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 (Figure 7). Dividing thickness (Figure 7) by respective age intervals of the layers provides a first order estimate of subsidence rates of >400 m/Ma during the Chattian. Since the basin model only accounts for fluid flow and disequilibrium compaction to produce overpressure, the thickness of low permability units (mostly Chattian and Rupelian) should also be an indicator of where higher overpressure is more likely to build up. Thereby, the Chattian and Rupelian sum up to approximately 900 m, 1900 m, 2200, 1650 m and 2100 m at the locations of Well A, Well B, Well C, Well D and the Geretsried GEN-1 well.
Pore pressure calibration of the 3D basin model
Drilling data and velocity-based pore pressure estimates
The basin model has been calibrated to drilling data and velocity-based pore pressure estimates of Well A, Well B, Well C and Well D (Figure 8A-D). In summary, all wells have pore pressure maxima at the base Rupelian and top Schoeneck Formation (Figure 8A-D). Except for Well A, all wells comprise overpressured sections in the Rupelian and Schoeneck Formation, while Chattian and Upper Cretaceous shales are only overpressured at (Well C):
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).
Compaction and permeability relationships of Quarternary, OSM, Burdigalian, Aquitanian, Eocene, Lower Cretaceous and Jurassic layers have not been altered for the pore pressure calibration procedure. The Quarternary has been modelled as permeable siliciclastic sandstone (typical sandstone after Hantschel and Kauerauf 2009; c.f. Figure 5). OSM, Burdigalian and Aquitanian are represented by a clay-rich sandstone (after Hantschel and Kauerauf 2009; c.f. Figure 5) and Lower Cretaceous and Upper Jurassic have been modelled as a nearly uncompressible limestone (ooid grainstone after Hantschel and Kauerauf 2009; c.f. Figure 5) to mimic the comparably high permeability present in these carbonates even at depths > 4000 m (Przybycin et al. 2017). The Eocene Lithothamnium Limestone has been modelled with chalk properties (typical chalk after Hantschel and Kauerauf 2009; c.f. Figure 5) to represent a fast compacting limestone. Relationships defining compaction and permeability of the shale-rich units (Chattian, Rupelian, Schoeneck Formation and Upper Cretaceous) have been varied using the permeability-porosity relationship of Yang and Aplin (2010) with clay contents between 50% and 90% (c.f. 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 (Kuhlemann and Kempf 2002) 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 significant reduction of possible permeability model combinations:
See formula 3 in the supplementary files.
Where KCh, KRu, KSch, KUC 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 define +/- 0.15 g/cm3 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, sufficient overpressure in the Rupelian and Schoeneck Formation only builds up if a clay content of ≥90% or 2-phase 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 fit model (model C19, Table 2 and Figure 8A-D) is achieved by application of 60% clay content to the permeability model (after Yang and Aplin 2010) of the Chattian layer and 90% clay content to the permeability models (after Yang and Aplin 2010) of the Rupelian, Schoeneck Formation and Upper Cretaceous. Thereby, the permeabilities of the Schoeneck Formation and Upper Cretaceous have been further reduced by applying the 2-phase permeability correction (eq. 2, Busch and Amann-Hildenbrand 2013). Substituting, the permeability of the Rupelian with a 70% clay content porosity-permeability relationship (Yang and Aplin 2010) corrected for 2-phase permeability (Busch and Amann-Hildenbrand 2013) also gives a good fit (model C21, Table 2 and Figure 8A-D).
Impact of permeability of the Schoeneck Formation and the Eocene
The best fit 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 of Yang and Aplin (2010). Second, the compaction and permeability model of the Schoeneck Formation has been replaced with the limestone model applied to the Upper Jurassic and Lower Cretaceous (ooid grain stone; c.f. Hantschel and Kauerauf 2009), yielding very high and almost constant permeabilities (c.f. Figure 5). While the impact is very low and still yields simulated pore pressures within acceptable ranges at all four calibration wells in the first 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, fluids 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 m2 (c.f. Figure 5), which are comparable to typical shale permeabilites (c.f. Yang and Aplin 2010). However, the flow properties of the Lithothamnium Limestone are highly uncertain, and higher permeabilities are also possible. Therefore, an additional model with the setup of the best fit model (model C19, Table 2), but with a permeable and incompressible Eocene layer has been run (model Eo1, Table 2). The Eocene has been set to the same lithology model as the Lower Cretaceous and Jurassic in this study (ooid grainstone, c.f. Hantschel and Kauerauf 2009). The resulting pore pressures yield significant lower pore pressures at all overpressured well locations and throughout the model domain (model Eo1, Table 2 and Figure 8A-D). This might be due to two factors:
- The higher permeability reduces the overall effective permeability, and thus sealing capacity, of the package between hydrostatic Lower Cretaceous and overpressured Rupelian
- 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 fit 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 m2 appear to be unrealistic, a secondary overpressure generation mechanism, such as fluid 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 first model (model LC1, Table 2) and replacement of the compaction and permeability model of the Upper Cretaceous with the limestone model applied to the Upper Jurassic and Lower Cretaceous (ooid grain stone; c.f. Hantschel and Kauerauf 2009), again yielding very high and almost constant permeabilities, in a second model (model LC2, Table 2).
Both models yield too low pore pressures at Well C and Well D (models LC1 and LC2, Table 2), suggesting that the presence of low permeability shales in the Upper Cretaceous is important to maintain overpressure at high magnitudes in the Rupelian and Schoeneck Formation (c.f. Drews et al. 2018). A third model (model LC3; Table 2), where presence of low permeability Upper Cretaceous shales is mimicked by substituting the high permeability limestone model of the Lower Cretaceous by the low permeability model of the Upper Cretaceous has also been run to further validate the impact of the Upper Cretaceous on overpressure maintenance. In contrast to the Upper Cretaceous, Lower Cretaceous is present in the entire AOI (c.f. Figure 7). The resulting pore pressure distribution shows significant 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; Table 2 and Figure 8C-D),.
Pore pressure predictability: blind test at the Geretsried GEN-1 well location
The 1D extraction from the best fit basin model (model C19, Table 2) at the Geretsried GEN-1 well location matches maximum pore pressure magnitudes in EMW within the overpressured sections of the Chattian, Rupelian and Schoeneck Formation (Figure 10). A similar prediction prior to drilling would have likely avoided the severe kick at 3285 m and other drilling problems in the high pressure zone between 3250 m and 4200 m.
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 profile in the Rupelian at the Geretsried GEN-1 well location is different than the profiles 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 (PPBSB, Figure 10). A third alternative scenario could be given by an early onset of the pressure regression towards the hydrostatically pressured Upper Jurassic. The variability of the VSP within the Rupelian suggests lithological heterogeneity, which would be supportive of the latter scenario, since even small scale heterogeneities in shales can significantly increase effective permeabilities (c.f. Drews et al. 2013). As a fourth scenario, the VSP data-based pressure regression could also be an effect of increased lateral stresses, which would result in underestimation of pore pressure by velocity-based methods, when assuming vertical effective stress as a good proxy for compaction and mean stress (Couzens-Schultz and Azbel 2014; Drews and Stollhofen 2019; Obradors-Prats et al. 2017). However, the Geretsried GEN-1 well is at a similar distance to the North Alpine Thrust Front as Well B and Well C (c.f. 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 finally 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 fluid flow 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 sufficiently 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 m2. Although such low permeabilities have been measured and observed before (Busch and Amann-Hildenbrand 2013; Hildenbrand et al. 2002; Kwon et al. 2001; Lee and Deming 2002; Luffel et al. 1993; Yang and Aplin 2010, 2007), the presence of secondary overpressure mechanisms offers a more plausible explanation. 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, fluid 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, 1998; Gier et al. 2018). Moreover, the role of lateral stresses is not resolved, yet. The study area is only a few kilometers away from the first thrust front of the Eastern Alps and might therefore be influenced by increased lateral stresses, which would influence 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, significant lateral continuity of permeable units are still to be proven in the Cenozoic basin fill 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.
Facies distribution and fault zones
The basin model used in this study does neither incorporate lateral nor vertical facies variations in individual layers, representing stratigraphic units. Although a general change from more terrestrial deposits in the WNW towards a pure marine setting in the ESE of the North Alpine Foreland Basin in SE Germany has been described for the Chattian and Rupelian (Kuhlemann and Kempf 2002), significant changes of depositional environment of the Chattian, Rupelian, and Schoeneck Formation within the study area have not been reported by respective studies (Kuhlemann and Kempf 2002). However, lateral and vertical facies variations within the Rupelian appear to impact overpressure estimation from velocity data and simulation using basin modelling. Careful mapping and incorporation of facies variations within the Rupelian might therefore increase the accuracy of pore pressure predictions in the studied part of the North Alpine Foreland Basin in SE Germany.
The 3D basin model applied in this study does not consider any structural elements, which are abundantly present as normal faults in the entire North Alpine Foreland Basin in SE Germany. However, most of these normal faults only comprise throws on the order of 10-100 m (c.f. von Hartmann et al. 2016). Pore pressure perturbations due to hydrocarbon accumulation against these faults would therefore be very small and well within the range of uncertainty defined in this study (+/- 0.15 g/cm3). Otherwise, faults generating local pressure compartments in the Upper Jurassic carbonates might have an impact on overpressure preservation, if these faults prevented the Jurassic from hydraulic drainage.