**3. Case Study**

The presented modelling study is a working example of how to set up and populate a 3D coupled thermal-hydraulic-mechanical model of an underground gas storage site. The case study reservoir is a depleted gas reservoir located about 65 km east of Munich in the Central Molasse Basin. It is an anticlinal structural trap bounded by a normal fault. The reservoir formation is mainly Early Cenozoic Chattian sand, with 85-m thick, three gasbearing layers, found at a depth of 1770 m (1200 m below sea level). The initial gas-water contact is at 1239 m below sea level (BSL). The reservoir has produced 528 million m3 of gas over 18 years from 1958 till 1976; replenishment started in 1978 and has continued to the present, and the reservoir has not been in operation to date [10]. The modelling study uses pore pressure development during the production history and subsequent shut-in phase to calibrate the dynamic reservoir fluid model.

The 3D MEM model is built using a hydraulic model (green area in Figure 1), which comprises a high-resolution reservoir section and regions of lower resolution away from the reservoir section, called the sideburden, overburden, and underburden sections. Topography is extracted from the elevation maps of the ground level to include the top surface of the model. The horizons bounding the reservoir are used to make overburden layers and underburden layers. The basal unit of the model comprises crystalline basement rocks at a depth of about 5 km. However, as none of the wells has reached this depth, this information is inferred from regional geological knowledge. The final 3D THM model consists of 12 horizons and 11 lithostratigraphic units with dimensions of about <sup>30</sup> × <sup>24</sup> × 5 km3 in the X, Y, and Z directions, respectively. The grid of the THM with the reservoir model embedded is shown in Figure 1. The higher resolution in the area of interest (reservoir) and the lower resolution outside make up a grid that creates balance between simulation precision and computational demand. The initial pore pressures and elastic properties are upscaled and interpolated from the 1D MEM's. The calculated and calibrated log-derived properties, including pore pressure, Young's modulus, Poisson's ratio, and density, are upscaled from the well locations to the entire model domain. The Kriging interpolation method is used to populate the 3D geomechanical model. The precision is of course decreasing away from the wells, but the model fits well with overall trends.

**Figure 1.** Reservoir model proper embedded in 3D geomechanical model with reservoir, overburden, underburden, and sideburden zones: (**a**) is the top view, and (**b**) is the oblique view, the arrows represent north direction [10].

Further details regarding the model setup, population of the model from 1D MEMs, history match, etc., are explained in our previous publication [10]. The starting point of the

further modelling study in the following sections is the state after the replenishment phase, achieved by a history match of the production and pressure data from the production and subsequent shut-in phases, respectively.

#### **4. Modelling**

#### *4.1. Modelling Scenarios*

The following section describes the dynamic fluid flow models setup for future scenario testing cases designed for short-term (weekly) gas storage operations. The pressure profile of different future testing scenarios can be coupled with and incorporated into the THM model. The concept for these scenario tests is to evaluate geomechanical stresses on the reservoir due to pressure changes with intensive injection/production cycles. There are various models with different short-term cases that have been considered. German data for excess electricity throughout 2017 have also been considered in one case to address the issues of renewable energy aspects. This case implies that the excess of power energy (electricity) in Germany can be stored in underground gas storage with the power-to-gas (PtG) concept, and then the stored gas can be reused for power generation (gas-to-power) when needed. All the cases are summarized in Table 1. The starting pressure point of these future scenario testing cases is the end point pressure of the replenishment phase, i.e., ~15.8 MPa.

**Table 1.** All modelling scenarios with input parameters. WBHP is well bottom hole pressure, WGIR is well gas injection rate, and WGPR is well gas production rate.


Short-term scenario cases represent weekly storage operations. The scenario scheme has been designed to compensate for the excess power produced in a season and to store power-to-gas energy into same underground gas storage. A short-term cycle consists of phases of one week of injection, one week of shut in, two weeks of production, and one week of shut (1wkInj-1wkShut-2wkProd-1wkShut) for one year. During the injection week, gas is injected into the reservoir, which builds up field pressure (but again limited by 18.8 MPa, the upper limit of WBHP); then, one week of shut in maintains the pressure, followed by a two-week production phase to withdraw gas, which drops the field pressure (lower limit constraint to 13.8 MPa), and again a shut in phase to maintain the well bore pressure.

#### *4.2. Case A*

There are three wells considered for this scenario: two wells are vertical wells (X2 and X6), and one is a horizontal well (H1). All the wells have been considered to have the same short-term weekly schedule as discussed above. This case comprises the same schedule as discussed above, but the well water production rate (WWPR) is limited to 5 m3/day to take into consideration the economic aspects of operating the gas storage. The commercial storage industry limits the water production rates to minimize operating costs and enhance economic returns. Therefore, this aspect has also been considered in this case study. The gas rate for injection and production both is 100,000 m3/day. Bottom hole pressure is constrained by an upper limit of 18.8 MPa and a lower limit of 13.8 MPa in cases of injection and production, respectively. The water cut-off is again 5 m3/day in the production phase to limit the production of water from each well.

The FPR profile for this case is shown in Figure 2. The progressive oscillation cycles of FPR are injection (upward) and production (downward) phases. The overall upward trend of FPR from its initial pressure of ~15.39 MPa represents the buildup pressure with each passing schedule cycle.

**Figure 2.** Field pressure (FPR) profiles of all three wells (X2, X6, and H1) with schedule 1wkInj-1wkShut-2wkProd-1wkShut for one year.

The upward trend of FPR throughout the schedule year is due to the well water production rate (WWPR) (Figure 3d), and as a result, the field pressure is not stabilized in such a short time span. To maintain material balance in this scenario, the injection rate should be lowered to the actual production rates of each cycle.

The comparison of the properties of all three wells is summarized in Figure 3. The WBHP of X6 reaches the maximum limit of 18.8 MPa at the end of each injection cycle and drops back to ~15 MPa at the end of the production phase. The WBHP of X2 also shows similar behaviour but at a lower pressure; e.g., it varies between 16 MPa and 17 MPa at the end of each injection phase and drops back to the same level of ~15 MPa. The WBHP behaviour of H1 is however different from that of both X2 and X6. It reaches a maximum value of 16 MPa at the peak injection time and drops to the lowest level of ~14 MPa (Figure 3a). The WGPR behaviour of all three wells is similar with respect to linear increases with each increasing cycle. However, the rates are completely different for each well. The WGPR of well X2 ranges within ~10,000–11,000 m3/day during the initial cycles but reaches up to 18,000 m3/day at the end of the schedule. Contrarily, the WGPR of well X6 ranges within ~5000–6000 m3/day during the initial cycles but reaches up to ~9000 m3/day at the last cycle. An entirely different behaviour of WGPR is exhibited by well H1, showing ~50 m3/day during the initial cycles but reaching up to ~1100 m3/day at the end of the schedule year (Figure 3b).

**Figure 3.** Well properties comparison of the three-well case scenario with the short-term schedule 1wkInj-1wkShut-2wkProd-1wkShut for one year. X2 and X6 are vertical wells, and H1 is the horizontal well: (**a**) well bottom hole pressure (WBHP) of all wells; (**b**) production gas rates (WGPRs) for all three wells; (**c**) injection gas rates (WGIRs) for all three wells and; (**d**) well water production rate (WWPR) for all the wells.

The WGIR profile of each well is completely different from the profile of the WGPR; the WGIR of well H1 shows the highest WGIR rates among other vertical wells (X2 and X6). The WGIR of H1 reaches to the maximum rate of 100,000 m3/day. The WGIR of well X2 and X6 reach a maximum of 40,000 m3/day and 50,000 m3/day, respectively (Figure 3c).

The comparison shows that the horizontal well allows more gas injection and less gas production than the vertical wells and vice versa.

### Results

The modelling results of this case are presented in the form of pore pressure and effective stress changes of the top layer of the reservoir. Two-time steps have been selected for the analyses of changes in pore pressure and effective stresses acting on the reservoir. Time step t1 (16 December 2020) represents the lowest pressure during the production phase of the schedule cycle, and t2 (23 December 2020) indicates the maximum injection pressure. The fluctuations in pore pressure and effective stress on the reservoir during t1 and t2 are the main results of this model.

Figure 4 shows the locations of three wells, which are denoted by H1, X2, and X6. The pore pressures at t1 and t2 for the well H1 are ~15.0 MPa and ~15.3 MPa, respectively, whereas the effective stress values are ~29.3 MPa at t1 and about 29.0 MPa at t2. There is a difference of about ~0.3 MPa for both pore pressure and effective stress from t1 to t2.

The vertical wells X2 and X6 are close to each other; therefore, the differences in the change in pore pressure and effective stress at these well locations are negligible. The values of pore pressure at both well locations at t1 and t2 are about 15.4 MPa and ~15.7 MPa, respectively. The effective stresses at t1 and t2 are ~28.5 and ~28.2 MPa, respectively, at both well locations. There is an increase in pore pressure of ~0.3 MPa from t1 to t2 and a decrease in effective stress of about 0.3 MPa.

**Figure 4.** Pore pressure (*Pp*) and effective stress (*Sef f ec*) changes from t1 (16 December 2020) to t2 (23 December 2020) in the short-term case with three wells (X2, X6, and H1) with a water cut-off rate of 5 m3/day. The arrows show the location of maximum observed fluctuations in *Pp* and *Sef f ec* from t1 to t2. The color scale is in MPa. (**a**) is pore pressure at time t1; (**b**) is pore pressure at time t2; (**c**) is effective stress at time t1; (**d**) is effective stress at time t2.

#### *4.3. Case B*

Three wells are considered for this scenario, two of which are vertical wells (X2 and X6), and one is a horizontal well (H1). All wells are assumed to have the same shortterm weekly schedule as described above. WGIR and WGPR both have same value of 100,000 m3/day; however, they are constrained by the upper limit of BHP of 18.8 MPa and the lower limit of BHP of 13.8 MPa in the cases of injection and production, respectively.

The FPR profile for this case is shown in Figure 5. The progressive oscillation cycles of the FPR are injection (upward) and production (downward) phases. The general trend of the FPR remains within the limits of ~15.85 MPa and ~15.375 MPa during the injection and production phases, respectively.

The comparison of the properties of all three wells is summarized in Figure 6. The WBHP of X6 reaches the maximum limit of 18.8 MPa at the end of each injection cycle and falls back to ~13.8 MPa at the end of the production phase. The WBHP of X2 also shows almost similar behaviour. However, the WBHP behaviour of H1 is different from both X2 and X6. It reaches a maximum value of 17.4 MPa at peak injection time and drops to the lowest level of ~13.8 MPa (Figure 6a). The WGPR behaviour of all three wells is similar in terms of linear increase with each increasing cycle. However, the rates are completely different for each well. The WGPR of well X2 is ~12,000–16,000 m3/day during the initial cycles but reaches up to 24,000 m3/day at the end of the schedule. In contrast, the WGPR of well X6 varies between 14,000 and 15,000 m3/day during the initial cycles and reaches up to 22,000 m3/day at the end of the last schedule cycle. The WGPR of well H1 is entirely different from the other two wells because it shows ~400–500 m3/day during the initial cycles but reaches up to ~70,000 m3/day at the end of the schedule year (Figure 6b).

**Figure 5.** Field pressure (FPR) profile of all three wells (X2, X6, and H1) with schedule 1wkInj-1wkShut-2wkProd-1wkShut for 1 year.

**Figure 6.** Well properties comparison of the three-well case scenario with short-term schedule 1wkInj-1wkShut-2wkProd-1wkShut 1 year. X2 and X6 are vertical wells, and H1 is the horizontal well: (**a**) well bottom hole pressure (WBHP) of all wells; (**b**) production gas rate (WGPR) for all three wells; (**c**) injection gas rate (WGIR) for all three wells and; (**d**) well water production rate (WWPR) for all the wells.

The WGIR profile of each well is completely different from the WGPR profile; the WGIR of well H1 shows the highest WGIR among the other vertical wells (X2 and X6). The WGIR of well H1 reaches the maximum value of 100,000 m3/day. The WGIRs of wells X2 and X6 reach maximum values of 44,000 m3/day and 45,000 m3/day, respectively (Figure 6c). The comparison shows that the horizontal wells allow for higher WGIR and WGPR than the vertical wells under the same WBHP conditions.

The WWPR of well X2 allows a maximum rate of 5 m3/day throughout schedule year, and the WWPR of well X6 also remain constant over the schedule year with a rate of 10 m3/day, while the WWPR of well H1 remains higher, within the range of 250 m3/day to 310 m3/day (Figure 6d).

#### 4.3.1. Results

The modelling results of this case are presented in the form of pore pressure and effective stress changes of the top layer of the reservoir. Two time steps with the greatest fluctuations in pore pressure have been selected. Time step t1 (9 December 2020) corresponds to the lowest pore pressure point, and t2 (23 December 2020) corresponds to the highest pore pressure point of the schedule cycle. The fluctuation in pore pressure and the effective stress on the reservoir during time t1 and t2 are the main results of this model.

Figure 7 shows the locations of three wells, which are denoted by H1, X2, and X6. These three wells are the operating wells for this scenario. The main changes in pore pressure, along with the effective stress, occur around these wells. The pore pressures at t1 and t2 for well H1 are ~15.5 MPa and ~15.4 MPa, respectively, whereas the effective stress values are ~29.1 MPa at t1 and about ~28.7 MPa at t2. There is a difference of about ~0.4 MPa for both pore pressure and effective stress at t1 and t2.

**Figure 7.** Pore pressure (*Pp*) and effective stress (*Sef f ec*) changes from t1 (9 December 2020) to t2 (23 December 2020) in the short-term case with three wells (X2, X6, and H1) without a water cut-off rate of 5 m3/day. The arrows show the location of maximum observed changes in *Pp* and *Sef f ec* from t1 to t2. The color scale is in MPa. (**a**) is pore pressure at time t1; (**b**) is pore pressure at time t2; (**c**) is effective stress at time t1; (**d**) is effective stress at time t2.
