Origin, migration and secondary processes of oil and natural gas in the western part of the Polish Outer Carpathians: geochemical and geological approach

The origin, migration pathways, as well as the influence of secondary processes of oil and natural gas accumulated in lower Cretaceous to lower Miocene strata of the western part of the Polish Outer Carpathians (between Kraków and Pilzno towns) based on results of organic geochemical analyses are investigated in this paper. Oil and thermogenic hydrocarbon gases were generated mainly from type II kerogen, and type II and III kerogen mixed in various proportions. These kerogens mainly occur in the Oligocene Menilite beds of the Silesian and Dukla nappes. Oils were generated from early to late “oil window”. Secondary cracking was recorded in oils from Dukla nappe, other secondary processes including biodegradation, water washing and evaporative fractionation were also developed to a various extent in many oils. The most biodegraded oils occur in seep S-Li, and the most extensive water washing is observed in the oil from seep S-Sa/1. The evaporative fractionation processes most significantly occur in the selected deepest parts of the multi-horizontal Biecz field. Hydrocarbon gases originated during both microbial and thermogenic processes of organic matter transformation. Natural gas has not been subjected to biodegradation processes. Carbon dioxide is derived from both microbial and thermogenic decomposition processes of organic matter and was generated together with hydrocarbon gases.


Introduction
The study area of the western part of the Polish Outer Carpathians between the towns of Kraków and Pilzno (Fig. 1a) covers about 950 km 2 . Oil, condensate and gas fields were discovered in sandstone reservoirs within the lower Cretaceous to lower Miocene lithostratigraphic units in the Silesian, Dukla and Magura nappes of the Polish Outer Carpathians (Fig. 2). Some oil and gas fields occur at shallow depths, where circulation of edge water can be observed (Karnkowski and Konarski 1973;Karnkowski 1999), creating suitable conditions for secondary processes of biodegradation and water washing. At the same time effective source rocks generate petroleum from strata within deeply buried Dukla nappe beneath the Magura nappe , where oils may undergo secondary cracking. Oil with associated natural gas and non-associated natural gas occur in sandstone reservoirs, having distinct geochemical signatures indicating a range of genetic and post-accumulation histories.
The aim of this paper is establishing the origin, migration and mixing of oil and natural gas and influence of secondary processes (biodegradation, water washing, cracking and evaporative fractionation), occurring in the study area ( Fig. 1) based on the results of oil analyses of sulphur content, vanadium and nickel concentrations, GC and GC-MS analyses (fraction composition, n-alkanes and isoprenoids distribution, biomarker composition of saturated and aromatic hydrocarbon fractions) and stable carbon isotope composition of oil and its four fractions, as well as gas analyses of molecular composition of hydrocarbon and non-hydrocarbon components, and stable carbon and hydrogen isotope composition of hydrocarbon components and carbon dioxide. Interpretation of results of mentioned above analyses is performed in relation to geological setting and genetic type and maturity of source rocks.

Geological setting
The Carpathian Mts. form an almost perfect arc extending from the Vienna Basin in the west through Slovakia, Poland and Ukraine to Romania in the southeast (Fig. 1a). The Carpathian Orogen comprises two main tectonic zones of different geological settings and history: the Outer and the Inner Carpathians (see e.g. Oszczypko et al. 2008). The Inner Carpathians are the older (late Cretaceous) fold belt whereas the Outer Carpathians are the younger (Oligocene-middle Miocene) fold-and-thrust belt, known also as the Flysch Carpathians. The nappes of the Outer Carpathians form a strongly arcuate (oroclinal) fold-and-thrust belt overthrusted along its full length onto the younger foreland molasses, which cover (with a stratigraphic gap) the Meso-Palaeozoic structural stages of the platform slope or rest directly upon the Precambrian basement.
The Outer Carpathians comprise a number of nappes and slice-folds containing various lithostratigraphic profiles and showing complicated tectonic styles (Figs. 1, 2) (e.g., Golonka et al. 2011;Siemińska et al. 2018;Waśkowska et al. 2018). The lithostratigraphic profiles are dominated by upper Jurassic to lower Miocene, deep-marine, siliciclastic strata (see e.g. Oszczypko et al. 2008) deposited in separate sedimentary basins, each of them showing different geological development. In the late Oligocene-middle Miocene, the flysch strata were detached from the basement and thrusted over both the West and the East European platforms (see e.g. Cieszkowski et al. 1985;Oszczypko 1992). From the south to the north of the Polish Outer Carpathians, the nappes occur: Dukla, Silesian, Sub-Silesian and Skole.
The study area includes the Silesian and Magura nappes, parts of the Dukla (Grybów) nappe exposed in the tectonic windows and the Silesian nappe (Fig. 1a). Each nappe comprises its own stratigraphic sub-units and zones, which reveal specific lithostratigraphic columns (Fig. 2) and/or specific patterns of tectonic deformations. The spatial relations of these three nappes and structure of Kryg-Libusza-Lipinki and Fellnerówka-Hanka fields in the Silesian nappe within the study area are shown in Figs. 3 and 4, respectively. Their lithostratigraphic profiles comprise depositional systems ranging from the late Jurassic through the whole Cretaceous up to the early Miocene, composed of various associations of clayey-sandy strata dominated by turbidites and other sand-mud gravity flow deposits accompanied by minor carbonates and pyroclastics (Fig. 2). The division of these lithostratigraphic sequences into formal (Formation) or informal (beds, shales) units remains unresolved (e.g., Dziadzio et al. 2006).

Petroleum occurrence
In the study area, a total of 19 oil and gas fields have been discovered, in that 7 oil and 4 gas fields in the Silesian nappe (Table 1), 4 oil and 1 oil-condensate-gas fields in the Dukla (Grybów) nappe (Table 2) and 3 oil fields in the Magura nappe ( Table 2). Exploitation of oil began in 1858 (Klęczany field) and natural gas production in 1939 (Szalowa-Heddy-Bystra field) (Tables 1, 2). Eleven fields had been discovered already before World War II (Tables 1, 2). At present, only six oil fields and three gas fields are exploited (Tables 1, 2).
Crude oil samples were collected in a glass container (~ 1000 cm 3 ) from the separators or wellheads of producing wells and from seeps. Free gas samples were collected directly at the wellhead into a metal container (~ 1000 cm 3 ) with head pressure at least 5 MPa. Associated gases (dissolved in oil) were taken from a separator into a glass container (~ 500 cm 3 ) at pressures of at least 0.2 MPa. Natural gases from seeps were collected to glass containers filled with NaCl-saturated solution. General information on the sampling sites is given in Table 3, whereas their locations are shown in Fig. 1.
In Leśniówka-2 (Le-2) well a gas-condensate accumulation was found within the upper Cretaceous-Palaeocene beds (Dukla nappe) at a depth of 4043-4210 m (Table 3). However, technical conditions were very bad, cementing of the lining pipe was wrong, and gas escaped to the surface. The migration of methane and higher hydrocarbons to the near-surface zone may be hazardous to buildings and 1 3   Ślączka and Kamiński (1998), Dziadzio et al. (2006Dziadzio et al. ( , 2016 and Kotarba et al. (2020a, b) showing distribution of petroleum reservoirs and source rock horizons after Kotarba and Koltun (2006) and Kotarba et al. (2013Kotarba et al. ( , 2014Kotarba et al. ( , 2020a Figure 4a), Dominikowice-Kobylanka, Fellnerówka-Hanka (cf. Figure 4b) and Biecz fields and modified after Kuśmierek and Baran (2013), and distributions of  Tables 4, 5, 6, 7, and for natural gases in Table 9. Biodegradation level for oil listed in Table 5. a.s.l. above sea level, Aro aromatics; ΣMN sum of methylnaphthalenes 1 3  Table 1 Oil and gas fields of the Silesian nappe in the study area, years of their discovery and abandoned, and new and previously published oil and gas samples from wells used for genetic interpretation El-58 oil sample from well, Bn-6 gas sample from well, Dl-25 oil and gas samples from well, L. Mioc. lower Miocene, Olig. Oligocene, Pal. Palaeocene, U. Cr. upper Cretaceous, OIL oil with dissolved gas, GAS free gas, X reservoir horizon (no analysed) Geochemical data after: a Kotarba and Nagao (2008), b Kotarba et al. (2009), c Kotarba et al. (2013), d Matyasik and Dziadzio (2006) (Table 3) were collected in selected holes situated about 5 m to W and 10 m to SW from Le-2 well, respectively ( Fig. 1a and Table 3). After the installation of a special probe, near-surface gas samples were collected from the deepest 1.0 m interval of the holes and transferred into 1000 cm 3 volume glass vessels filled with saturated NaCl solution. Such sampling depth enabled us to eliminate the impact of atmospheric air (Klusman 1993;Saunders et al. 1999;Tedesco 1995). The results of the previous geochemical studies of 15 crude oil (ten Haven et al. 1993;Więcław 2002;Matyasik and Dziadzio 2006) and 17 natural gas (Kotarba 1987(Kotarba , 1992Kotarba and Nagao 2008;Kotarba et al. 2009Kotarba et al. , 2013Kotarba et al. , 2017 samples from 11 fields, one uneconomic accumulation and 3 seeps in the study area were also used for genetic interpretation. Locations of these fields and samples are shown in Fig. 1.

Analytical procedure
Oil Oils were analysed for the American Petroleum Institute (°API) gravity using an Anton Paar DMA™ 5300 M density meter and for sulphur content with a Leco ® SR-12 analyzer. Before fractionation by column chromatography, the oils were topped under nitrogen (5 h) at a temperature of 60 °C and the asphaltene fraction was precipitated from oil with petroleum ether. The maltenes were separated into fractions of saturated hydrocarbons, aromatic hydrocarbons and resins by column chromatography using alumina/silica gel (2:1 v/v) columns (0.8 × 25 cm). The fractions were eluted with petroleum ether, toluene and toluene:methanol (1:1 v/v), respectively. The oils and their individual fractions were combusted in an on-line system for the measurement of stable carbon isotope composition. The stable carbon isotope analyses were performed using a Thermo Scien-tific™ Delta V Plus mass spectrometer (MS) and the results are expressed in the δ-notation (δ 13 C, ‰) relative to the VPDB (Coplen 2011) using international standard NBS 22 for isotopic normalization. Analytical precision established as standard deviation from 10 measurements is estimated to be ± 0.2‰. Whole oils were analysed by high resolution gas chromatography using a Hewlett ® Packard 5890 series II gas chromatograph (GC) equipped with a flame ionization detector (FID). The isolated saturated hydrocarbon fractions were diluted in isooctane and analysed by a GC coupled to a mass selective detector (MSD) for biomarker composition. The analysis was carried out with an Agilent 7890A GC Table 2 Oil and gas fields of the Dukla and Magura nappes in the study area, years of their discovery and abandoned, and new and previously published oil and gas samples from wells used for genetic interpretation Sl-7 oil sample from well, Sl-20 gas sample from well, U. upper; Pal. Palaeocene, Cr. Cretaceous, OIL oil with dissolved gas, GAS free gas, X accumulation occurs (no analysed) a Cisna beds in the Dukla nappe and Ropianka Formation in the Magura nappe (= equivalents of Inoceramian beds) Geochemical data after b Kotarba (1987), c Kotarba (1992), d Kotarba et al. (2009) equipped with the Agilent 7683B automatic sampler. The aromatic hydrocarbons fractions of the oils were analysed by the GC-MSD for naphthalene, phenanthrene, dibenzothiophene and their methyl derivatives and triaromatic steroids relative concentrations. The analysis was carried out using the same equipment as for the saturated hydrocarbon fraction. Details of analytical procedures of oils were described in Kotarba et al. (2019Kotarba et al. ( , 2020a.

Natural gas
Molecular compositions of natural gases (CH 4 , C 2 H 6 , C 3 H 8 , i-C 4 H 10 , n-C 4 H 10 , i-C 5 H 12 , n-C 5 H 12 , C 6 H 14 , C 7 H 16 , CO 2 , O 2 , H 2 , N 2 , He) were analysed in a set of columns on two Agilent 7890A GCs equipped with a gas sampling valve plumbed with a dual sample loop. Stable carbon isotope analyses were performed using a Finnigan™ Delta Plus mass spectrometer (MS) coupled through a GC combustion III interface with a 6890 gas chromatograph. Methane, ethane, propane, butanes, pentanes and carbon dioxide were separated chromatographically, and carbon dioxide produced by the on-line system was transmitted to the MS. The stable carbon isotope data are expressed in the δ-notation (δ 13 C, ‰) relative to VPDB (Coplen 2011). The stable hydrogen isotope analyses of methane, ethane and propane were performed in a Thermo Scientific™ Delta V™ Plus MS connected through Conflo IV and GC Isolink™ interfaces with a Trace GC Ultra chromatograph. The stable hydrogen isotope data were reported in δ-notation (δ 2 H, ‰) relative to VSMOW (Coplen 2011). The stable nitrogen isotope analyses were performed using a Finnigan™ Delta Plus MS coupled through a GC combustion III interface with a 6890 gas chromatograph. Molecular nitrogen was separated chromatographically for stable nitrogen isotope analysis and was transmitted to the MS via the on-line system. The results of stable nitrogen isotope analysis were presented in the δ-notation (δ 15 N, ‰) relative to atmospheric nitrogen. Details of analytical procedures of natural gas were described in Kotarba et al. (2019Kotarba et al. ( , 2020a and Więcław et al. (2020).

Oil
The analysed crude oils accumulated in the Upper Cretaceous-Palaeocene to Oligocene sandstone reservoirs in the study area (Table 3) vary in their physical and geochemical properties. Gravity of oils varies from 24.5 (S-Sy/1) to 45.1 °API (S-Kl) (values from 30 to 40 °API dominate), density from 0.797 to 0.903 g/cm 3 with sulphur content ranging from traces (S-Kl) to 0.27 wt% (Pl-8) (average 0.14 wt%) ( Table 4). The concentration of saturated hydrocarbons usually exceeds 50 wt%. The lowest content of this fraction was recorded in the Jo-44 oil (41.8 wt%, Table 4). Correspondingly, in all analysed oils, low content of asphaltenes (below 5 wt%) was recorded. This fraction's highest content was recorded in oil samples taken from Jo-44 and Pl-8 (10.9 and 10.4 wt%, respectively) (  (Table 4). Selected indices calculated based on crude oil GC-FID analysis are presented in Table 5. GC analyses indicate that most oils have a full range of n-alkanes (up to C 35 ). The CPI (formula see Table 5) values are near or greater than 1.0, except for sample Ha-6. Pristane/phytane (Pr/Ph) ratio values are above 2.0, with a maximum value of 3.41 for Dl-25 oil (Table 5). Only for sample Dl-51 Pr/Ph ratio is 1.04. Selected indices calculated based on sterane and terpane distributions and relative concentrations of n-alkanes, isoalkanes and steranes + terpanes of currently analysed oils are presented in Table 6. The sterane/terpane ratios are similar for oils from Silesian and Magura nappes, with average of 0.32; also the tricyclic/pentacyclic terpane ratios for these oils are close-on average of 0.07 (for the explanation of formulas, see Table 6). Only both oils collected from Dukla nappe have elevated values, over 0.41 and 0.14.
The relative concentration of regular 20R C 27 , C 28 and C 29 steranes for all oils, except Go-2 and S-Kl samples, is similar and ranges from 30 to 40% for each component. For the oils from S-Kl seep and Go-2 well, the relative concentration of 20R C 29 regular sterane is higher and equals 42%; correspondingly, these oils contain the lowest 20R C 27 regular sterane. For all oil samples, values of C 29 20S/(20S + 20R) ratio are above 0.30, and Ts/(Ts + Tm) values are greater than 0.4. The only exception is for Jo-44 oil, where these indices are 0.29 and 0.16, respectively ( Table 6). The values of C 29 ββ/(ββ + αα) index are at least 0.34. The above-mentioned elevated values of C 29 ββ/(ββ + αα) index correlate with high values of C 27 dia/(dia + reg) ratio, up to above 0.5 for Le-2, Sl-13, S-Kl and S-Li oils. The C 31 homohopane 22S/(22S + 22R) ratio values are all approximate 0.55 (Table 6). Values of C 24 t/C 23 t and C 22 t/C 21 t ratios of tricyclic terpanes vary from 0.52 to 1.08 and from 0.07 to 0.49, respectively. In all oils, the gammacerane/17α hopane ratio (GI) is not higher than 0.1 ( Table 6). The C 29 norhopane/17α hopane ratio is consistently below 0.1 and C 35 /C 34 ratio below 1.0, respectively. There is a visible distinction in oil indices among oil from Dukla nappe and remaining oils (from Silesian and Magura nappes).
Indices calculated based on GC-MS analysis of the aromatic hydrocarbon fraction of analysed oils are presented in Table 7. For all oils, the MPI index (Radke et al. 1982) ranges from 0.44 to 1.24. The elevated values above 1.0 were recorded for Dl-25 (Silesian nappe, Biecz field) and all oils accumulated in Dukla nappe. The highest MDR ratio values (Radke et al. 1986) are noted for the same oils. In contrast, some oils collected from seeps in Magura nappe have low values (below 2.0). All oil samples are characterised by a dibenzothiophene/phenanthrene ratio below 0.15. Values of short-chain to long-chain triaromatic steroids ratio [TA(I)/ TA(I + II)] range from 0.07 to 0.99. This index's highest values (greater than 0.2) come from samples Dl-25 and Dl-51 (both from the Biecz field in the Silesian nappe), all oils from Dukla nappe and S-Li from the Magura nappe. The highest contents of methyl-and dimethylnaphthalenes were recorded in oils Wl-15 and S-Li (above 100 ppm and 2000 ppm, respectively). In contrast, the lowest concentrations of MN and DMN were measured in the Le-2 oil. In some oils, renieratane, a significant amount was recorded: So-9, El-58, Jo-44 and Wl-15 (Table 7).

Origin
For the evaluation of oil origin results of bulk oil analyses, distribution of biomarkers and stable carbon isotope composition were applied. The sulphur concentration below 0.5 wt%, mostly at gravities below 40 °API suggests a connection of the analysed oils with the low-sulphur type II kerogen (Orr 2001). However, generation from type III or type I kerogen is also possible (Duan et al. 2009). The CPI values above 1.0 indicate that shales are the dominating source of rock lithology (Moldowan et al. 1985). The above suggestion is supported by the V/(V + Ni) values ranging from 0.06 to 0.10 (Lewan 1984). Also values of saturate/aromatics ratio ranging from 1.5 to 26.7 (average 5.1, Table 4) suggest the PMM and TG generation of hydrocarbons from organic matter present in shales (Palacas 1984). Some oils are characterised by a reduced range of n-alkanes and higher iso-alkanes concentrations (Fig. 5a, b). In two samples (S-Li and S-Sa/1 from the Magura nappe), the concentrations of n-alkanes relative to the sum of n-alkanes, iso-alkanes and steranes + terpanes are very low and do not exceed 2% (Table 6). Correspondingly, the last-mentioned oil (S-Sa/1) is characterised by the highest relative concentrations of steranes and terpanes (13%) ( Table 6). It is an effect of biodegradation, which is widely described in chapter about secondary processes. The C 24 t/C 23 t and C 22 t/C 21 t tricyclic terpane ratios above 0.5 and below 0.5, respectively, indicate that all oils were generated from organic matter deposited in marine shales (Peters et al. 2005, p. 558). Both indices' narrow ranges suggest a common source or sources containing the same organic material deposited in similar conditions. The prevalence of siliciclastics in the mineral matrix of the source rocks is also supported by low values of the C 29 norhopane/17α hopane ratio (less than 0.5) and C 35 /C 34 ratio (below 1.0), and high values of C 27 dia/(dia + reg) ratio, up to about 0.7 (Table 6) (ten Haven et al. 1988). The Pr/n-C 17 and Ph/n-C 18 ratios range from 0.99 to 24.4 and from 0.42 to 29.8, respectively. Oils from S-Li and S-Sa/1 seeps have the highest values of these ratios. A set of indices calculated based on C 6 -C 8 hydrocarbons distribution is presented in Table 5. These indices have similar values for most oils collected from producing wells and are distinctly different for oils from seeps. Distributions of n-alkanes are variable, usually mono-modal, with a distinct maximum in the short-chain range (C 8 -C 11 , Fig. 5c), characteristic of hydrocarbons generated from marine organic matter (e.g., Bourbonniere and Meyers 1996). Visible irregularities are the result of secondary processes to be discussed later (Fig. 5a, b). The mono-modal distribution of n-alkanes may also result from increased maturity and/or fractionation during migration. The correlation of the Pr/n-C 17 and Ph/n-C 18 indices (Fig. 6) simultaneously suggests that mixed terrestrial and marine kerogen is responsible for the generation of analysed oils. The conclusions about II/III type kerogen are supported by the interpretation of the isoheptane (IHR) and heptane (HR) ratios (Fig. 7a). The highest share of the terrigenous organic matter in the source kerogen is indicated for oil from the Biecz (Dl-25 and Dl-51), Limanowa-Słopnice (Le-2) and Klęczany fields (S-Kl). The interpretation of some oils' origin (Pl-8, S-Sy/1, S-Sa/1 and Wl-15) in Fig. 8a may be erroneous due to biodegradation processes affecting the composition of hydrocarbons. The canonical n-C17 n-C18 n-C19 n-C20 n-C21 n-C22 n-C23 n-C24 n-C25 n-C26 n-C27 n-C28 n-C29 n-C30 n-C31 n-C32 n-C33 n-C34 n-C35 Pr Ph n-C19 n-C20 n-C21 n-C22 n-C23 n-C24 n-C25 n-C26 n-C27 n-C28 n-C29 n-C30 n-C31 n-C32 n-C10 n-C11 n-C12 n-C13 n-C14 n-C15 1 3 variable (CV) values below 0.47 (Sofer 1984) indicate that analysed oils were generated from marine kerogen (Table 4). Dibenzothiophene/phenanthrene and pristane/phytane (Pr/ Ph) ratios identify the depositional environment of source rocks primarily as marine or lacustrine shales deposited under the anoxic/non-sulfidic conditions based on the criteria of Hughes et al. (1995). Gammacerane widely occurs in the analysed oils in low concentrations (Table 6), as noted in previous studies (ten Haven et al. 1993;Matyasik and Dziadzio 2006). It indicates that a stratified water column in source-rock depositional environments was not present .
The distribution of C 27 , C 28 and C 29 regular 5α,14α,17α(H)-20R steranes in the crude oils is routinely used for identifying their source organic matter (Huang and Meinshein 1979). Generally, the relative proportion of sterane carbon numbers in the analysed oils indicates a mixture of marine plankton and land plants as the source of organic matter. Values of the analysed oils' sterane/terpane ratio (S/T) are usually in a narrow range of 0.26-0.45 (Table 6). It suggests that they come from a source rock enriched in terrigenous and/or reworked material (e.g., Moldowan et al. 1985). This conclusion is supported by mainly low values of the tricyclic/pentacyclic terpane ratio (Table 6). However, low values of this ratio are also found in freshwater depositional environments (Tao et al. 2015). The elevated values of this index, up to 0.75, are observed in oils accumulated in Dukla nappe and are connected with their increased maturity (Peters et al. 1990). The Carpathian fine-grained rocks (especially Oligocene Menilite and Krosno beds) often contain allochthonous, reworked organic material (Zielińska 2017;Waliczek et al. 2019) from eroded Pennsylvanian-age rocks. These particles' contribution to the organic matter mass is variable and decreases with total organic carbon content (Zielińska et al. 2020). In all oils collected from Silesian and Magurs nappes, β-carotane was identified ( Table 6). The presence of this biomarker suggests a saline lacustrine or highly restricted marine depositional setting (Peters et al. 2005). In many oils, also isorenieratane, the β-carotene diagenesis product (Koopmans et al. 1996) was recorded ( Table 7). The stable carbon isotope composition of the crude oils and their fractions (Table 4) generally support the biomarker data. They indicate that the analysed oils were generated from the same genetic type of kerogen. In most oils, asphaltenes are depleted in 13 C isotope relative to resins, which is characteristic of oil generated from algal kerogen (Galimov 2006). Because the aromatic hydrocarbon and asphaltene fractions are more resistant to biodegradation (Sun et al. 2005), the oil-oil correlation is more reliable using the stable carbon isotope composition of these fractions. Asphaltenes of all oils accumulated in the Silesian nappe show a narrow range of δ 13 C values (− 27.5 ± 1‰), suggesting one common source. Visible enrichment in 13 C of oils (and their fractions) accumulated in Dukla and Magura nappes suggests their genetic relation. It indicates a higher share of terrigenous material in source organic matter. The presence of oleanane in all oils (Table 6), a biomarker derived from angiosperms widely occurring in Cretaceous or younger organic matter (Ekweozor and Udo 1988), points to organic-rich Oligocene Menilite beds and Upper Cretaceous-Palaeocene Istebna shales (Matyasik and Dziadzio 2006) as the most probable source rocks.

Maturity
The maturity of crude oils was determined based on the composition of light hydrocarbons (Table 5), selected biomarkers (Table 6), and indices calculated from relative concentrations of phenanthrene (Phen) and dibenzothiophene (DBT) and their methyl derivatives, as well as triaromatic steroids (Table 7).
The distribution of methylphenanthrenes (MP) reveals a wide range of oil maturity. The methyl phenanthrene index (MPI1) (Radke et al. 1982) indicates generation from early mature to the late phase of the oil window (calculated vitrinite reflectance, R cal(MPI1) from 0.63 to 1.13%) ( Table 5 and Więcław 2002). The methyldibenzothiophene ratio (MDR) maturity index (Radke et al. 1986) generally confirms the same range of oil maturities (Table 7 and Więcław 2002). Some discrepancies between the measured values, e.g., Le-2 and Sl-13, may be related to the impact of biodegradation and water washing on MDBT isomers' distribution (Ugochukwu et al. 2014).  Shanmugam 1985). For oil codes and symbols, see Table 3. Previously analysed samples after ten Haven et al. (1993), Więcław (2002) and Matyasik and Dziadzio (2006) 1 3 The distribution of steranes is dominated in sample Jo-44 by ααα20R-isomers (Fig. 8e) and change to domination of αββ-isomers in Le-2 (Fig. 8a). Moreover, the increasing role of tricyclic terpanes in the distribution of terpanes from sample Jo-44 (Fig. 8e′) to Le-2 (Fig. 8a′) is also visible. It indicates that analysed oils were generated from the organic matter at different maturities consistent with initial phase to peak of the "oil window". The C 29 20S/(20S + 20R) and C 29 ββ(ββ+αα) sterane ratios show that the lowest maturity oil is the F-8 sample (Fig. 9) and the highest-oils collected from Słopnice and Klęczany fields. The plot of the C 29 ββ(ββ+αα) ratio versus the 20S/(20S + 20R) ratio for the C 29 steranes (Fig. 9b) shows that the variability of analysed samples' maturity from early mature to peak of the "oil window" generally confirms conclusions from the MPI and MDR interpretation.
The relation between the stigmastane and sum of 3-and 4-methyldiamantane concentration (Fig. 10a) after categories of Dahl et al. (1999) indicates that oils from the Limanowa-Słopnice field and Klęczany seep are at the initial stage of the cracking process. Oils from the Biecz field (Dl-25 and Dl-51) contain elevated amounts of methyldiamantanes and simultaneously high stigmastane concentrations. It suggests that they are mixtures of high-mature cracked und low-mature uncracked oils. Maturity indices calculated based on triaromatic steroids distribution are effective even for oils with extensive water washing (Chang et al. 2018) and highly sensitive, especially for high maturity samples (Mackenzie et al. 1981). Heating experiments of Beach et al. (1989) indicate that the TA(I)/TA(I + II) ratio (Table 7, Fig. 10b, c) increases due to preferential degradation of the long-chain triaromatic homologs rather than due to the conversion of long to short-chain homologs. The highest maturities, above 1.0% in Ro scale (based on MPI1, sterane and TA[I]/TA[I + II] indices), were recorded for oils accumulated in the Dukla nappe (Limanowa-Słopnice and Klęczany fields and oil outflows in Karczyska, Pod Rosochatką and Stara Wieś) (Tables 6, 7, Więcław 2002;ten Haven et al. 1993).

Secondary processes
The physical and geochemical properties of migrating oil or oil accumulated in a field may be changed by secondary processes, such as biodegradation, fractional evaporation, cracking or water-washing (e.g., Connan 1984;Thompson 1983Thompson , 2010Palmer 1984Palmer , 1993. In the Magura nappe, a total of three insignificant oil and gas fields have been discovered (presently abandoned, Table 2). Most of the analysed oil from seeps occur in the Magura nappe (Table 3). In this tectonic unit's lithostratigraphic profile, Oligocene Menilite beds are characterised by poor source indices, and other source rocks do not occur (e.g., Sachsenhofer et al. 2017). Oil and natural gas migrated to traps in the Magura nappe from the Dukla and Silesian nappes and flew out to the surface, creating seeps, got partly oxidised or escaped to the atmosphere (Fig. 3).
Crude oil deposits in the Outer Carpathians have very favourable conditions for microbial activity due to reservoir temperatures, generally up to 55 °C (Karnkowski, 1999), and the introduction of water in the traps. Marcinkowski and Szewczyk (2008) reported that the extraction of water from oil fields in the eastern part of the Silesian nappe of the Polish Carpathians was sometimes four times higher than oil production. The highest water/oil ratio values were recorded for the shallowest traps within the Oligocene-lower Miocene Krosno beds (Marcinkowski and Szewczyk 2008).
The simplest and most sensitive method for identifying and estimating the extent of secondary processes is the  Fig. 7 a Heptane ratio and b toluene/n-heptane ratio versus isoheptane ratio. Kerogen type curves and maturity ranges after Thompson (1983). For oil codes and symbols, see Table 3. Oils collected from seeps are marked by symbols with thick outline complete oil GC analysis and the examination of the distribution of n-alkanes, iso-alkanes, acyclic isoprenoids, and short-chain hydrocarbons (C 6 -C 8 ) (Halpern 1995;Thompson 1987;Wenger et al. 2002;Więcław et al. 2020). The Pl-8 chromatogram presents a full range of n-alkanes and low content of isoprenoids (Fig. 5c). According to Wenger et al. (2002), this type of distribution is characteristic of non-biodegraded oils. More extensive biodegradation causes a reduction in the range and relative concentration of n-alkanes, first revealed in Carpathian oils by Gondek and Pomykała (1982). At very slight biodegradation levels (Wenger et al. 2002), the relative concentrations of pristane and phytane (acyclic isoprenoids) are comparable with the neighbouring n-alkanes. Slight biodegradation results in Fig. 9 Sterane C 29 20S/ (20S + 20R) ratio versus a Ts/ (Ts + Tm) and b C 29 ββ/(ββ+αα) ratios for oils. Maturity fields after Peters and Moldowan (1993). For oil codes and symbols, see Table 3. Previously analysed samples after ten Haven et al. (1993) and Matyasik and Dziadzio (2006)  the domination of isoprenoids over neighbouring n-alkanes (Fig. 5b) and a "hump" representing an unresolved complex mixture (Wenger et al. 2002). The increased biodegradation level (moderate level) significantly reduces the concentration of n-alkanes, causing raised values of the Pr/n-C 17 and Ph/n-C 18 ratios (Table 5, Figs. 5a,6). The increase in the extent of biodegradation to the heavy level results in the elimination (decomposition) of acyclic isoprenoids (Wenger et al. 2002).
None of the oils in this study have reached this level of biodegradation. The above-mentioned hydrocarbon groups are not affected and the ratio of C 29 25-norhopane (biomarker created as a product of biodegradation of C 30 hopane, Peters et al. 1996) to C 30 hopane of the oils is low (Table 6). In this study, the level of biodegradation is illustrated quantitatively by the relative proportions of n-alkanes, isoalkanes, and steranes plus hopanes (Table 6, Fig. 11). It is useful if the extent of biodegradation is not severe (steranes and hopanes remain unaltered, Więcław et al. 2020).
In the case of crude oil from the Biecz field (samples Dl-25 and Dl-51), significant differences in biodegradation level are observed (Table 6, Figs. 7,11), although the accumulation depths are similar. The Dl-51 oil comes from the deepest SW tectonic element of the deposit (Fig. 1b). The other crude oil (Dl-25) comes from a shallower element located on another tectonic block. This may mean that the migration of fluids takes place in the SE-NW direction, and the pathways through which microorganisms enter the beds are S-N faults (Fig. 1d).
According to Thompson's (1987) criteria (Fig. 7), the highest biodegradation level was recorded in oils from Pl-8 well and S-Sa/1 and S-Sy/1 seeps. This conclusion is consistent with the biodegradation evaluation by other criteria for oils collected from seeps (Table 5 and Figs. 5,11), whereas the oil Pl-8 is not biodegraded and probably water washing (Fig. 5c) influenced the distribution of C 7 hydrocarbons.
Because the higher density is generally associated with biodegraded oils (Baskin and Peters, 1992), the highest density oil, S-Sy/1 (0.903 g/cm 3 , 24.5 °API, Table 4), should be heavily degraded. This oil is evaluated in Wenger's et al. (2002) criteria as only slightly biodegraded. This sample was taken from a seep and the evaporation of low boilingpoint compounds (Fig. 5b) has caused the lowering of the API gravity. Two other oils from seeps: S-Li and S-Sa/1, also have low gravities and are biodegraded (Fig. 5). The sulphur content of the analysed oils varies from traces in S-Kl to 0.27 wt% for oil from the Pl-8 well (Table 4). Because all biodegraded and non-biodegraded oils in this study have low sulphur concentrations, this parameter does not correlate with biodegradation level. However, Więcław (2002) found a significant increase in the sulphur content during biodegradation of crude oil from seeps in Stara Wieś (S-SW/1 and S-SW/2), Pod Rosochatką (S-PR/1 and S-PR/2) and Karczyska (S-Ka/1 and S-Ka/2). The content of the saturated hydrocarbon fraction in the analysed oils is consistent with the level of biodegradation. Non-biodegraded oils have ± 70% aliphatic hydrocarbons on average and biodegraded oils have ± 55% (Table 4). Lowered values of saturates/aromatics ratio are observed in oils with elevated biodegradation levels (Table 4).
To sum up, the extent of biodegradation ranges from nondegraded to moderately degraded. The most degraded oils occur in seeps S-Li and S-Sa (upper Cretaceous-Palaeocene Ropianka Formation).
A significant reduction in the concentration of methylnaphthalenes (MN) and dimethylnaphthalenes (DMN) in the aromatic fraction of oil and simultaneously a decrease in naphthalene/phenanthrene (Naph/Phen) and methylnaphthalenes/dimethylnaphthalenes (ΣMN/ΣDMN) ratios indicate an increased extent of water washing due to differences of water solubility of the mentioned hydrocarbons (Forsythe et al. 2017). The highest content of MN and DMN and highest values of Naph/Phen and ΣMN/ΣDMN ratios are recorded for oils from the Wl-15 and SB-32 wells and S-Li seep. It suggests that these oils undergo the water washing process on a reduced scale (Fig. 12). The other oils have probably experienced water washing, with the most significant extent of this process recorded in the Sl-13 and Le-2 oils (Fig. 12). However, Mikołajewski et al. (2019) evidenced that the migration process also controls the relative abundance of MN and DMN. In the Outer Carpathian region, shallow deposits have had significant water exposure due to the long exploitation history and rising of the oil-water contact (Dziadzio et al. 2006;Marcinkowski and Fig. 11 Ternary diagram of relative concentrations of sum of isoalkanes, sum of n-alkanes and sum of steranes and terpanes. For oil codes and symbols, see Table 3 Szewczyk 2008). Thus widespread water washing is not surprising.
Analysing relationships between concentrations of the above-mentioned aromatic hydrocarbons and calculated ratios (Fig. 12), two populations are different in the concentrations of MN and DMN. Oil characterised by MN concentration below 5 ppm is evaluated as significantly water washed (S-Sa/1, Sl-13 and Le-2). The remaining oils were evaluated as being subjected to minimal water-washing.
In all analysed oils, methylcyclohexane (MCH) dominates over n-heptane resulting in the n-heptane/MCH ratio values from 0.14 to 0.48 (Table 5). Compared with elevated values of toluene/n-heptane ratio (usually above 1.0), these values indicate that all the oils have experienced evaporative fractionation (Thompson 1987;Holba et al. 1996). A significant evaporative fractionation developed in oils from Dl-25 and Dl-51 wells in Biecz field and Le-2 in Limanowa-Słopnice field (Fig. 7b). For the rest of the analysed oils, the evaporative fractionation process has been minimal (early phase of fractionation and possible biodegradation, according to Thompson (1987) and Holba et al. (1996). The extent of evaporative fractionation in oils collected from seeps in Magura nappe is hard to evaluate due to the biodegradation or evaporation of the low-boiling compounds (Table 5). Concluding, the evaporative fractionation processes occur in all reservoirs of the study area, most significantly in the deepest parts of the selected multi-horizontal Biecz field.

Hydrocarbon gases
Stable carbon and hydrogen isotope and molecular compositions evidence the existence of two genetic groups of hydrocarbon gases-microbial and thermogenic ones, as shown on diagrams on Fig. 13. Microbial and thermogenic gases occur regardless their accumulation type in a particular nappe or reservoir (Fig. 13). Thermogenic gases were mainly produced from a source rock with the prevailing type III or mixed type II/III and III/II kerogen at maturity stages representing the whole stage of the "oil window" (Fig. 13). Natural gas in samples Le/6 and Le/21 collected from nearsurface zone near Le-2 well does not contain microbial admixture as might be expected. Its molecular and isotopic signatures indicate that it comes from the same accumulation as natural gas exploited by Le-2 well (Figs. 13, 14a). The geochemical data indicate that the near surface zone adjacent to the well is supplied only by natural gas escaping from the accumulation Limanowa-Słopnice located within the reservoir in the Dukla nappe in the depth below 4000 m due to a leaky cementing of the lining pipe. Natural gas from this accumulation was produced from organic matter of mixed type and shows the highest maturity (Fig. 14). Maturity curves constructed after Faber (1996, 1997) for two different types of kerogen: type II (δ 13 C = − 28.6‰) and III (δ 13 C = − 24.6‰) ) confirm that thermogenic gases in the study area were produced during the whole stage of "oil window" assuming type II kerogen (Fig. 14). If type II kerogen contribution was highest, they might have been produced even during the "gas window" stage, but the common presence of C 2+ hydrocarbons (Table 8) rather preclude the late mature thermogenic gas (Fig. 14). A normal isotopic trend of δ 13 C values is observed in all analysed gases as evidenced in the diagram plotting stable carbon isotope composition of hydrocarbon gases versus the reciprocal of their carbon number constructed after Chung et al. (1988) (Fig. 15). This isotopic order indicates the simple generation (Zou et al. 2007), migration and accumulation processes of studied gases. δ 13 C values of butanes and pentanes reflect their source related to types III, II and mixed kerogens. The shifts of δ 13 C values of methane and ethane, especially demonstrated by gases from Go-11, Go-8 and He-4 wells are the evidence of microbial admixture (Fig. 15). Stable hydrogen isotope pattern of methane, ethane and propane data are uniform for analysed gases indicating similar thermogenic generation history. Methane from S-Li seep and Wl-15 well is enriched in 1 H isotope due to microbial input (Fig. 16). Exceptional δ 2 H arrangement shows natural gas from Ha-6 well in which methane, ethane and propane have very similar values. Relative 2 H enrichment in methane may be caused by gas diffusive migration changing original isotopic ratio (e.g., Qilin 2012). Natural gas in this field most likely contained more microbial components, but due to gas diffusion isotopically light methane For oil codes and symbols, see Table 3 escaped more easily. This conclusion is also supported by relatively low ethane (5.07 vol%) concentration compared to propane (6.66 vol%) and 2 H-enriched ethane compared to methane (Fig. 16), which can result from ethane diffusion from reservoir gas. Microbial gases without thermogenic addition occur in previously investigated accumulations (Kotarba 1992;Kotarba et al. 2009Kotarba et al. , 2013Kotarba et al. , 2017: Gorlice-Glinik (Go-11 well), Kobylanka (Go-8 well) and Szalowa-Heddy-Bystra (He-4 well) fields and Dołuszyce (De-4 and De-6) uneconomic accumulations of the Silesian nappe. Their isotopic similarity suggests a common origin from a comparable source rock, however natural gas in Dołuszyce uneconomic accumulation most likely is derived from the autochthonous Miocene strata of the Carpathian Foredeep and migrated to the Silesian nappe of the Outer Carpathians due to a privileged tectonic setting (Kotarba 1992;Kotarba et al. 2017). Relatively high microbial admixture is observed in Ha-6 well and S-Ta seep of Silesian and Magura nappes, respectively (Fig. 13b). Similarly, both molecular and isotopic signatures of microbial gases suggest the uniform generation processes related to microbial CO 2 reduction (Fig. 13). Natural gas in the study area does not show manifestations of biodegradation (Table 9, Figs. 13, 16, 17) as evidenced by low i-C 4 /n-C 4 values below 1.2, and neither 13 C nor 2 H enrichments in individual hydrocarbon components and also no distinct 13 C enrichment of carbon dioxide (e.g., Pallasser 2000;Milkov 2011;Kotarba et al. 2019Kotarba et al. , 2020a. Natural gas from Wl-15 well of the Dominikowice-Kobylanka field is the only gas showing positive δ 13 C values CO 2 which may result from the secondary microbial methane production (Table 9, Fig. 17).
Natural gas was generated from source rock of Oligocene Menilite beds in Dukla and Silesian nappes, then migrated through fissure zones of overthrusts and porous-sandstones and filled traps in the Magura nappe (Fig. 3). Fig. 13 Genetic characterization and influence of secondary processes of analysed natural gases using δ 13 C(CH 4 ) versus a hydrocarbon index (C HC ) and b δ 2 H(CH 4 ). Compositional fields and arrow directions of maturity and secondary processes after Whiticar (1994) and Milkov and Etiope (2018). Key for sample codes, see Table 3 and previously analysed samples, see Kotarba et al. (2017). CR CO 2 reduction, F methyl-type fermentation, SM secondary microbial, EMT early mature thermogenic gas, OA oil-associated thermogenic gas, LMT late mature thermogenic gas, BIOD. biodegradation, Up. upper, Cret. Cretaceous, Quat. Quaternary  Fig. 14 Genetic characterization of analysed natural gases using δ 3 C(C 2 H 6 ) versus a δ 13 C(CH 4 ) and b δ 13 C(C 3 H 8 ). Vitrinite reflectance curves (R o ) for Type II and III kerogen after Berner and Faber (1996) based on average δ 13 C data for Type II (− 28.6‰) and III (− 24.6‰) kerogen in Oligocene Menilite beds after Kotarba et al. (2017). Key for gas samples codes and symbols, see Table 3. Previously analysed samples after Kotarba et al. (2017) 13 δ C(CH ) (‰)

Fig. 15
Stable carbon isotope composition of methane, ethane, propane, i-butane, n-butane, i-pentane and n-pentane versus the reciprocal of their carbon number for analysed natural gases. In diagrams, the order of δ 13 C values for CH 4 , C 2 H 6 and C 3 H 8 is after Chung et al. (1988). δ 13 C data for Type II (− 28.6‰) and III (− 24.6‰) kerogen from the Oligocene Menilite beds after Kotarba et al. (2017). Key for gas samples codes and symbols, see Table 3. Previously analysed samples after Kotarba et al. (2017)  Genetic characterization and influence of biodegradation of the analysed natural gases using a δ 13 C(CH 4 ) and b C HC gas hydrocarbon index versus δ 13 C(CO 2 ). Compositional fields and directions of maturity and secondary processes for diagram a from Milkov and Etiope (2018) and for diagram b modified from Milkov (2011Milkov ( , 2018. Key for gas samples codes and symbols, see Table 3. Previously analysed samples after Kotarba et al. (2017) δ 13 C values indicate its biogenic origin. CO 2 from Wl-15 well showing δ 13 C of 1.3‰ may be related to secondary CO 2 reduction (e.g., Milkov and Etiope 2018) or dissolution and precipitation processes involving reservoired CO 2 that change its primary isotopic signature, which may also be responsible for 13 C enrichment in CO 2 in samples Dl-25, Ha-6 and S-Li. The effect of CO 2 isotopic fractionation can be also much easier observed in gases containing low concentrations of this component. The origin of CO 2 in the study area is connected with hydrocarbon gas generation associated both with the microbial and thermogenic processes. However, in this case, the thermogenic component prevails (Fig. 17a).

Conclusions
The results of organic geochemical analyses of oils, as well as molecular and isotopic compositions of natural gases associated or non-associated with oil that accumulated in the lower Cretaceous-lower Miocene strata of the Silesian, Dukla and Magura nappes in the study area between Kraków and Pilzno of the western part of the Polish sector of the Outer Carpathians, indicate that: 1. Oils and thermogenic hydrocarbon gases were generated from marine shales containing primarily type II kerogen with admixture III kerogen, and sometimes type I kerogen. The oils from the Dukla and Magura nappes (e.g., Biecz, Limanowa-Słopnica and Klęczany deposits) were generated from organic matter with significant terrestrial admixture. 2. Oils were generated from early through the peak to late "oil window". Secondary cracking was recorded in oils from Dukla nappe. Other secondary processes, including biodegradation, water washing and evaporative fractionation, were also developed in many oils to a different extent. 3. Analysed oils are non-degraded to moderately degraded.
The most degraded oils occur in seep S-Li of the upper Cretaceous-Palaeocene Ropianka Formation (Magura nappe). 4. The most extensive water washing is observed in the oil from seep S-Sa/1 in Sękowa. The remaining oils were evaluated as being subjected to minimal water-washing. 5. The evaporative fractionation processes occur in all reservoirs of the study area, most significantly in the selected deepest parts of the multi-horizontal Biecz field. 6. Hydrocarbon gases are of biogenic origin related to both microbial and thermogenic processes. Hydrocarbon gases show similar stable carbon and hydrogen isotope compositions suggesting their common origin from a source rock with prevailing type mixed III/II and II/III kerogen at maturity levels corresponding to the whole range of "oil window". 7. Molecular and isotopic compositions reveal that natural gas has not been distinctly subjected to biodegradation processes. 8. Carbon dioxide is derived from both microbial and thermogenic transformation processes of organic matter and was generated together with hydrocarbon gases.
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