Acid fracturing technique has been widely used in the oil and gas industry for improving the carbonate reservoir permeability. In recent years this chemical stimulation technique is borrowed from the oil and gas industry, employed in the enhanced geothermal systems at Groß Schönebeck, Germany (Zimmermann et al., 2010), and at Soultz-sous-Forêts, France (Portier et. al., 2009). In principle, acid fracturing technique utilizes strong acids that react with acid-soluble rock matrix to non-uniformly etch the fracture surfaces. The permeability-enhancing effect depends upon the degree of surface irregularity after pore-scale acidizing which is affected by the compositional heterogeneity of the reacting rock matirx, fracture aperture heterogeneity, and flow and transport heterogeneity. In order to have an insight into these impacts on the acid etching process with the final goal of determining optimum operating conditions (e.g., acid type and acid injection rate), pore-scale acid-fracturing model is needed. The core components of the pore-scale acid-fracturing model consist in tracking the motion of the fluid-matrix boundary surface induced by acid etching. To date, a number of front tracking approaches (e.g., local remeshing technique, embedded boundary method, immersed boundary method, and level-set method) have been proposed by many researchers in order for moving boundary problems. Each approach has its pros and cons. In this work, we propose employing the phase-field approach as an alternative to the existing front tracking approaches to capture the physically sharp concentration discontinuities across the liquid-solid interface. The developed pore-scale acid-fracturing model includes the Stokes-Brinkmann equations for fluid flow in the fracture-matrix system, the multi-component reactive transport equation for transport of solute species in the rough-walled fracture, and the phase-field equation for the reaction-driven motion of the fluid-matrix boundary surface. The simulation results show that the developed pore-scale acid-fracturing model enables to track recession of carbonate fracture surface by acid etching and to capture the solute concentration jump (w.r.t., Ca²⁺, H⁺, and HCO₃⁻) across the solid-liquid interface.

Reference

Zimmermann, G., Moeck, I. and Blöcher, G., 2010. Cyclic waterfrac stimulation to develop an enhanced geothermal system (EGS) — conceptual design and experimental results. Geothermics, 39(1), pp.59-69.

Portier, S., Vuataz, F.D., Nami, P., Sanjuan, B. and Gérard, A., 2009. Chemical stimulation techniques for geothermal wells: experiments on the three-well EGS system at Soultz-sous-Forêts, France. Geothermics, 38(4), pp.349-359.

The undisturbed or static formation temperature (SFT) is a key objective of the borehole measurements analysis. Conventional methods to estimate SFT require borehole temperature data measured during thermal recovery periods. As such, shut-in conditions should prevail for temperature logging, which can be both economically and technically prohibitive in actual operational conditions, especially for high-temperature boreholes. This study investigates the use of temperature logs obtained under injection conditions for SFT determination by applying a Bayesian inference approach--Markov Chain Monte Carlo (MCMC). In particular, surrogate models are trained using artificial neural networks to replace the original high-fidelity numerical models to save computational effort. The inversion scheme is firstly tested on three different synthetic scenarios where the formation all consists of multiple thermal layers (i.e., the initial geothermal gradient of each layer can be different). The results indicate a significant success of the method in predicting SFT profiles, given that the borehole temperature data and the surrogate model are accurate. In addition, if a fluid loss zone occurs along the borehole, the error of the estimated SFT below the loss zone is likely to increase. Furthermore, errors in the measured data also have a significant impact on the quality of the SFT estimates. For example, if the measurement has an error of ±1°C, the predicted SFT is found to have maximum errors ranging from 16.7 °C to 47.2 °C in the 95% confidence interval. Therefore, high-quality temperature data needs to be used to achieve reliable estimation results, and the uncertainty in the measured data should be integrated into the inversion procedure if possible. Finally, the method was applied to a real-world example where the SFT near the RN-15/IDDP-2 well in Iceland is estimated using drilling temperature data. As mentioned in Friðleifsson et al. 2020, the Reykjanes geothermal system exhibits both conductive and convective heat transport behavior in the formation at different depths. Therefore, this study also investigates different assumptions about the shape of the SFT profile. In one hypothesis, the thermal gradient is constant. In another, the formation consists of multiple layers where the thermal gradients can be different from each other. For each scenario, fluid losses at three reported depths during the drilling are jointly estimated with the SFT. The inversion results show that the predicted fluid losses are almost the same (with differences being less than 0.3%) under the two different hypotheses. However, the estimated SFT values can have much difference (maximum ~80 °C) at depths. Our results will be compared with other studies that use geophysical data to assess the formation temperature around the well. Their implication about the geothermal field around the investigated deep hot well will also be discussed.

Fractures are main flow paths for heat extraction from fractured geothermal systems. The process of injecting cold water to extract hot water from a fractured reservoir results in thermal and poroelastic stresses in the rock matrix. Therefore, these thermo-hydro-mechanical (THM) mechanisms govern the efficiency of an enhanced geothermal system (EGS) operation. Fractures’ aperture is a controlling factor for the heat extraction efficiency. Due to the lack of field and experimental works, a constant aperture is considered for all fractures in previous works. However, insights from outcrop or wellbore shows that there is a possibility of some relationships between fracture length and its aperture. To shed light on the effect of this relationship on the heat extraction efficiency, numerical simulations are conducted on a fully coupled THM manner in which the fracture aperture is controlled by the thermo-poroelastic stress. 100 fractures from a Discrete Fracture Network (DFN) are taken as a basis during simulations. For the sake of the computational efficiency, a two‐dimensional planar model (1000 m × 600 m) is selected. Three types of relationships between fracture length and fracture aperture as constant aperture, linear and power law relationships are considered here. To have a better comparison between different cases, a constant value is used for the summation of the ''fracture length multiplied by fracture aperture'' for these three cases.

Fluid and rock properties are selected from the literature in a way to be a good representative of actual cases. Furthermore, fluid properties dependency on pressure and temperature of the system is implemented through the well-known correlations. Constant pressure is assumed as the boundary condition for the injection and production wells. All fractures within the domain are regarded as internal boundaries, implicitly considering the mass and energy exchange between porous media and fractures. We have constrained the displacement in all normal directions. All boundaries of the modeled domain are no flow for both fluid and heat transmission. The local thermal non-equilibrium theory is adopted to simulate the heat exchange between the rock matrix and the flowing fluid. For rock matrix, the energy transfer process is mainly dominated by the heat conduction and the heat exchange between pore fluid. Simulation results reveals that fracture aperture dependency on fracture length is an important factor for heat extraction efficiency from the fractured geothermal systems and requires future attention to this missing factor in the literature. Considering constant aperture results in the later thermal breakthrough which would affect the techno-economic analysis in comparison to the real field data. Possibility of a linear relationship would eventuate the lowest performance between the examined cases.

Determining fluid flow through natural fractures is an important task in many geoscience-related fields, such as geothermics. In order to estimate crucial parameters of single fractures controlling the flow and flow distribution, for example hydraulic apertures, hydro-mechanical numerical models have been established in recent years in addition to experimental methods. Although models enable a greater variety of analyses, they still require time-consuming processing before and after the simulation.

This study presents a novel workflow for hydro-mechanical modeling of a single fracture, with a particular focus on simplifying and shortening data preparation and calibration. First, a Python code matches laser scans of two fracture surfaces by enabling translation in the x-y-direction, minimizing the average mechanical aperture between the fracture surfaces, and automatically generating an input file for numerical modeling in MOOSE. Hydraulic simulations are conducted representing the fracture as a 2D-domain in a 3D-environment and computing Darcy velocities based on the cubic law. The additional use of an external mechanical contact model enables theoretical deformation of the fracture due to normal stress and thus estimation of flow under different lithostatic pressures representative of depths between 50-5,000 m. Subsequently, a mobile air permeameter is used to obtain calibration data. The entire workflow was tested on a bedding joint in a sandstone block sample (Flechtinger Sandstone, North German Basin).

Initial hydraulic simulations without mechanical stress result in hydraulic apertures between 509 µm and 604 µm depending on the matching type, whereas the measured aperture is 82.2 µm. Consequently, the surfaces are matched by preconditioning of the initial contact area. The best consistency between measured and modelled hydraulic aperture is achieved when the contact area is equivalent to 33.5 % of the fracture surface. In addition, the velocity distribution in the fracture indicates that the flow generally occurs along few preferential pathways that are structurally predetermined by smaller fissures or mineralogically distinct veins characterized by higher mechanical apertures or smoother mineral surfaces. Due to the high proportion of contact area, the flow through the fractures is highly localized. The results of the mechanically deformed fractures illustrate an exponential reduction of the hydraulic apertures with depth. The hydraulic aperture converges at approximately 50 µm which is representative of depths that are significantly larger than 5,000 m.

The change of the pathway distribution and the exponential reduction of hydraulic apertures at increasing contact area seem realistic and are comparable to results of other studies. Although the preconditioned contact area of 33.5 % appears to be very high, initial contact areas of up to 20 % were also found in other studies of the Flechtinger Sandstone. In conclusion, this study displays a less time-consuming workflow compared to conventional methods. In future work, a further adaptation could be achieved by creating the surface scans using the dense image matching (DIM) method, which is more flexible and less cost-expensive as laser scanners.

The CDGP [https://cdgp.u-strasbg.fr], Data Center for Deep Geothermal Energy, was created in 2016 by the LabEx G-Eau-Thermie Profonde (continuing now in ITI GeoT) [https://geot.unistra.fr/], to archive the high-quality data collected in the Upper Rhine Graben geothermal sites and to distribute them to the scientific community for R&D activities, taking Intellectual Property Rights into account. It manages seismological (catalogues, waveforms, focal mechanisms), seismic, hydraulic, geological, and other data related to anthropogenic hazard from different phases of a geothermal project. Up to now, data are related to Soultz-sous-Forêts, Rittershoffen, Vendenheim and Illkirch.

The CDGP was designed (1) as a store to archive and distribute isolated data and (2) as a gateway to access data handled by another datastore. Indeed, other data can be found elsewhere: in official national stores like Minergies [http://www.minergies.fr/en]or InfoTerre [https://infoterre.brgm.fr/], in academic or project-related stores like BCSF-Renass [https://renass.unistra.fr] or GFZ Data Services [https://dataservices.gfz-potsdam.de/portal/], or even using an internal data service like the one provided by the EOST’ seismological data center CDS [https://eost.unistra.fr/plateformes/cds].

A major objective is to give access to data – even outside the CDGP; they are described in metadata records, where links to the resource are set. Access rights can be controlled and granted either by the destination store, or - if requested - by the CDGP. In this latter case, access rules are defined by the center providing data, and access is validated by the CDGP and request is made only if it is granted. Another advantage is to avoid data duplication and therefore disk space, follow-up of updates, access rights management. If possible, these remote data are also provided as the local data to the EPOS Anthropogenic Hazard platform [https://tcs.ah-epos.eu/]

This feature is useful for users who do not need to search for data on several different sites. It is also useful for data providers and centers who wish to make their data known while keeping control of data access, or need to do special actions before giving access to their data.