Predictability and controlling factors of overpressure in the North Alpine Foreland Basin, SE Germany: An interdisciplinary post-drill analysis of the Geretsried GEN-1 Deep Geothermal Well

The North Alpine Foreland Basin in SE Germany Germany’s most active deep geothermal province. However, in its southern and eastern part the basin is considerably overpressured, which is a signicant challenge for drilling deep geothermal wells. In this study, combine drilling data and velocity-based pore pressure analyses with 3D basin modelling to assess the predictability and controlling factors of overpressure in the sub-regional context (area of 80 km x 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 modelling 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 modelling 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 modelling of subsurface stresses and deep geothermal production in the North Alpine Foreland Basin. Deep Project, approximately 30 km of In this study, the predictability and controlling factors of overpressure in the greater Geretsried area will be analyzed, combining drilling- and velocity data-based well analyses and pore pressure– centric 3D basin modelling. The results will be compared with pore pressure indicators from drilling data and a pore pressure estimate from vertical seismic prole (VSP) data of the Geretsried GEN-1 well. The integration of these methods is the rst of its kind in the North Alpine Foreland Basin in SE Germany, especially in the context of deep geothermal projects in South Germany. The results of this study are of relevance to planning and drilling of future deep geothermal wells in the North Alpine Foreland Basin in SE Germany. Quantication of overpressure is also of signicance to geomechanical studies in the North Alpine Foreland Basin in SE Germany, e.g. considering the prediction of induced microseismicity caused by geothermal exploitation. In addition, the presented methodology and results will be a valuable reference case for other pore pressure studies to investigate overpressure distributions and mechanisms in sedimentary basins with a combination of different methods and from limited data sources.


Introduction
Within any deep geothermal project, drilling is associated with the highest risk, both economically and safety-wise (e.g. Stober and Bucher 2013). This especially applies to deep geothermal projects in basins with very deep target sections and with only a few wells being drilled per year, such as the North Alpine Foreland Basin in SE Germany. Quite often the effective implementation and continuation of a deep geothermal project depend on the success of the rst well drilled. Therefore, most deep geothermal projects are similar to classical wild cat exploration situations. Unexpected changes in pore pressure and subsurface stresses can lead to severe drilling problems such as in uxes, kicks, blow-outs, drilling uid losses, differential sticking, over-pulls, etc., which in the best case only delay drilling and cause economic damage, but in the worst case endanger the continuation of the project or even pose a signi cant safety risk (Mouchet and Mitchell 1989). Therefore, careful well planning and adequate prediction of subsurface stresses and pressures are crucial for a successful completion of deep geothermal projects and deep drilling in general. This is particularly valid in overpressured basins (Mouchet and Mitchell 1989).
Overpressure is de ned as the excess pressure above hydrostatic pore pressure given by a vertical depth, the formation water's density and the Earth's gravitational acceleration. Overpressure or pore pressure in general can be estimated from data sources such as geophysical well logs (Bowers 1995;Eaton 1975Eaton , 1972, seismic velocities derived from vertical seismic pro les, seismic surveys or sonic logs (Bowers 1995;Eaton 1975Eaton , 1972, drilling parameters (Mouchet and Mitchell 1989) Satti et al. 2015). Origins of overpressure include disequilibrium compaction through retarded dewatering of pore uids due to low permeability barriers in the context of high sedimentation rates (Osborne and Swarbrick 1997;Swarbrick and Osborne 1998) and volume changes due to diagenesis and/or uid expansion at higher temperatures (Osborne and Swarbrick 1997;Sargent et al. 2015;Swarbrick and Osborne 1998). Additional overpressure can be induced in extensive, laterally amalgamated and dipping permeable sediments through lateral pressure transfer (Lupa et al. 2002;Yardley and Swarbrick 2000).
Within the North Alpine Foreland Basin in SE Germany overpressure is known to generally increase with burial depth from north to south and towards the Alps (Drews et al. 2018;Müller et al. 1988). Particularly to the south and east of Munich, overpressure can reach signi cant pressure gradients that translate to equivalent drilling uid densities (mud weight) in excess of 1.8 g/cm³ (Drews et al. 2018;Müller et al. 1988). Overpressure in the North Alpine Foreland Basin in SE Germany has been previously studied by Rizzi (1973), who demonstrated with two examples, that overpressure can be estimated from geophysical well logs such as electrical resistivity and acoustic transit time (sonic log). Müller et al. (1988) and Müller and Nieberding (1996) were the rst to study the regional distribution of maximum overpressure and its origin, based on a combination of maximum drilling mud weights and the structural interpretation of 2D seismic cross-sections. They presented a regional map of maximum pore pressure gradients inferred from maximum drilling mud weights. Based on analysis of drilling data and velocity data, Drews et al. (2018) demonstrated that overpressure can be estimated with reasonable accuracy from seismic velocities of sonic logs and vertical seismic pro les. Drews et al. (2018) also provided pore pressure gradient maps for all overpressured stratigraphic units present in the North Alpine Foreland Basin in SE Germany. However, previous work by Müller et al. (1988), Müller and Nieberding (1996) and Drews et al. (2018) were either based on drilling mud weight data and/or 1D velocity data of hydrocarbon wells, but did not incorporate 3D geologic models. Furthermore, these studies did not include any more recent deep geothermal wells from the North Alpine Foreland Basin in SE Germany, despite several deep geothermal wells have been drilled in the overpressured part of the basin during the past two decades -in some cases with signi cant overpressure-related drilling problems (Lackner et al. 2018).
A recent example of a deep geothermal exploration well in the overpressured section of the North Alpine Foreland Basin in SE Germany is given by the Geretsried Deep Geothermal Project, approximately 30 km SSE of Munich. In this study, the predictability and controlling factors of overpressure in the greater Geretsried area will be analyzed, combining drilling-and velocity data-based well analyses and pore pressurecentric 3D basin modelling. The results will be compared with pore pressure indicators from drilling data and a pore pressure estimate from vertical seismic pro le (VSP) data of the Geretsried GEN-1 well. The integration of these methods is the rst of its kind in the North Alpine Foreland Basin in SE Germany, especially in the context of deep geothermal projects in South Germany. The results of this study are of relevance to planning and drilling of future deep geothermal wells in the North Alpine Foreland Basin in SE Germany. Quanti cation of overpressure is also of signi cance to geomechanical studies in the North Alpine Foreland Basin in SE Germany, e.g. considering the prediction of induced microseismicity caused by geothermal exploitation. In addition, the presented methodology and results will be a valuable reference case for other pore pressure studies to investigate overpressure distributions and mechanisms in sedimentary basins with a combination of different methods and from limited data sources.

Geological Setting
The North Alpine Foreland Basin is a classical peripheral foreland basin. Its part in SE Germany stretches from Lake Constance in the west to the Austrian Border in the east ( Figure 1). To the north, the extent of the North Alpine Foreland Basin in SE Germany is roughly outlined by the Danube River, and towards the south it is bounded by the thrust-front of the Subalpine Molasse (also called Folded Molasse; Figure 1). The presence of overpressure in the North Alpine Foreland Basin in SE Germany has been attributed to disequilibrium compaction due to sedimentation rates exceeding dewatering rates of the buried ne-grained sediments (Drews et al. 2018;Müller et al. 1988). According to previous studies (Allen and Allen 2013; Zweigel 1998), peak sedimentation rates around 300 m/Ma occurred during Chattian and Aquitanian times. During the Cenozoic, ne-grained sediments forming shales and marls were primarily deposited during the high-stand phases in the  Drews et al. (2018) showed that disequilibrium compaction with the assumption of vertical stress as a proxy for mean stress is a valid model to estimate pore pressure and overpressure from shale velocities in the North Alpine Foreland Basin in SE Germany. This is also supported by the interpretation of leak-off tests and formation integrity tests in shale packages in the greater Munich area, which suggest the presence of a normal faulting or trans-tensional stress regime in the Cenozoic basin ll of the North Alpine Foreland Basin in the greater Munich area ).

Data And Methods
The aim of this study is to a) investigate how a combination of velocity-based pore pressure analyses, drilling data and basin modelling can be used to predict pore pressure in the North Alpine Foreland Basin in SE Germany and b) what are the controlling geological factors on overpressure presence and generation in the greater area around the Geretsried GEN-1 well location. To do so, the 3D basin model is calibrated to velocity and drilling data-derived pore pressure pro les of four wells in the greater Geretsried area. The basin model also serves the purpose of investigating the controlling factors of overpressure presence. The Geretsried GEN-1 well is not part of the calibration, but acts as a blind test. To do so, a 1D pore pressure extraction from the calibrated 3D basin model at the Geretsried GEN-1 well location is compared to the drilling history, drilling related pore pressure indicators and a pore pressure estimate from the vertical seismic pro le data of the Geretsried GEN-1 well.
Drilling history and pore pressure indicators of the Geretsried GEN-1 well The deep geothermal project "Geretsried Nord" was initiated by Enex Power Germany GmbH on the Wolfratshausen concession in September 2004. The Geretsried GEN-1 well was planned as a producer and was drilled approximately 5 km northwest of the city of Geretsried from mid-January 2013 to mid-July 2013. The well reached a total vertical depth of 4852 m (6036 m in measured depth). Despite excellent temperature conditions with a bottom-hole temperature of about 160°C the project was halted due to a lack of productivity in the targeted Upper Jurassic (Malm) carbonate aquifer. In 2017, a scienti c sidetrack was drilled into a nearby fault zone in hope of increased permeability, but it did not yield a su cient increase in productivity. In true vertical depth (TVD), the Geretsried GEN-1 well penetrated approximately 70 m of Quaternary sediments, 4162 m of Cenozoic deposits, 105 m of Cretaceous stratigraphy and 515 m of Upper Jurassic carbonates (Malm). The Geretsried GEN-1 well was drilled in ve sections. Figure 3 is a graphical representation of the following description of the drilling history and pressure indicators of the Geretsried GEN-1 well.
In the rst two sections (down to 2922 m) low gas readings and a drilling mud weight of less than 1.2 g/cm3 generally indicate balanced to overbalanced drilling and likely hydrostatic pressure conditions ( Figure 3A, B). However, within lower Aquitanian and Chattian shale sequences ( Figure 3C) increased cavings, over-pulls and tight-hole sections were recorded ( Figure 3A), which might indicate underbalanced drilling and slightly elevated pore pressures. Accordingly, maximum total gas readings of 7.1% were detected in the sands of the Lower Chattian ( Figure 3B).
During drilling of the third section the drilling mud weight was increased from 1.16 g/cm³ to 1.25 g/cm³ followed by a water in ux within Chattian/Rupelian sands of the so called Baustein Beds at 3285 m ( Figure 3A). Recorded shut-in pressures of 17.13 MPa and a drilling mud weight of 1.25 g/cm³ indicate a formation pressure of 57.41 MPa or an equivalent mud weight of 1.78 g/cm³. The drilling mud weight was therefore increased to 1.86 g/cm³ until high total gas readings of up to 49% within the lower Oligocene and possibly Eocene required a further mud weight increase to 1.94 g/cm³, which nally stopped the increased gas readings ( Figure 3A, B). A formation pressure between 1.86 g/cm³ and 1.94 g/cm³ around 4115 m vertical depth is therefore likely. Consequently, the section was cased with a 9 5/8" string down to 4123 m vertical depth.
The next section (2922-4122 m) experienced high total gas readings and a small gas kick ( Figure 3A, B). Measured shut-in pressures within the Eocene Lithothamnium Limestone yielded formation pressures of 51.02 MPa or 1.26 g/cm³ in equivalent mud weight. As a result, the drilling mud weight was increased from 1.24 g/cm³ to 1.31 g/cm³, which stopped the gas in ux.
The last section was drilled entirely within the Upper Jurassic carbonate aquifer (Malm) to a TVD of 4852 m (6036 m measured depth) with a maximum drilling mud weight of 1.07 g/cm³ ( Figure 3A). However, high gas readings within the Upper Jurassic of up to 73% indicate underbalanced drilling and likely an Upper Jurassic aquifer ( Figure 3B), which is slightly overpressured and eventually not as hydraulically active as described in other parts of the North Alpine Foreland Basin in SE Germany (c.f. Lemcke 1976). These observations t with the low productivity rates found in the Geretsried GEN-1 well.

Study area and well data
The study area extends over 80 x 50 km and is roughly centered by the Geretsried GEN-1 drill site approximately 30 km south of Munich ( Figure 4). The study area includes closer studied wells in the north (Well A), west (Well B), east (Well C) and northeast (Well D) of the Geretsried GEN-1 drill site ( Figure 4). Velocity and drilling data of these four wells have been studied in more detail to provide pressure calibration points for the 3D basin model. An additional set of 14 wells plus one well approximately 7 km WNW outside of the study area were used to constrain extent and thickness of the stratigraphic units included in the 3D basin model (Figure 4). The available data of all wells are summarized in Table 1 Vertical seismic pro le (VSP) data of the Geretsried GEN-1 well The near-offset VSP (i.e. source was located at 81 m offset from the wellhead) was measured by DMT/Weatherford in the deviated Geretsried GEN-1 well in 2016 (Bello 2016). Two primary objectives were pursued: a) gaining the velocity control through the well and b) establishing the tie between seismic events and formation tops. The VSP acquisition was performed at the depth interval of 1880 m to 4265 m MD below ground level with a vertical spacing of c. 15 m between successive geophones. The depth interval of 465 m to 1880 m MD below ground level was covered by a check-shot survey, where time-to-depth measurements were taken at 7 irregularly spaced geophone locations. Consequently, the combined check-shot-VSP survey covers the entire stratigraphic pro le between top Burdigalian and base Eocene (compare Figure 2). Measured depths and times were corrected with respect to the wellbore deviation and then referenced to the Seismic Reference Datum (SRD) of 450 m above mean sea level, using a correction velocity of 3000 m/s. Interval velocities were subsequently calculated based on the corrected depth and time measurements.
Velocity-based pore pressure analysis For the velocity-based pore pressure analysis of the four calibration wells Well A, Well B, Well C and Well D, available sonic log and VSP data were used to estimate shale pore pressure. Thereby, the work ow strictly followed the methodology and normal compaction trend developed Foreland Basin in SE Germany. In combination with the Eaton pressure transform for seismic velocity (Eaton 1975(Eaton , 1972, the normal compaction trend can be used to estimate shale pore pressure in the North Alpine Foreland Basin in SE Germany. The described method requires an estimate of the vertical stress σv. Su cient density data were neither available for the calibration wells, nor for the Geretsried GEN-1 well. Thus, the velocity-density transform of Gardner et al. (1974) was applied in those cases in which vertical seismic pro le data were available. Otherwise an Athy-type effective stress-porosity relationship with the parameters de ned by Drews et al. (2018) was used. In this study, pore pressures and subsurface stresses are usually presented as pressure/stress gradients in equivalent mud weight (EMW) with the density unit g/cm³, which is calculated as follows: See formula 1 in the supplementary les.
Where PP is the pore pressure in kPa, g is the Earth's gravitational acceleration at 9.81 m/s² and TVD is the true vertical depth in m, referenced to the ground level of the drill site. In equation 1, PP can also be substituted by any stress parameter to represent stress in equivalent mud weight.

Geological and geometric constraints
Modelling is performed on the basis of stratigraphic well tops from geological well reports of 20 wells (c.f. Table 1 and Figure 4). Structural elements such as faults are not included in the model. Individual horizons are generated on the basis of interpolation of thicknesses of the respective stratigraphic units. Facies variations within individual stratigraphic units have not been included in the basin model to keep the degrees of freedom to a minimum. Therefore, the model results represent general pore pressure trends and cannot re ect pressure perturbations due to structural or facies-related heterogeneities.
For the sake of comparability, the geologic ages have been assigned according to previous studies, which speci cally addressed stratigraphy, sedimentation and subsidence of the North Alpine Foreland Basin in SE Germany (c.f. Figure 2): for the Cenozoic section ages have been assigned according to , except for the geological ages of the Schoeneck Formation and the Eocene, which have been derived from Zweigel (1998). Since the Cenozoic basin subsidence put the underlying Mesozoic strata most likely to their maximum burial depth, Paleocene and Eocene erosion events have only been modelled as stratigraphic pinch-outs of the eroded strata. Accordingly, geologic ages for the underlying Mesozoic strata were simply derived from the International Chronostratigraphic Chart ). Thus, the Mesozoic section of the 3D basin model of this study should be seen as a pre-existing basement section, while the actual basin modelling process starts with the Cenozoic basin ll.
Facies variations are not included in this study and therefore only 3 basic lithologies are used: sandstone (typical and clay-rich after Hantschel and Kauerauf 2009), limestone (ooid grainstonel and typical chalk after Hantschel and Kauerauf 2009) and shale. Porosity and permeability of sandstones and limestones have been modelled using Athy's depth-porosity relationship (Athy 1930) and a three-point porosity-permeability relationship, respectively, with parameters for both porosity and permeability relationships provided by Hantschel and Kauerauf (2009) (Figure 5). Shale compaction (porosity as a function of effective stress) has been modelled with the same porosity trend as used for constraining the normal compaction trend of the velocity-based analysis (c.f. Drews et al. 2018).
Shales play a signi cant role in overpressure generation due to their low permeability (Osborne and Swarbrick 1997) and most likely are the main driver for overpressure generation in the North Alpine Foreland Basin (Drews et al. 2018). Shale permeability has been modelled with the clay content-dependent porosity-permeability developed by Yang and Aplin (2010), which covers a permeability range between 10 -18 m² to 10 -21 m² for clay contents between 50% and 90% ( Figure 5). However, both the relatively thin Schoeneck Formation and Upper Cretaceous shales are known to comprise signi cant overpressure in the North Alpine Foreland Basin in SE Germany (Drews et al. 2018), suggesting even lower permeability might be required to build up and maintain signi cant overpressure. Since at least the Schoeneck Formation is known to be organic-rich (Bachmann et al. 1987), two-phase permeability reduction offers a possible explanation for shale permeabilities below 10 -21 m². Laboratory studies demonstrated, that two-phase permeability of mudrocks can be reduced by >2 orders of magnitudes compared to single-phase permeabilities (Busch and Amann-Hildenbrand 2013). For a 2-phase system between methane and water the following empirical relationship has been found by Busch and Amann-Hildenbrand (2013): See formula 2 in the supplementary les.
Where K 2-phase is the reduced 2-phase shale permeability and K Single is the actual single phase shale permeability. Figure 5 summarizes all compaction and permeability relationships used in this study.

Boundary conditions
The Upper Jurassic carbonates are known to be at sub-hydrostatic to hydrostatic pressure conditions (Drews et al. 2018;Lemcke 1976). Therefore, a permanent hydrostatic pressure boundary condition (referenced to sea level) has been set for the Jurassic. For the modelled geologic history of the study area (200 Ma to present day), a constant surface temperature of 10°C has been applied. The basal heat ux (BHF) has been set to 53 mW/m², which is in concordance with previous studies in the North Alpine Foreland Basin Gusterhuber et al. (2014). Since only very little information is known about absolute paleo-sea level values and since water depth changes have no impact on effective stress and thus present day pore pressure, paleo-water depths were not included (zero water depth assumed for all modelled stratigraphic events).

3D basin model
A 3D basin has been set up to investigate a) the sub-regional pore pressure distribution, b) the impact of presence and distribution of stratigraphic units and their permeability and c) the predictability of overpressure in the North Alpine Foreland Basin in SE Germany, using the Geretsried GEN-1 well as a blind test. The basin model has been constrained to stratigraphic tops of 20 wells with a minimum distance of ~3 km between two wells (c.f. Figure 4). A horizontal cell size of 1 km x 1 km was used for the basin model. The basin model comprises 11 layers ( Figure 6) and the number of sublayers has been set such that the vertical cell size does not exceed 500 m, yielding a total of 22 layers. The extent of the basin model is identical to the map of Figure 4, resulting in an 80 km x 50 km grid. The model has been cropped to an area of interest (AOI) after simulation (c.f. Figure 4). Within the AOI, the resulting maximum difference between actual present day well tops and modelled stratigraphic tops at the individual well locations does not exceed 70 m for the base of the Chattian (c.f. Figure 6), which is the thickest stratigraphic unit (average thickness of 1200 m in the AOI, Figure 7) and therefore associated with the highest potential deviation. All layers fully cover the AOI, except for the Schoeneck Formation, Eocene and Upper Cretaceous, which are missing in the northwest due to erosion. Erosion of these units has been implemented as stratigraphic pinch-outs ( Well A is located to the north-west of the Geretsried GEN-1 well (c.f. Figure 4). The top of the Upper Jurassic is at ~2600 m. Upper Cretaceous is missing (c.f. Figure 7). Well A generally shows no signs of overpressure has been drilled with a maximum drilling mud weight of 1.1 g/cm³ ( Figure 8A). Only at the transition between Rupelian and Schoeneck Formation velocity data indicates maximum pore pressures of 1.09 g/cm³ EMW at 2554 m ( Figure 8A).
Well B is located to the west of the Geretsried GEN-1 well (c.f. Figure 4). Velocity data indicate an overpressured zone is present between 3500 m (top Rupelian) and 4100 m (base Schoeneck Formation) with a maximum of 1.65 g/cm³ EMW at 4035 m ( Figure 8B). This is also supported by a drill stem tests, drilling mud weights of 1.62 g/cm³ and high gas readings in the section that drilled through the overpressured zone ( Figure 8B). However, the shut in pressures of the DSTs have not been corrected to full build up and therefore only provide minimum pore pressures. A shallower top of overpressure at ~3200 m, where velocity data indicates very mild overpressure is also possible ( Figure 8B). Below the Schoeneck Formation, pore pressures are quickly receding to normal pressures < 1.2 g/cm³ ( Figure 8B).
Well C is located to the east of the Geretsried GEN-1 well (c.f. Figure 4). Drilling mud weights, shale sonic log data and gas readings indicate a top of mild overpressure at the top of the Chattian increasing to very high overpressure at the base Rupelian and within the Schoeneck Formation ( Figure 8C). Maximum shale pore pressures based on velocity data reach 1.89 g/cm³ EMW at 4278 m ( Figure 8C). The well just tapped the Upper Cretaceous, but velocities are indicating mild to medium overpressure (~1.3-1.4 g/cm³) might be present ( Figure 8C).
Well D is located to the north-east of the Geretsried GEN-1 well (c.f. Figure 4). Drilling mud weights, high gas, pressure cavings and VSP velocities suggest an overpressured zone between the top of the Rupelian and base of the Schoeneck Formation (maximum pore pressure of 1.76 g/cm³ EMW at 3633 m, Figure 8D). Velocity data indicates hydrostatic pressure conditions in the Upper Cretaceous ( Figure 8D).  Figure 5). In order to also account for possibly lower permeabilities the 2-phase permeability correction of Busch and Amann-Hildenbrand (2013) has been applied to the relationship of Yang and Aplin (2010) with clay contents between 50% and 90% (c.f. eq. 2 and Figure 5).
From litho-stratigraphic analysis  and known overpressure magnitudes (Drews et al. 2018) it follows that the Rupelian, Schoeneck Formation and Upper Cretaceous must comprise higher clay and/or organic content and therefore lower permeabilities than the shales of the Chattian. From cutting descriptions, available in the geological well reports, also follows that the Chattian generally comprises less clay-rich units than the Rupelian, and therefore has probably higher permeability. Incorporating these relationships by the following rule allows for signi cant reduction of possible permeability model combinations: See formula 3 in the supplementary les.
Where K Ch , K Ru , K Sch , K UC are the permeabilities at a given depth of the shales of the Chattian, Rupelian, Schoeneck Formation and Upper Cretaceous, respectively. The resulting models are then tested against the deviation from the maximum recorded pore pressure gradients in EMW at the calibration wells A-D. Hereby, +/-70 m of depth variation are allowed, which corresponds to the maximum vertical geometry error of the basin model. Also, we de ne +/-0.15 g/cm 3 as an acceptable range of pore pressure deviation in terms of equivalent mud weight (EMW), which matches the uncertainty range of velocity-based pore pressure estimates (Drews et al. 2018) and still allows for quick well control intervention in case of drilling problems. In addition, we add the deviation of the maximum modelled pore pressure from the maximum measured/estimated pore pressure, independent of depth, as a criterion (Table 2).
Testing equal permeability models for all four varied layers indicates, that the permeability structure has to vary: using the permeability model of Yang and Aplin (2010) with clay contents of 50%, 70% and 90% for all four layers either results in pore pressures that are generally too low (50% and 70%) or result in a mismatch, with too high pore pressure in the Chattian and too low pore pressures in the Rupelian and Schoeneck Formation (models C1-3; Table 2). Therefore, permeabilities of the Rupelian and Chattian have been tested next, with the Schoeneck Formation and Upper Cretaceous set to the lowest permeabilities (90% clay content, corrected for 2-phase permeability).
From application of the models yielding the lowest permeabilities, 2-phase model after Busch and Amann-Hildenbrand (2013) applied to 90% clay content model of Yang and Aplin (2010), to the Schoeneck Formation and Upper Cretaceous, quickly follows, that too much overpressure builds up within the Chattian layer at Well A, if a clay content of ≥70% is applied to the Chattian permeability model (models C24-26; Table 2). Vice versa, su cient overpressure in the Rupelian and Schoeneck Formation only builds up if a clay content of ≥90% or 2phase permeability corrected model with 70% clay content is applied to the permeability of the Rupelian layer (models C14, C15, C17-19, C21-23; Table 2). Also, very low permeabilities as provided by the model based on 90% clay content for the relationship of Yang and Aplin (2010) corrected by the 2-phase model of Busch and Amann-Hildenbrand (2013) have to be applied to either the Schoeneck Formation or Upper Cretaceous to build up overpressure to observed magnitudes at Well B, Well C and Well D. Otherwise, overpressure will be too low at the overpressured well locations (models C10, C13, C16, C20, C24; Table 2). The best t model (model C19, Table 2

Impact of permeability of the Schoeneck Formation and the Eocene
The best t model (model C19, Table 2) has been used to test the impact of the permeability of the Schoeneck Formation. First, the permeability model of the Schoeneck Formation has been replaced with 50% clay content applied to the porosity-permeability relationship  Figure 5). While the impact is very low and still yields simulated pore pressures within acceptable ranges at all four calibration wells in the rst case (model Sch1, Table 2), the high permeability limestone case results in too low pore pressures at all overpressured wells (model Sch2, Table 2 and Figure 8A-D). This is likely due to bypassing the shales of the Upper Cretaceous: since the Schoeneck Formation is present almost in the entire in the north west of the AOI, whereas the Upper Cretaceous is missing, uids can migrate along a hypothetical high permeability Schoeneck Formation from the overpressured Rupelian to the normally pressured Upper Jurassic. Although this effect is not realistic for the Schoeneck Formation, it might be a mechanism, which is eventually associated with the Eocene Lithothamnium Limestone.
The permeability of the Eocene Lithothamnium Limestone has been modelled with a fast compacting limestone, yielding permeabilities in the order of 1-100*10 -21 m 2 (c.f. Figure 5), which are comparable to typical shale permeabilites (c.f. Yang and Aplin 2010). However, the ow properties of the Lithothamnium Limestone are highly uncertain, and higher permeabilities are also possible. Therefore, an additional model with the setup of the best t model (model C19, Table 2), but with a permeable and incompressible Eocene layer has been run (model Eo1,  Figure 8A-D). This might be due to two factors: 1. The higher permeability reduces the overall effective permeability, and thus sealing capacity, of the package between hydrostatic Lower Cretaceous and overpressured Rupelian 2. The Eocene extends further to the northwest than Upper Cretaceous shales, and, if permeable, has the potential of acting as lateral drainage system between overpressured Oligocene and (sub-)hydrostatically pressured Lower Cretaceous and Upper Jurassic carbonates (Figure 9). A higher permeability than modelled in the best t model (model C19, Table 2) also requires even lower permeabilites or a secondary overpressure generation mechanism to be present in the Schoeneck Formation to build up observed overpressures. Since permeabilities below 10 -25 m 2 appear to be unrealistic, a secondary overpressure generation mechanism, such as uid expansion due to hydrocarbon generation and/or clay diagenesis, seems to be more likely.

Impact of permeability and spatial distribution of the Upper Cretaceous
Similar to the Schoeneck Formation and Eocene, the impact of the permeability of Upper Cretaceous shales has been tested: substitution of the Upper Cretaceous with 50% clay content applied to the porosity-permeability relationship of Yang and Aplin (2010) in a rst model (model LC1, Table 2 Table 2).
Both models yield too low pore pressures at Well C and Well D (models LC1 and LC2,  Figure 7). The resulting pore pressure distribution shows signi cant overpressure (>1.8 g/cm³) would also build up at Well A (model LC3; Table 2 and Figure 8A), if Upper Cretaceous shales were present in the northwest of the study area, while simulated pore pressures are still in acceptable ranges at all other calibration well locations (model LC3;  Within the Chattian some elevated gas readings suggest slight underbalanced drilling and accordingly, the basin model predicts mild overpressure ( Figure 10). Nevertheless, the variable VSP-data shows that the Chattian is fairly heterogeneous. Such small-scale vertical facies variations are not captured by the basin model.
The basin model fails to match the severe water kick at 3285 m in the Baustein Beds, which is neither met by the VSP data-based pore pressure estimate ( Figure 10). This is could be due to the large thickness of the sands of the Baustein Beds -the velocity based pore pressure estimation only functions in shales. Assuming a hydrostic pressure gradient tied to the water kick pressure of 1.78 g/cm³ in EMW then demonstrates, that shale pressures can indeed be lower below the Baustein Beds, while still belonging to the same pressure regime ( Figure 10). Still, the velocity-based pore pressure pro le in the Rupelian at the Geretsried GEN-1 well location is different than the pro les of the calibration wells Well B, Well C and Well D: Instead of a pore pressure maximum at the transition between Rupelian and Schoeneck Formation (c.f. Figure 8B-D), pore pressure in EMW appears to decline within the Rupelian based on VSP data. One explanation might be a different mineralogical composition of the Rupelian shales in the Geretsried area, leading to a faster velocity signal (e.g. by increased carbonate content, lower clay content and higher contents of coarser grained material or advanced Smectite to Illite transformation). A second explanation can be given by vertical pressure transfer within the thick Baustein Beds, or even through lateral pressure transfer in the Baustein Beds or a nearby fault zone in the Chattian/Rupelian transition, which indeed has been indicated by the mud log. Pressure transfer would also explain the sudden pressure increase in the Baustein Beds. A water gradient shifted to the overpressure of the Baustein Beds supports this hypothesis, since it extends to the estimated and lower shale pressures in the Upper Rupelian (PP BSB , Figure 10 Figure 4). It should be noted, that all four scenarios do not contradict each other and a combination is also possible.
In the Upper Cretaceous, pressures are nally decreasing to the slightly above hydrostatic conditions in the carbonates of the Lower Cretaceous and Jurassic. This decline is also represented in the 1D extraction of the base case basin model ( Figure 10). The VSP data acquisition stopped in the Eocene and does not extend into the Cretaceous and deeper (Figure 10).

Secondary overpressure mechanisms
Since the here used basin model only incorporates uid ow and mechanical compaction and associated permeability reduction, it can be deduced, that, on a sub-regional to regional scale, overpressure in the study area and likely the entire North Alpine Foreland Basin in SE Germany can be su ciently simulated and explained with disequilibrium compaction as overpressure generation mechanism. First order estimates of sedimentation rates (thickness divided by age interval) in excess of 400 m/Ma at overpressured locations (Well B, Well C, Well D) vs. lower rates (~200 m/Ma) at normally pressured locations (Well A) support this hypothesis (c.f. Figure 7). These sedimentation rates are higher than previously reported sedimentation for the North Alpine Foreland Basin (Allen and Allen 2013; Zweigel 1998). However, it has to be noted, that litho-stratigraphic units with very low permeability units are required -in some cases less than 10 -23 m 2 . Although such low permeabilities have been measured and observed before ( Especially, for the Schoeneck Formation, which is rich in organic matter (Bachmann et al. 1987) and within the oil window in most parts of the study area, uid expansion due to hydrocarbon generation would be a good candidate as an additional source of overpressure. This might even be enhanced by capillary sealing of the pores against the water phase due to primary hydrocarbon migration, which has been partly covered in this study using the 2-phase permeability reduction model of Busch and Amann-Hildenbrand (2013). In addition, clay diagenesis might be another secondary overpressure generation mechanism. Onset of clay diagenesis has been previously reported around 2000-2500 m TVD in the Austrian Part of the North Alpine Foreland Basin and Vienna Basin (Gier 2000(Gier , 1998Gier et al. 2018). Moreover, the role of lateral stresses is not resolved, yet. The study area is only a few kilometers away from the rst thrust front of the Eastern Alps and might therefore be in uenced by increased lateral stresses, which would in uence velocity-based and basin modelling-based pore pressure estimates (Gao et al. 2018;Obradors-Prats et al. 2017, 2016. Also, lateral pressure transfer (Lupa et al. 2002;Yardley and Swarbrick 2000) could be a mechanism yielding either additional overpressure or even pressure regressions. However, signi cant lateral continuity of permeable units are still to be proven in the Cenozoic basin ll of the North Alpine Foreland Basin in SE Germany, since the current understanding assumes more isolated lenticular sand bodies (Müller and Nieberding 1996). In summary, the true impact of secondary overpressure generation mechanisms still has to be investigated and cannot be fully resolved by this study.

Conclusions
Drilling data and velocity-based pore pressure analyses have been combined with 3D basin modelling to test the predictability and controlling factors of overpressure in the area of the Geretsried GEN-1 deep geothermal well, located in the North Alpine Foreland Basin in SE Germany. Thereby the following concluding remarks can be drawn: High overpressure is present within the sediments of the Rupelian and Schoeneck Formation at the Geretsried GEN-1 well location and to the west, south and east of it. However, unusually high pressures are present in the Baustein Beds at the Geretsried GEN-1 well location, which might be explained through vertical pressure transfer.
Mild overpressure is present in sediments of the Chattian and Upper Cretaceous at the Geretsried GEN-1 well location and to the east of it.
Disequilibrium compaction is likely the primary source of overpressure. This is supported by 3D basin modelling, high sedimentation rates and presence of thick shales at overpressured locations. However, very low permeabilities are required if diesequilibrium compaction was the sole mechanism. Thus, secondary mechanisms are likely contributing. In particular, in the organic-rich Schoeneck Formation uid expansion could be a viable mechanism.
Presence of Upper Cretaceous shales are controlling overpressure maintenance. In the northwestern part, where Upper Cretaceous shales are not present, overpressure cannot be maintained against the hydraulic pull of the hydrostatically pressured Upper Jurassic carbonates. Otherwise, signi cant overpressure magnitudes would have built up also in this part of the North Alpine Foreland Basin.
The 3D basin modelling calibrated to drilling data and velocity-based pore pressure estimates at surrounding wells provides a viable tool to predict pore pressure pre-drill in the North Alpine Foreland Basin, which has been demonstrated with a blind test at the Geretsried GEN-1 well location. Knowledge of pore pressure presence and magnitudes pre-drill is key to design the drilling mud weight program and select appropriate casing points and to ensure safe and economic drilling. However, pre-drill pore pressure prediction could be further improved by incorporating lateral and vertical facies distributions and mapping of permeable units using 3D seismic data.

Availability of data and material
The data that support the ndings of this study are available from Leibniz Institute for Applied Geophysics (LIAG), Enex Power Germany GmbH, ENGIE Deutschland AG, ExxonMobil Production Deutschland GmbH and Wintershall Dea Deutschland GmbH, but restrictions apply to the availability of these data, which were used under license for the current study, and so are not publicly available. Data are however available from the authors upon reasonable request and with permission of Leibniz Institute for Applied Geophysics (LIAG), Enex Power Germany GmbH, ENGIE Deutschland AG, ExxonMobil Production Deutschland GmbH and Wintershall Dea Deutschland GmbH.      Study area and extent of 3D basin model with used wells. The Geretsried GEN-1 drill site is marked with a grey star, the calibration wells A-D are marked with black crosses, while black dots indicate additional wells (B1-B15) used to constrain the 3D basin model. One well is outside of the map area and was used to constrain the extent of the Schoeneck Formation. The map coincides with the extent of the full basin model, which has been reduced to an area of interest (AOI, marked by the black lined polygon) after simulation.

Figure 7
Isopach maps of each layer of the 3D basin model, except for the Quarternary (thickness generally < 100 m) and Jurassic, which has been modelled with a constant thickness of 600 m.

Supplementary Files
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