Previous studies showed that cloud-fracture networks (CFNs), networks of permeable microfractures densely distributed over rock body, formed in granite at superhot geothermal conditions (> ~400 °C) through the stimulation of pre-existing microfractures by low-viscosity water near and above its critical temperature. The CFNs were also shown to form in granite at conventional (~150 – 300 °C) and superhot geothermal conditions by injection of low-viscosity CO₂, through the same mechanism as that by low-viscosity water at superhot geothermal conditions. The stimulation of pre-existing microfractures by the low-viscosity CO₂ implied that CFNs may be formed in the matrix (i.e., unfractured rock) of naturally-fractured conventional and superhot geothermal environments, where conventional bi-winged hydraulic fractures are known to be difficult to be achieved by injection of cold water. The present study illustrates the possibility of CFN formations in naturally-fractured geothermal environments, along with the shear-slip of the natural fractures, through CO₂-injection experiments into cylindrical granite samples, each contained a sawcut (representing a natural fracture) inclined from the sample axis, under geothermal conditions. The experiments show that CO₂ injection induced a larger cumulative shear displacement on the sawcut at conventional geothermal condition than at superhot geothermal condition. CFNs were formed at conventional and superhot geothermal conditions; nonetheless, the fracture-apertures were thinner for the CFN formed at conventional geothermal condition. The results imply that CFNs may be formed in naturally fractured geothermal environments, and may provide additional fluid-flow paths between the stimulated natural fractures.

How to cite: Pramudyo, E., Goto, R., Sakaguchi, K., and Watanabe, N.: Shear-slip and Complex Fracturing by CO2 Injection in Naturally Fractured Granite at Geothermal Conditions, EGU General Assembly 2023, Vienna, Austria, 23–28 Apr 2023, EGU23-11330, https://doi.org/10.5194/egusphere-egu23-11330, 2023.

Matrix acidification is one of the most popular stimulation techniques to increase the porosity and permeability of reservoir systems. Usually, the thermal-hydro-mechanical properties of reservoir rocks affected by the matrix acidification process are studied using flow-through tests or autoclave experiments. In this study, a novel acidification approach was tested using a thermal triaxial device at the TU Darmstadt laboratory. Thereby, hydrochloric acid 0.0375% (HCl pH=2) was flushed continuously through a total of five Remlinger sandstone samples under reservoir conditions (90^oC temperature, s₁=25 MPa, and s₃=23MPa). Changes in matrix permeability and other petrophysical parameters due to the chemical reaction between the rock sample and HCl were recorded before, during, and after the reactive experiments. In addition, outflow fluid samples were collected and the pH was subsequently measured. After approximately 30 days of continuous flow for each sample, the permeability increased for all the samples, with a maximum increase of 300%. Likewise, porosity increased from 13.2% to 14.5%. In contrast, P- and -S-wave velocities decreased from 2608 to 2189 m‧s^-1 and from 1540 to 1380 m‧s^‑1, respectively. Test results provide important information for reservoir stimulation and can be used to benchmark THMC models.

How to cite: Ramirez, A., Hung, P. T., Weydt, L., and Sass, I.: Long-term matrix acidification experiments under reservoir conditions using the Thermo-Triaxial device, EGU General Assembly 2023, Vienna, Austria, 23–28 Apr 2023, EGU23-13703, https://doi.org/10.5194/egusphere-egu23-13703, 2023.

Shale has been focused because of its potentials in fossil fuel as unconventional reservoirs and in carbon storage as cap rocks. Fluid rock interaction is important for shale study. Because hydraulic fracturing in unconventional oil and gas development and the sealing ability of cap rock are all related to the fluid-rock interaction. The fluid-rock interactions,  such as the spontaneous imbibition (SI), were studied on Wolfcamp Shale core samples in Midland Basin, west Texas in this work. Multiple experiments including X-ray diffraction (XRD), contact angle measurement, scanning electronic microscopy (SEM), and (ultra-) small angle X-ray scattering [(U)SAXS] were performed to characterize the mineralogy, wettability, and pore structure to assist the analysis of the SI data in Wolfcamp Shale. XRD results indicated the Wolfcamp Shale samples were dominated by carbonate and siliciclastics with different sample depths, which is concordant with the well-logging data. The SI experiments were conducted in hydrophilic de-ionized water (DIW) and hydrophobic D2T (a mixture of two parts of decane and one part of toluene). Most samples have layer structure, therefore, the SI experiments were performed in directions that parallel to the layer (P direction) and transverse to the layer (T direction) on each sample. The fitting slopes of SI results show that samples have better pore connectivity in hydrophobic D2T than DIW in both directions. In P direction, the imbibed volume of DIW and D2T are very close to each other, which indicate the Wolfcamp Shale could be more oil wet. (U)SAXS results provided the pore diameter distribution (PDD) of the samples, which separates the samples into two groups. Associated with mineralogy, group 1 is dominated by siliciclastic with pores at 10 nm and 50 nm, and group 2 is dominated by carbonate with pores at 100 nm and 600 nm. Coupled with PDD and mineralogy, the fitting slopes in group 2 in DIW P direction decrease and then increase with clay content with the turning-point at 30%. The micro-fractures and well-aligned clay minerals in SEM images in samples with more clay content could help to form fluid pathways during the DIW imbibition. Such a positive relationship in fitting slopes and clay content also appeared in D2T P direction imbibition. In summary, the experiments conducted on the Wolfcamp Shale in west Texas including SI, XRD, SEM, and (U)SAXS could investigate fluid transport mechanisms in shale to support the studies for unconventional reservoir development and carbon storage.

How to cite: Zhao, C., Hu, Q., Wang, Q., Fan, M., Ilavsky, J., and Wang, M.: Fluid-rock interaction of Wolfcamp Shale: the effects of pore structure and mineralogy, EGU General Assembly 2023, Vienna, Austria, 23–28 Apr 2023, EGU23-7185, https://doi.org/10.5194/egusphere-egu23-7185, 2023.

In the last decades, the enormous potential for direct geothermal heat from aquifers attracted special attention, particularly toward those thermal springs indicating areas in which exploitation of geothermal energy might be economically feasible for indirect uses such as electrical power production. The availability of geochemical data besides the location of thermal spring areas assumes particular importance, especially in the first stages of a geothermal exploration program. In this work, we present a digitised format of the literature review of Gerald Ashley Waring on the geothermal springs of the world. This unprecedented dataset contains geographical coordinates (from georeferentiation) of ~6,000 geothermal spring areas, including complementary data such as temperatures, flow rates, total dissolved solids content (TDS, expressed in ppm), and quantitative chemical analysis of major elements (only for a few hundred sites). Using temperature and flow rate, we derive the heat discharged from 1483 thermal spring areas (between ~10^-5 and ~10³ MW, with a median value of ~0.5 MW and ~8300 MW in total). We complement this information with geological data sets currently available in the literature and analyse them using statistical and geospatial tools and a supervised machine-learning algorithm. We show that terrestrial heat flow, topography, volcanism, and extensional tectonic play a key role in the occurrence of thermal waters around the globe. These results can also be beneficial to address the geothermal interest towards specific and less studied areas and significantly drive the first steps of the geothermal surveys and detailed investigations. Finally, this data set in electronic format will be beneficial for future research on the spatial distribution of thermalism at a small scale and the variation of temperature and flow rate of several thermal springs in the last decades in certain regions.

How to cite: Tamburello, G., Chiodini, G., Ciotoli, G., Procesi, M., Rouwet, D., and Sandri, L.: Global thermal spring distribution and relationship to endogenous and exogenous factors, EGU General Assembly 2023, Vienna, Austria, 23–28 Apr 2023, EGU23-13900, https://doi.org/10.5194/egusphere-egu23-13900, 2023.

Shale is an unconventional oil and gas reservoir with both generation and storage characteristics. Diagenesis has an important impact on its organic petrological characteristics, reservoir physical properties, pore system structure characteristics, mineral component content and transformation. Diagenesis is of great significance for its porosity and permeability analysis, reservoir comprehensive evaluation and shale gas productivity. At present, the researches on diagenesis and diagenetic evolution mainly focus on conventional sandstone reservoir. Because the application of conventional oil and gas reservoir characterization technology to shale reservoir is limited, and the diagenetic characteristics of shale reservoir are difficult to identify, the researches on diagenetic evolution of shale reservoir are relatively weak, and the comprehensive researches on diagenesis and diagenetic evolution of shale reservoir are relatively scarce.

At present, there are mainly two kinds of research methods on the dual effects of thermal evolution and diagenesis of shale: the first is the direct observation method, which uses high-resolution equipment to analyze shale samples with different maturity and diagenesis to determine the characteristics and development differences of diagenesis. However, this method ignores the heterogeneity and regional differences of samples, and cannot show all the evolution characteristics of shale in the diagenesis process. The second is the physical simulation method, that is, the sample of low maturity is selected, the temperature series is set, and the generation of diagenesis process is induced by heating. This method reduces the heterogeneity of samples and the influence of regional differences on the experimental results to a certain extent. It has strong comparability and can provide the overall characteristics in the process of diagenesis. However, the disadvantage is that it lacks intuitive characterization and cannot clearly and intuitively display the diagenetic evolution characteristics of minerals in the same area.

In view of the above problems, the diagenesis and diagenetic evolution of low-mature organic-rich Marine type II shale in the Middle Proterozoic Xiamalin Formation in Zhangjiakou area of Hebei Province were studied by using the method of high temperature and high pressure physical simulation. The characteristics of diagenesis were observed and characterized in the simulated samples, and the types of diagenesis in the simulated products were identified. A conceptual model of shale diagenetic evolution sequence based on physical simulation is established. In addition, this study also uses direct observation method to characterize the diagenetic characteristics of natural marine shales of Xiamaling Formation in this area. Five diagenetic types including compaction, cementation, dissolution, hydrocarbon generation of organic matter and clay mineral transformation are identified, and diagenetic stages of Xiamaling Formation shales are divided. Furthermore, the marine diagenetic evolution sequence and diagenetic evolution model of the Mesoproterozoic Xiamalin Formation in Zhangjiakou area of Hebei Province are established (Fig.1). This study makes up for the deficiency in the study of shale diagenetic evolution, and has important reference and indicative significance for the development of other high-over-mature Marine shale gas reservoirs in China and the world.