## 5 Discussion  
### Comparison of Results  
The permeability values that we have derived from the production tests of wells T-1 and VS-1 at Mezobereny, 18 to 278 mD (Table 1), are low compared to regional averages published in 1994 by [PERSON] et al. [11], -70 to -400 mD (Figure 16). Nonetheless, because [PERSON] et al. [11] only published average permeability values, it is unclear if our dataset is statistically different from theirs. We have no access to the raw data underlying their study but suggest possible reasons for this difference in results. One possible reason is because of skin formation. However, as already noted, the shut-in periods in between production tests were only two hours long and therefore unsuitable to identify whether skin formation affected the pressure build-up during shut-in. The same short shut-in times also create uncertainty in the determination of the pressure derivative from the pressure build-up curve, which has been used for calculating the average permeability of the production interval. A third possible reason is uncertainty in well completion: if the screened sections of the Mezobereny wells are not accurately aligned with the sandstone intervals then the calculations in Table 1 will be inaccurate. Given these issues, the permeability values calculated in Table 1 must be regarded as only rough estimates. Figure 15: Enlargement of Figure 13d with linear scale, showing estimates of permeability and porosity for different sub-volumes of sample F3, greyscale cutoffs for pore space, and modelled flow directions, fitted using modified Kozeny-Carman curves of the form of Equation (4). Our numerical flow simulations have indicated a range of permeabilities of \(\sim\)150 to \(\sim\)800 mD in the horizontal direction and \(\sim\)250 to \(\sim\)1100 mD in the vertical direction (Figure 13). For comparison, [PERSON] et al. [11] reported \(\sim\)100 to \(\sim\)400 mD in the horizontal direction and \(\sim\)70 to \(\sim\)300 mD in the vertical direction (Figure 16). It is thus evident that [PERSON] et al. [11] regarded this formation as more permeable in the horizontal direction whereas our results indicate greater vertical permeability. However, for both sets of measurements, the difference between horizontal and vertical permeability is small compared with the range of values measured in either direction. Likewise, as already noted, the [PERSON] [23] dataset indicates that the horizontal permeability typically exceeds the vertical permeability by \(\sim\)50%, both values being typically in the range \(\sim\)100-200 mD. Furthermore, our estimates of porosity for the high-value greyscale cutoff (Figures 13c,d and 15) are in good agreement with the \(\sim\)0.24 expected value for a sample from \(\sim\)1900 m depth, after Almasi [23]. Our numerical simulations are based on a single core fragment, F3, from well Gyoma-1 (Figure 1), and cannot necessarily be considered representative of the Ujfalu Fm. either at Mezobereny or for the Bekes Basin in general. The apparent higher permeability perpendicular to the bedding might be a real feature of the core from the Gyoma-1 well, conceivably through diagenesis, but might potentially instead have arisen from the image processing workflow in which the initial suite of two-dimensional X-ray projections has been reconstructed into a three-dimensional volume, then transformed into a series of slices in planes perpendicular to the z-axis (Figure 4); the [PERSON] et al. [11] and [PERSON] [23] datasets favour the latter interpretation. Furthermore, the wider range in permeabilities from the flow modelling could be because of the smaller volumes analyzed compared to [PERSON] et al. [11], which makes it possible to capture high porosity and low porosity sub-volumes separately from each other, whereas in a core-scale experiment these would average out.