*7.1. Hydraulic Model*

The results of the hydraulic model show variations in gas saturation at different phases during short-term injection-production cycles. Figure 16 shows that the injectionproduction cycle increases the gas saturation during the later cycles, as more gas is produced with increasing cycles until convergence is reached. This outcome indicates the adoption of high-speed multicycle injection-production in UGS with time. This characteristic of UGS indicates the increase in gas-containing pore space with time and explains encroachment of gas flow continuously into the ground water zone for production in the pore throat development area, as the injection-production cycle increases. Meanwhile, under the wetting function, the water film is concentrated in the small pore space compared to the larger pore space; the storage space occupied by the formation of water and dead gas zones is released by the gas execution. Further analysis of the data shows notable findings on the correlation between the time and the amplitude of the gas saturation increase, as shown in Figure 16.

During injection and production cycles, gas saturation increases from ~35% to ~50% from the first cycle to the sixth cycle. Therefore, it appears that, during multi-cycle injection and production in the pre-UGS gas zone, the pore gas storage space in reservoirs with low permeability generally increases sharply, as evident from the correlation between low permeability and high initial water saturation (according to [6]). Moreover, the higher the relative quantity of liquid phase that is continuously transported and dried during high velocity development, the greater the increase in gas saturation.

**Figure 16.** Gas saturation (%) during injection-production cycles.

The gas injection production capacity tends to improve in the UGS gas zone when gas production is increased during the injection production cycle. Further investigation of the UGS gas zone shows that the degree of gas production also increases with the injectionproduction cycle, but the degree of gas production varies according to the different physical properties and connectivity of the pore spaces [6]. Strong seepage is observed in reservoirs with high permeability, and the gas production and degree of gas recovery are also high under the same injection-production conditions [6].

The gas saturation first decreases in the pre UGS phase and then increases significantly during multi-cycle injection and production, showing the decrease in gas saturation and gas storage space when the gas-drive water zone (gas-water zone, where gas saturation is more dominant) is converted into gas storage. Due to the intrusion of lateral and bottom water, part of the gas storage space is occupied by water during the slow exploitation phase, and a capillary trap for the gas-containing space is also created. Further data show that higher permeability causes water to penetrate, leading to an even greater reduction in gas saturation. During the multi-cycle injection and production phase in UGS, there is no water encroachment, or the part where water encroachment occurs is displaced in the initial gas injection phase of gas storage into the gas-drive water zone. In contrast, under the influence of high velocity injection and production cycle extraction, residual water is produced that is like that in the gas zone before UGS [6]. The experimental analysis shows that the gas-drive water zone is the main expansion zone of the UGS, as the storage space and storage capacity are greatly increased in this gas-drive water zone [6].

The variation of gas saturation in the gas-drive water zone shows the same trends compared to both the trend in the single core experiment and the trends of average gas saturation in the parallel multicore experiment. However, in the multicore parallel experiment, the reduction in gas saturation caused by water encroachment is relatively small [6]. The distinctive feature of reservoir heterogeneity, a formation with high permeability, has a great impact on the water body as it promotes water intrusion, while formations with medium and low permeability are less affected by water intrusion. During high velocity injection and production, the gas preferentially percolates into the high permeability formation, resulting in gas saturation recovery in the high permeability reservoir.

The gas permeability of the reservoir may also decrease due to clay minerals in the reservoir, which may expand when they encounter water, thereby occupying the pore space. For this reason, gas production and gas content are relatively low in the first injection and production cycle. Meanwhile, the gas recovery level and gas production level are low due to lower vertical permeability [6]. Furthermore, gas production and injection increase with increasing permeability.

The transition of the reservoir characteristic of the gas-water transition may indicate that water intrusion is caused not only by exploitation of the gas field but also by the gas storage cycle in the operational phase. In general, the gas saturation decreases both in operational zones of the reservoir and in the gas-water zone. However, the effects of physical properties and heterogeneity, wettability, and capillary pressure of the reservoir make the production mechanism of multicycle injection complex. The relationship between gas and water in the gas-water transition zone tends to be rational, and the gas saturation tends to plateau during multicycle injection production [6]. Alternatively, residual gas and trapped gas are effectively reduced due to the back-and-forth movement of gas and water through the gas-containing spaces, but the changes in gas saturation are small throughout the reservoirs. Conversely, in high-speed injection and production, water is still continuously transported into the pore throat for production, but in gas storage, the main discharge concerns water in the large pore throat because it is difficult to displace water in the micropores. For this reason, gas saturation tends to plateau in the gas-water transition zone. Due to the reduction in water intrusion energy, gas saturation increases slightly in the subsequent phases of injection and production operations.

These results show that low gas saturation and poor recovery are observed in the gas-water transition zone of UGS and that effective exploitation of the gas-water transition zone is affected by reservoir heterogeneity [6]. Therefore, the effective utilization of the gas-containing pore space under the high-speed injection and production conditions of gas storage is significantly different from the utilization of the gas reservoir. For that reason, the optimal design of UGS capacity and calculation of gas storage parameters should be founded on the effective utilization of the gas-containing pore space, as well as on the effective pore space of the reservoir structure in different zones [6].

#### *7.2. THM Coupled Modelling*

The geomechanical approach presented in this paper allows for characterization, from a geomechanical point of view, of the target reservoir in a very understandable way. The coupled simulation of one-way flow and geomechanics (VISAGETM) focuses on understanding the variation in effective stresses due to pressure changes associated with gas injection into the subsurface reservoir. In other words, the focus is on the pore pressure changes during operation. The VISAGETM model is created directly from the geological model and can therefore be considered more accurate in terms of geometry compared to another finite element model, such as an ANSYSTM model. The material properties in the VISAGETM model are scaled up from borehole logs, and their population contains information about the original vertical and horizontal variations. The VISAGETM simulator treats faults as 3D cells with different material parameters in relation to the surrounding rock. The output of the VISAGETM model is continuous through space, and the presence of faults can be detected by an abrupt change in depth at the point of displacement, even if the horizon is technically not present at that point. Therefore, VISAGETM is used for ECLIPSETM-VISAGETM coupling to build a coupled THM model to achieve the desired geomechanical results.

THM coupled modelling involves coupling of static geomechanical model with dynamic fluid (hydraulic) modelling. The geomechanical stresses of the reservoir change in space and time when coupled with pore pressure, either from reservoir history or from future testing scenarios. In general, these dynamic models are based on the concept of effective stress to characterize the effects of pore pressure changes on reservoir and caprock integrity, as well as fault stability. Simplified geomechanical models rely mainly on the concept of effective stress to distinguish the effects of pore fluid changes on reservoir integrity and fault stability. Terzaghi [36] proposed this effective stress concept for soil systems. The result of the increase in pore fluid pressure is equal to the decreased effective stress on the rock mass, and conversely, this concept implies that the effective stress experienced by the rock framework is due to the changes in fluid pressure, with the absolute magnitudes of the principal in situ stresses themselves remaining unaltered.

From a classical point of view from Terzaghi [36], changes in vertical stress can be predicted as the effective vertical stress increases and decreases during withdrawal and injection, while the reservoir stress path effect can clearly distinguish the changes in the effective minimum horizontal stresses. As a result of the increased fluid pressure, the Mohr circle drifts to the left, in turn reducing the diameter of the circle, implying that the fault is under a lower differential stress. The theoretical viewpoint consolidates only the concept of effective stress, and the assumption can be made that the stress path during compression is parallel to the failure envelope rather than towards it [2]. A steeper stress path during the injection process is the result of a small Poisson's ratio, a large Biot coefficient, a large shear modulus, and a shallower reservoir, further causing drift away from the failure envelope.

At the case study reservoir, reactivation of the fault with increasing fluid pressure would not be possible if the stress path could be assumed to be exactly linear to higher fluid pressures. The magnitude of the stress path in the reservoir is an absolute criterion to ensure that the faults are not tapered by pressurization or depressurization. Furthermore, this linear extrapolation of the stress path is obviously only suitable for moderate fluid pressure levels. During pressurization of the system, there are some points at which the horizontal stress becomes the maximum principal stress instead of the vertical stress. This outcome shows that, in the absence of stress path effects, the stress path changes and moves towards the failure criterion.

One of the main aspects of the THM modelling results is the deformation within and outside of the reservoir formation because of injection and withdrawal of fluid/gas in reservoirs. Pressurization and depressurization cause deformations in both the reservoir and the overburden, which are part of the effective results of geomechanical modelling. During overpressure or underpressure, the elastic or non-elastic expansion or contraction of the rock mass causes such deformations. The reactivation of faults and the integrity of the rock may be affected by deformations within the reservoir. In addition, deformations associated with reservoir depletion can also pose a serious problem in terms of casing collapse and can become a major obstacle to subsequent drilling [37].

The main risks related to pressurization and depressurization of a field during injection and withdrawal periods, respectively, are fault reactivation and associated permeable leakages. During gas injection and production phases, reactivation of the fault and associated permeable pathways is one of the main risks associated with pressurization and depressurization. The classical fault model would predict that, as the fault approaches shear reactivation, there will be an increase in fluid pressure that would reduce the effective normal stress on the fault. However, the stability of the fault is significantly affected by the progression of reservoir stresses through the effects on horizontal stress magnitudes. As discussed in the above section, the simulation results of the THM model predict decreases in effective stresses but increases in pore pressure in various short-term storage cases. If this difference in effective stresses and consequently in pore pressures is very small, no significant stress perturbations would occur. However, if this difference is large, i.e., if the pore pressure in the reservoir is large, then there is a high probability of fault reactivation with increasing pore pressure, as described in the above regarding the various fault reactivation cases. Fault reactivation occurs in the reservoir already at 1.25 times the initial pore pressure of the reservoir, indicating that the Mohr circle reaches the failure line at this pressure.

Distinguishing deformations above and at the surface of the reservoir is also important for surface monitoring and for potential reactivation of faults in the reservoir section. These deformations (either elastic or sometimes plastic) occur due to contraction and expansion of the rock mass during over-pressuring and under-pressuring phases. Over- and underpressuring of reservoirs are directly related to large amounts of gas injection and production rates, respectively. For this reason, the upper (18.8 MPa) and lower (13.8 MPa) limits of bottom hole pressure (BHP) are considered, which do not allow the pressure to rise or drop below the designated pressure limits. The deformation caused by this over-pressuring and under-pressuring of reservoirs could initiate fault reactivation and may affect caprock integrity. The significant drop in reservoir pressure due to rapid depletion may damage the casing and induce drilling complications for newly planned wells in the reservoir [37].

This study does not include a sensitivity analysis to determine the stress field or displacement of the ground surface when elastic properties vary. Due to the poor correlation between the mechanical properties of the rock and the porosity in the individual wells, there can be considerable variation in the construction of the static geomechanical model, which can affect the distribution of the mechanical properties, rather than the magnitudes. In contrast, the successive calibration of the sonic logs and the mechanical tests themselves appear to have close correlations, demonstrating their accuracy. However, it is possible that the actual values for Poisson's ratio and Young's modulus may differ slightly from those used in the modelling. There are several studies have already been performed on these parameter studies and the effects of parameter variation on geomechanical stresses and ground surface displacement [38]. Chen (2012) modelled the pressurization of a reservoir at 600 m of depth by 1 MPa using Young's modulus and Poisson's ratio values close to our case study reservoir. This modelling study suggests reducing the stiffness of the reservoir; i.e., reducing the value of Young's modulus from 5 GPa to 3 GPa, the vertical displacement increases from 0.08 to 0.12 mm [38]. Similarly, a reduction in the Poisson ratio from 0.3 to 0.2 results in an increase in the ground surface displacement from 0.11 to 0.13 mm [38]. It should be borne in mind that the sensitivity of these parameters is highly dependent on several different factors, including the depth and size of the reservoir, the stress field, and the properties attributed to the surrounding formations [38]. However, the work presented by Chen gives a rough idea of the types of variations that might be expected from such modelling.

#### **8. Conclusions**

THM modelling provide important results for short term gas storage, e.g., conversion of the former gas field to a storage site with short-term (weekly) injection-production schedules. There have been three cases tested for future scenarios with short-term operations. German surplus energy data from renewable energy sources (such as wind and solar energy) from 2017 have also been incorporated into these future testing cases to implement PtG technology on former gas reservoirs to meet Germany's future energy demand. The operating volumes in these cases are controlled by the upper (18.8 MPa) and lower limits (13.8 MPa) of well bottom hole pressure (WBHP). The results of the coupled THM modelling of these cases show that the maximum difference in pore pressure and subsequently effective stress is observed to be 0.6 MPa among all tested cases.

Fault reactivation analyses are performed on the THM models, which evaluate various gas injection scenarios without any upper limit of WBHP. The quantified stresses are then examined against Mohr–Coulomb failure criterion to estimate fault stability. This goal is achieved by including faults with specific properties in the 3D geomechanical model. The stress state of the 3D cells with fault properties exceeding the shear failure line is observed against different gas injection volumes. Fault reactivation occurred at the gas injection rate of 240,000 m3/day, yielding a value of critical pore pressure. This critical pore pressure was observed to be 1.25 times the original pore pressure, which is equivalent to the WBHP value of 20.25 MPa. With the determination of pore pressure, it is also possible to estimate an upper limit of the gas injection rate for safe storage operation, which in this case study is observed to be in the range between 100,000 and 150,000 m3/day.

In this study, the critical pore pressure is calculated at the well location, whereas the reference location for further studies can be anywhere in the reservoir, and the high permeability of the reservoir can reduce possible differences in the reference sites. Analysis of the case study numerical modelling results shows that a 4-MPa increase in pore pressure would be sufficient to trigger fault failure.

Thermal stresses depend merely upon the thermal-dynamic processes in the system. Therefore, one case (seasonal) has been tested for thermal stress analysis using the same THM model. The original reservoir temperature is 45 ◦C, and the injected gas temperature is set at 25 ◦C. The thermal changes are small (0.5 ◦C) and occur only near and around the wellbore. The thermal effects on stress are not significant in the reservoir, even after injecting 100,000 m3/day of colder gas for about half a year. This outcome suggests that the thermal changes in the short-term cases are negligible to be considered in the analysis

of geomechanical stresses in the reservoir during storage operations. This finding is due to the low operating volumes and short time cycles for injection production (weekly schedule) in short-term cases.

In terms of storage capacity of PtG technologies, the case study storage can store up to maximum of 1,322,400 kWh/d of electricity from renewable or other resources, converting the maximum gas volume of 150,000 m3/day. This amount of energy storage can at least contribute to Germany becoming a greenhouse gas neutral country (GHGND) in 2050, corresponding to an energy demand of 1600 TWh of electricity.

The entire workflow outlined and tested in this study is not site specific but generally applicable to any gas storage in a porous medium including methane, CO2, and hydrogen.

#### *Perspectives*

The modelling schemes described in this study provide a thermal-hydraulic-geomechanical assessment consistent with the observational data presently available. This THM modelling study can be used to assess borehole stability, which can be achieved by analysing the hydraulic and mechanical limits of the borehole walls. Another application of the model can be a fully coupled model, in which geomechanical and hydraulic models are coupled in such a way that both can receive and process the required parameters simultaneously (explained in the last paragraph). This modelling study can also serve as a benchmark for the use of UGS as a seasonal battery for PtG technologies. In this way, the excess energy can be stored as gas in the UGS and later converted back into electricity when needed.

The rock properties of the reservoir have an important influence on the estimated amount of subsidence. For future modelling, it would be useful to conduct detailed rock mechanics experiments with representative samples from the deposits in the region. It is important to have as much reliable data as possible on vertical elevation changes in the region to test different hypotheses related to subsidence. Such data could come from repeated surveys of existing first-order contour lines, GPS, or InSAR observations. In addition, sensitivity analyses or parameter studies to determine the stress field or displacement of the ground surface as elastic properties vary would be useful to understand the reservoir behaviour in response to changes in, for example, Young's modulus or Poisson's ratio.

THM modelling in this study uses a one-way coupling simulation approach. The coupling between dynamic fluid flow and geomechanical simulation can improved by adopting two-way or even fully coupled simulations. Such a simulation means that not only the pore pressure is passed from the fluid flow model to the geomechanical model, but also properties from the geomechanical model, such as porosity, permeability, and rock compressibility, are passed back to the fluid flow model to obtain continuously updated accurate modelling results. Two-way and fully coupled simulation approaches would also be useful to analyse ageing effects in reservoirs due to long- and short-term storage operations.

**Author Contributions:** Conceptualization, M.Z.-U.-A. and A.H.; methodology, M.Z.-U.-A.; software, M.Z.-U.-A.; validation, M.Z.-U.-A. and A.H.; formal analysis, M.Z.-U.-A.; investigation, M.Z.-U.-A.; resources, M.Z.-U.-A.; data curation, M.Z.-U.-A.; writing—original draft preparation, M.Z.-U.-A.; writing—review and editing, A.H.; visualization, M.Z.-U.-A.; supervision, A.H.; project administration, A.H.; funding acquisition, A.H. All authors have read and agreed to the published version of the manuscript.

**Funding:** This research was funded by BMBF (Federal Ministry of Education and Research), grant number 03G0869.

**Data Availability Statement:** Data available in a publicly accessible repository. The data presented in this study are openly available in [TUprints, Darmstadt] at [DOI: 10.26083/tuprints-00022537, CC-BY-SA 4.0 International.

**Acknowledgments:** The authors thank Uniper SE for providing data for this research. We acknowledge the German Federal Ministry of Education and Research (BMBF) for providing financial support for the SUBI research project. In addition, we acknowledge support from the Deutsche Forschungsgemeinschaft (DFG, German Research Foundation) and the Open Access Publishing Fund of the Technical University of Darmstadt.

**Conflicts of Interest:** The authors declare no conflict of interest.
