selected methods of reconstructing abandoned, disused (not abandoned and not decommissioned) or damaged boreholes in order to use them in the geothermal water extraction process. Four examples of borehole reconstruction, designed and carried out with the participation of MEERI PAS in Kraków, are discussed in more detail. [ABSTRACT FROM AUTHOR]

The development of the Rittershoffen deep geothermal field (Alsace, Upper Rhine Graben) between 2012 and 2014 induced unfelt seismicity with a local magnitude of less than 1.6. This seismicity occurred during two types of operations: (1) mud losses in the Muschelkalk formation during the drilling of both wells of the doublet and (2) thermal and hydraulic stimulations of the GRT-1 well. Seismicity was also observed 4 days after the main hydraulic stimulation, although no specific operation was performed. During chemical stimulation, however, no induced seismicity was detected. In the context of all field development operations and their injection parameters (flow rates, overpressures, volumes), we detail the occurrence or lack of seismicity, its magnitude distribution and its spatial distribution. The observations suggest the presence of the rock stress memory effect (Kaiser effect) of the geothermal reservoir as well as uncritically stressed zones connected to the GRT-1 well and/or rock cohesion. A reduction of the seismic rate concurrent with an increase of injectivity was noticed as well as the reactivation of a couple of faults, including the Rittershoffen fault, which was targeted by the wells. These results are derived from the homogeneous and consistent catalogue of more than 1300 local earthquakes that is provided. This reference catalogue is based on a standard detection method, whose output was manually verified and improved. The given absolute locations have been computed in a calibrated, geologically realistic 3D velocity model. Our work builds on previous analyses addressing the seismicity induced by the GRT-1 hydraulic stimulation and places the results into a historical context, thus considering the full dynamics of the observed phenomena. This paper also complements existing descriptions of the hydrothermal characteristics of the deep reservoir by providing insights separate from the wells. [ABSTRACT FROM AUTHOR]

The authors have retracted this article (Drews et al. 2019) because some data have been used without the appropriate permissions. Additionally, the funding statement is not complete and the authorship is incorrect. [ABSTRACT FROM AUTHOR]

In the 1950s, a petroleum well in Soultz-sous-Forêts (no 4589; Upper Rhine Graben, France) reached the Lettenkohle (Triassic) at 830 m depth. During the exploration phase at Soultz-sous-Forêts, the first enhanced geothermal system pilot project in the world, the well was core-deepened up to 2227 m into the granitic basement (then renamed EPS-1). The objectives of this deeper well were (i) to explore the granitic fractured reservoir and (ii) provide a precise geological characterization of the Soultz-sous-Forêts horst. This paper presents the first complete core analysis of the sedimentary formations observed in the EPS-1 cores (from the middle Muschelkalk to the Permian) in conjunction with the gamma-ray log description and field works. The detailed descriptions of the geological formations encountered in the well are presented with photo boards displaying the most characteristic facies of each formation, since the wells are rarely cored, especially in the Muschelkalk. This study also aims to describe the gamma-ray log to provide a strong baseline for future geothermal well exploration in this area (or old well reinterpretations). At this time, it is the only available reference for the complete section: Muschelkalk to Permian sedimentary formations. [ABSTRACT FROM AUTHOR]

Integrity issues create challenges for maintaining the production of mature geothermal wells. Such problems are likely to occur in wells designed according to oil and gas standards, without considering the extreme geothermal environment. PT Geo Dipa Energi as the operator of the Dieng geothermal field, one of the longest operated in Indonesia, has experienced this difficulty since acquiring the field. Almost half of the production wells have been abandoned because of casing issues. To increase production, the operator plans to reactivate wells that have been previously abandoned. An initial study was performed to assess the technical feasibility of reactivating wells at Dieng; it included the development of a well assessment methodology including casing design, comprising historical data analysis, identification of well problems, and investigation of well integrity. The study focused on the identification and characterization of two abandoned wells, HCE9B and HCE28B, current casing conditions, limitations, and challenges to perform a well intervention and workover which is realistic, measurable, economic, and technically feasible. The result of this study will be applicable for casing design for future wells. [ABSTRACT FROM AUTHOR]

Fault zones in the Upper Jurassic aquifer of the North Alpine Foreland Basin are generally regions with possibly increased hydraulic properties. They are consequently often part of the geothermal exploration concepts in this area and a primary target for the drilling operation. Data from this aquifer, gathered in pump tests, however, show that only four out of 41 successful wells exhibit hydraulic proof for the presence of such a fault zone in terms of a bi-/linear flow regime. Besides technical effects, also the contrast in hydraulic properties itself, between fault zone and surrounding host rock, can prevent the detection of a fault zone in pump test data. This means a certain threshold has to be surpassed until its effects become clearly visible. A simplified realistic numerical model was constructed and calibrated with pressure data from an exploration site in the south of Munich. This model was then used to observe the presence of linear and bilinear flows in dependence on the Malm aquifers parameter space. Sampling the possible hydraulic property combinations with the help of an HPC (high-performance computing) cluster and automating the detection of the corresponding main flow type allowed to quantify the areas in parameter space where the fault zone-related flow regimes of interest are present. Through the investigation of more than 30,000 combinations between fault zone permeability, matrix permeability, fault zone storage, matrix storage and fault zone thickness, it was found that, in the parameter space of the Malm aquifer, a bilinear flow can be observed for the first time only if the matrix permeability is lower than 2.0 × 10−13 m2, and a linear flow for matrix permeability values below 6.0 × 10−14 m2. Additionally, it was shown that fault zones, which have better hydraulic properties than the surrounding matrix, can indeed be hidden in pumping tests due to the parameter setting. [ABSTRACT FROM AUTHOR]

Although the resources of geothermal energy in Ukraine greatly exceed domestic conventional energy sources, using geothermal heat in the country is still far behind the existing opportunities. Addressing this gap requires a large-scale pre-feasibility assessment with proper account for hydrogeological and economic factors to facilitate identifying the most promising areas of the country for efficient use of geothermal energy. One of the well-known technologies in this field is a geothermal well system (GWS) that combines pumping out thermal waters, extracting heat on the ground, and reinjecting cooled water back to the aquifer. In this study, we created the maps of expected thermal output and profitability of the doublet GWS across Ukraine for minimum and maximum values of depth and flow rate of thermal waters applying analytical methods of heat transfer in saturated rocks in combination with the net present value (NPV) as a generally accepted economic criterion. Map analysis showed that the GWS maximum expected thermal output might reach 5–9 MW in the Black Sea coastal area and steppe Crimea at the flow rate exceeding 1500 m3/day and aquifer depth of 2 km and more. The NPV index is positive for the most part of Ukraine and increases up to 7–17 million € in southern regions of the country. Calculating performance parameters for two potential GWS sites showed a higher thermal output for a GWS in the Black Sea coastal area compared to the site in Transcarpathia but comparable NPV for both sites due to lower installation costs in the western part of the country. [ABSTRACT FROM AUTHOR]

Hydrogeochemical modelling has become an important tool for the exploration and optimisation of deep hydrogeothermal energy resources. However, well-established software and model concepts are often run outside of its temperature, pressure, and salinity ranges. The core of the model codes are thermodynamic databases which contain a more or less complete subset of mineral phases, dissolved species, and gases occurring in geothermal systems. Although very carefully compiled, they should not be taken for granted at extreme conditions but checked prior to application. This study compares the performance of four commonly used geochemical databases, phreeqc.dat, llnl.dat, pitzer.dat, and slop16.dat. The parameter files phreeqc.dat, pitzer.dat, and llnl.dat are distributed with PHREEQC and implement extended Debye-Hückel and Pitzer equations. Thermodynamic data in slop16.dat represent an implementation of the revised Helgeson-Kirkham-Flowers formalism and were converted to be used with the Gibbs Energy Minimizer ChemApp for this work. Test calculations focussed on the solubility for some of the most common scale-forming mineral phases (barite, celestite, calcite, siderite, and dolomite). The databases provided with PHREEQC performed comparatively well, as long as the range of validity was respected for which the corresponding database was developed. While it is obvious to use pitzer.dat at high salinities instead of phreeqc.dat, the range of validity for high temperature is usually not given in the database and has to be checked manually. The results also revealed outdated equilibrium constants for celestite in slop16.dat and llnl.dat and the lack of adequate temperature functions for the solubility constants of siderite and dolomite in all databases. For those two minerals, new thermodynamic data are available. There is, however, a lack of experimental thermodynamic data for scale-forming minerals in low-enthalpy geothermal settings, which has to be addressed for successful modelling. [ABSTRACT FROM AUTHOR]

A wider exploitation of deep geothermal reservoir requires the development of Enhanced Geothermal System technology. In this context, drilling and stimulation of high-enthalpy geothermal wells raise technical challenges. Understanding and predicting the rock behavior near a deep geothermal wellbore are decisive to implement stimulation strategies to reach the couple temperature/flowrate target. Numerical modeling can contribute to enhanced stimulation processes thanks to a better understanding of impact of stress release, pressure changes and rock cooling in the near-wellbore area. In this paper, we use Discrete Element Method (code PFC2D, © Itasca Consulting Group), and more specifically bonded-particle model to capture the thermo-mechanical processes at metric scale. The application case corresponds to the beginning of thermal stimulation at Reykjanes in well RN-15/IDDP-2  (Iceland, IDDP-2 project and H2020 project DEEPEGS). A cold fluid is injected at a depth of 4.5 km where the rock temperature is above 430 °C and the well pressure is around 34 MPa. Since we have site-specific data and logging images after drilling, we attempt to link the simulations with the reality. The numerical results are confronted with incipient interpretation of logging images and with analytical solution to go towards validation of the modeling approach. Numerical results show breakouts and thermally and/or mechanically induced fractures consistent with the analytical solutions. Moreover, the sensitivity analysis on uncertain parameters yields important clues regarding some logging features as, for example, asymmetric damaging or caving. [ABSTRACT FROM AUTHOR]

Two deep wells were drilled at Rittershoffen (Alsace, France) to produce high-temperature fluids to supply heat to a biorefinery. The GRT-2 production well was drilled to a depth of 3196 m MD and was deviated to target a permeable local fault in the granitic basement buried beneath a thick sedimentary cover. The objective of this study is to better understand the permeability of fractured reservoirs within crystalline rocks, focusing on the production well GRT-2. Based on a petrographic and mineralogical analysis of cutting samples, several granitic facies associated with hydrothermal alteration were identified on the basis of the amounts of illite, chlorite, anhydrite, secondary geodic quartz, and oxides. These observations were correlated with various geological and geophysical datasets (gamma ray, porosity, density, electrical resistivity, caliper, borehole image logs, temperature, rate of penetration, and mud losses) to localize and identify permeable fracture zones. In sections where acoustic image logs were not available, such as in the deepest part of the well, the geometries of the fracture zones were interpreted from an oriented caliper log. The caliper log interpretation detected one-third of the fractures detected by acoustic image logs. However, two major fracture sets striking N-S and dipping eastward or westward were observed. Furthermore, a synthetic resistivity log that fits the measured resistivity log relatively well was built using the Archie and Waxman and Smits models. This approach is a proxy for estimating the porosity and the mineralogical changes based on the cation exchange capacity, which is controlled by the chlorite/illite ratio, derived from electrical logs in granitic formations. The correlation of all these results allowed the identification of a resistivity signature of a permeable fracture zone that spatially fits with the temperature signature. The major contribution of this study is the identification of a hierarchy of permeable fractures based on petrophysical signatures. The geophysical signature of fracture zones with low residual permeability exhibits a broad depth extent, whereas the geophysical signature of a highly permeable fracture zone is more localized. Past hydrothermal circulation has enlarged the altered and porous zones around open fractures, and in some cases, intense illitization has plugged these fracture zones and reduced their permeabilities. [ABSTRACT FROM AUTHOR]