Assessment of generation temperatures of crude oils
Cs. Sajgo *
Laboratory for Geochemical Research, Hungarian Academy of Science, BudaoÈrsi uÂt 45, H-1112 Budapest, Hungary
Abstract
Biological marker maturity parameters were used to estimate the minimum HC generation temperatures of crude oils from Eastern Hungary. More than 50 oils and oil shows were analysed. Molecular- and homologous-ratios of biolo-gical marker compounds (triterpanes, steranes, mono- and triaromatic steroid hydrocarbons) were used as maturation parameters. The oils have at least ®ve maturity stages, i.e. they have been generated under dierent thermal conditions. The highest reservoir temperature in each group was chosen as the best estimate of the groups' temperature just below the generation temperature, i.e. reservoirs of the group might be expected to be at shallower depths (lower tempera-tures) than those of the generation zone due to vertical migration into pools. For each maturation level, a threshold temperature range for genesis was inferred from reservoir temperatures; they are from 130±135C for the least mature
oils to 210±215C for the most mature oils. In the least mature oils cracking was not observed, hence carbon±carbon
cracking reactions had not taken place during their genesis. The most mature oils are intensively cracked oils; they are almost condensates. Two major genetic groups (families) of oils were found in the area. Both are present in each maturation level. The eects of migration were checked, and no in¯uence on maturation was found. A number of the oils are in overpressured reservoirs within, or just above, the zone of the present-day active oil generation, hence the present-day temperatures of the pools must have been maximum temperatures. Contrary to the traditionally accepted temperature range for petroleum generation±maturation reactions (50±150C), there is strong evidence from this study
that the onset of oil generation requires temperatures higher than 130C and is still proceeding above 215C.#2000
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Keywords:Generation of crude oil; Generation temperature; Maturity parameters; Molecular ratios; Homolog ratios
1. Introduction
Petroleum, with a few exceptions (e.g. Por®r'ev, 1974), is considered to be a thermally-formed fossil fuel, and is one of the most complex and diversi®ed geologic materials. Chemically, crude oils are mixtures of hydro-carbons, containing small amounts of oxygen-, nitrogen-and sulphur-bearing compounds, nitrogen-and traces of metallic constituents. The compositions of oils exhibit a con-siderable variation (Tissot and Welte, 1978, pp. 379±410). Various petroleum classi®cations have been suggested by geochemists and oil re®ners. Re®ners concentrate on the chemical and physical properties of the distillation fractions. Geochemists attempt to correlate oils to source rocks and to rank the extent of their evolution.
Recently, Tissot and Welte (1978, pp. 416±423) pro-posed a new classi®cation.
Classi®cations of petroleum compositions are prone to error because oil-forming processes are complex and because the compositions have not reached thermo-dynamic equilibrium, i.e. they can alter in reservoir (e.g. Evans et al., 1971). Consequently, a given composition can be achieved through dierent pathways. Petroleum compositions are governed by three main factors: (i) the type of source material and rock matrix; (ii) the matur-ity of the source material; (iii) alteration processes in reservoirs. The ®rst factor is a generic one, the second is a genetic one. The eects of the third dierent depend on the situation.
Generally, thermal maturation, deasphalting, biode-gradation and water-washing are considered to be reservoir alteration processes. Each can seriously modify the composition of oils. Reservoir thermal maturation eects parallel source maturation eects (second factor).
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Consequently there is no analysis that could give reli-able evidence about place and time of generation. I have not found any convincing case histories that show only thermal degradation of reservoired oils. Evans et al. (1971) and Rogers et al. (1974) gave reasonable expla-nations for formation of pyrobitumens and methane from thermocracked oils in reservoirs; but they could provide no real evidence that the products had been formed entirely in the reservoirs. It seems more likely, that the oils would have been expelled from the reser-voirs by the generated HC gases if thermal catastrophes had occurred (crude oils not stable at any subsurface depth and is found in nature only because it is kineti-cally stable and is moving toward the thermo-dynamically stable products at a slow rate even on a geological time scale: Hunt, 1990; Barker and Takach, 1992). A considerable heating during burial diagenesis requires a long geologic time with intensive subsidence. The long heating time and fractures formed during tec-tonic events could oer opportunities for overpressured oils to leave reservoirs. This author cannot presently accept the severe thermal alteration of pooled petro-leums as a common phenomenon (as have been stated by Mango, 1990, 1991; Price, 1993; Helgeson et al., 1993; McNeil and BeMent, 1996).
In any case, the eects of a thermal alteration of the oils studied in this paper would be theoretically negli-gible because the oils' genesis is young (Pliocene to Quaternary). Furthermore the oils have migrated verti-cally upward and therefore their reservoir temperatures are less than their generation temperatures. Thus, in this study, the maturity of a given oil will be related to the maturity of its source rock at the time of oil release. Consequently, the generation temperature of a given oil can possibly be inferred from its maturity. (This assumes that the present reservoir temperature is so much lower than the source temperature at the time of release that no further in-reservoir maturation of the oil occurs.)
2. Geology of the Pannonian Basin
Two books were published about Pannonian Basin (Royden and HorvaÂth, 1988; Teleki et al., 1994) containing numerous studies, including tectonic, sedimentological, biostratigraphic, geothermal, maturation, petroleum geological and geochemical studies. On the basis of the above papers, I summarise some relevant statements on Pannonian Basin.
The Pannonian Basin in Central Europe is a back-arc basin superimposed on the Alpine compressional mega-structure, that resulted from continental collision between Europe and smaller continental fragments fol-lowing southward subduction of Thethyan ocean ¯oor. It represents one part of broad basin, which was formed by rising of the Alp, Carpathian and Dinaric mountains,
and by lowering of the terrain between their ranges. A set of discrete basins, whose development was pre-dominated by extensional listric and wrench faults, formed inside the Carpathian loop in Middle Miocene. The basins can be classi®ed as either peripheral basins that lie to and superimposed on thrust belts (Vienna basin, the Transcarpathian depression and the Transylvanian basin: are not considered part of the Pannonian basin).
The Pannonian Basin formed by extension (17±10 Ma) and subsidence (17±0 Ma). Prior to subsidence, the basement complex, formed from metamorphosed Pre-cambrian rocks, was considerable eroded. Several plate fragments juxtaposed by Cretaceous to Eocene tectonic events make up the pre-Tertiary basement complex of the region. The largest subbasin is the Great Hungarian Plain that lies east of Duna (Danube) river. The basin ®ll varies in age from early Neogene to Quaternary and locally can be as thick as 7000 m. Basement morphology is outlined by a system of troughs, which are divided by basement highs. Extensive geophysical surveys and numerous deep drillings have led to knowledge of the structural characteristics and sedimentation record of the basin. The Neogene sediments are almost exclusively shales and sandstones. The early Neogene sedimenta-tion resulted in mostly transgressive sequences, which deposited in deeper parts of the subbasins. In the troughs ®ne-grained marls and calcareous marls were accumulated with a relatively high organic content (Corg=1±2%). At this time the area was a part of Parathethys sea (maximum water depth: 800±1000 m). During the Sarmatian, the Pannonian basin was isolated from the sea, it became an isolated inland sea after-wards. The regressive sequences were accumulated in shallower water (200±400 m) as part of delta systems prograding from north and northwest towards the south. The Pliocene sediments were deposited in delta plain facies, their ¯uvio-lacustrine environment is demonstrated by the characteristic presence of brown coal and lignite seams.
The studied oils came from the area of the Great Hungarian Plain, the majority came from region of Algyo ®eld and BeÂkeÂs basin. The oils generated in the deeper units of the Great Hungarian Plain [Mako trough, BeÂkeÂs depression, NagykunsaÂg basin, Derecske basin and JaÂszsaÂg basin: look on Maps I, II and IV in Royden and HorvaÂth (1988)].
3. Approach
not heavy immature oils (e.g. Zumberge, 1987; Qin, 1988; Huang et al., 1990; Bazhenova and Are®ev, 1990) and they are not immature or mature condensates (e.g. Connan and Cassou, 1980; Snowdon and Powell, 1982; Thompson, 1987). The author considers the studied oils to have formed in the principal phase of oil generation during catagenesis. Most of the biological marker iso-merizations can take place prior to the onset or by the early stage of the oil genesis (SajgoÂ, 1984; Mackenzie et al., 1988; Sajgo et al., 1988); thus the use of isomeriza-tions is dubious in this case. The anomalies found by ten Haven et al. (1986) also suggest that the use of iso-merizations as maturation parameters should be avoided in oils if their source beds have not been identi®ed.
In this study, the maturities of the oils are estimated from the ratios of the lower molecular weight steroids (C18±C23) to the higher molecular (C26±C29) steroids. It
was assumed that biomarker maturity values directly re¯ect the maturity of the source rock at the time of petroleum expulsion. The application of tetracyclic aro-matic hydrocarbon distributions as maturity indicators began with Tissot et al. (1974), who studied extracts of Toarcian shales in the Paris Basin. Two humps were observed (C19±C21 and C27±C29 regions for CnH2n-12
steroid monoaromatics) with increase in favour of the C19±C21aromatics with increasing depth of burial. This
shift in carbon number distribution, later attributed to scisson of carbon±carbon bond in the side chain of C-ring monoaromatic steranes (Seifert and Moldowan, 1978; Mackenzie et al., 1981b). The usefulness of mul-tiring aromatic steroids as maturation tool was extended by Mackenzie (1980) and Mackenzie et al. (1981a). Two basic families were observed: a monoaromatic one and a triaromatic one (the structural types were inferred by mass spectral interpretation based on spectra observed for similar compounds, but are by no means proven), which both showed changes with increasing burial depth. Within each family a number of structural types, thought to be due to variation in the number of nuclear methyl substituents [the base peaks of monoaromatics there were types:m/z239: 1*CH3,m/z253: 2*CH3and m/z267: 3*CH3; and the base peaks for the triaromatics
were types: m/z217: 1*CH3,m/z231:2*CH3,m/z245:
3* CH3,m/z259: 4* CH3; ``x* CH3''),xdenotes number
methyl groups of ABCD-ring system); see Figs. 1, 2, 5, 6 and 8 in Mackenzie et al., (1981a)]. Their application as maturity parameters became apparent even prior to speci®c structural elucidation of the molecules involved. Later, most of the peaks inm/z253,m/z231 and some of them inm/z245 have been identi®ed (e.g. Hussler et al., 1981; Ludwig et al., 1981; Seifert et al., 1983; Riolo and Albrecht, 1985; Moldowan and Fago, 1986; Riolo et al., 1986). Mackenzie (1984) has reviewed the path of sterol diagenesis and catagenesis (Figs. 14, 15, 17 and 18) to various aromatic hydrocarbons. It seems to be obvious, to explain the enrichment of lower molecular
weight components within various aromatic steroid hydrocarbon homologous series in the case of:m/z239: 0*CH3(probably C-ring monoaromatic, that have lost a
nuclear methyl group and some rearranged to aromatic anthrasteroids; y* CH3, where y denotes the number
nuclear methyl groups of ABC-ring system), and m/z
267: 2*CH3 (probably C-ring monoaromatic, derived
from 2-, 3-, and 4-methylsterols and some rearranged as dia-ones inm/z253)m/z217: 0*CH3 (triaromatic
ster-oids, that have lost methyl group from C-17 position too),m/z245: 1* CH3(triaromatic steroids that have a
methyl group, which is rearranged from C-10 to either C-1, C-4 or other positions), m/z259 2* CH3
(triaro-matic steroids, that have two methyl groups probably derived from 2-, 3-, and 4-methylsterols one of them is rearranged from C-10 to either C-1, C-4 or other posi-tions), similarly to that in m/z 253: 0*CH3 m/z 231:
0*CH3 series (whose structures, have been elucidated).
Among the unproven structures the following have been used: m/z 239 (Seifert and Moldowan, 1978; Seifert and Moldowan, 1980); m/z 267 (Rubinstein et al., 1977, 1979; Mackenzie, 1980); m/z 245 (Mackenzie, 1980; Riolo et al., 1986) as source or maturation indicators.
Sajgo (1984), Wingert and Pomerantz (1986), Requejo (1994) and Requejo et al. (1997) found similar enrichment of short-chain steranes and diasteranes in oils and sedi-ments comparing to long-chain ones and the phenomenon was explained on the basis of extent of maturation.
Mackenzie et al. (1981a, 1983, 1988) and Sajgo et al. (1984) found that the relative abundance of short-chain biomarker homologs to the higher homologs increased as sediments moved through the oil window. Sajgo (1984), Hughes et al. (1985) and Riolo et al. (1986) demonstrated the same phenomenon for oils of dierent maturities. Amongst the possible explanations given for the increase of the ratio with maturation are as follows:
i. it re¯ects higher thermal stabilities of the lower molecular weight components (selective degrada-tion of the higher molecular weight components with increasing maturity);
ii. the short-chain homologs are the reaction pro-ducts of the higher homologs (as reactants) from direct carbon±carbon single bond cleavage in the side chain (long-chain compounds are more sus-ceptible to thermal cracking than short-chains giving rise to a relative increase of the short-chain components with maturity);
iii. the short-chain steroid species formed from the kerogen at higher temperatures are in higher relative abundance comparing to their lower relative abun-dance in products formed at lower temperatures; iv. a mixture of the above.
cleavage) of side chains of steranes and aromatic ster-oids. Earlier, Rubinstein et al. (1979) Seifert and Mol-dowan (1980, in Mackenzie et al., 1981b) could not observed aromatic steroidal hydrocarbons under open conditions of pyrolysis. Later, Rowland et al. (1986) found only Diels' hydrocarbon (C18triaromatic steroid
ofm/z217) in hydrous pyrolysis experiments, and they suggested a product±precursor relationship between the C26ÿ28aromatics Diels' hydrocarbon. Beach et al. (1989)
found no side-chain cracking, but only a faster rate of degradation for the long-chain homolog. Peters et al. (1990) observed increasing ratios of short-chain to long-chain aromatics (form/z253 and m/z231) in hydrous pyrolysis experiments with increasing temperatures, emphasising that ratio increases due to preferential degradation of long-chain homologs rather than con-version of long- to short-chain homologs. Amongst other reactions, the carbon±carbon bond cleavage in side-chains as well as the ring system during the thermal degradation of 5a (H)-cholestane under closed-system pyrolysis were observed by Abbott et al. (1995). Up to now, the simulation experiments could not elucidate how the aforementioned maturity indicators work.
In spite of these this con¯icting results, author accepts the concept of real or apparent side-chain cracking on the basis of the fragmentograms of the eight homo-logous series studied. The less mature oils display sim-pler homolog distributions than the mature and very mature oils [Figs. l and 2 and see also in Figs. 3.8 and 6.10 of Mackenzie (1980); Mackenzie et al. (1983), in Fig. 14 of Hughes et al. (1985), in Figs. 8, 10 and 11 of Riolo et al. (1986) and in Fig. 3 of Wingert and Pomer-antz (1986)].The increasing complexity of homologues as a function of maturity obviously appears to be the result of side-chain cracking. At lower levels of matur-ity, the bond cleavage theory are dominated (second and primary radicals formed), but the preferential forma-tions dominance is disturbed by other reacforma-tions at higher levels of maturity. Therefore, I have introduced homologous maturation parameters. Theoretically, their reliability should be greater than that of the molecular parameters, which show the same trends as the homo-logous parameters, but change only moderately. Per-haps the molecular parameters re¯ect primarily/mainly the higher thermal stability of the short-chain homo-logs, and only to a lesser degree the side-chain cracking of the long-chain homologs. Otherwise, it is dicult to explain the preferential cracking of a given reactant to another given product without considerable by-products under severe enough thermal conditions.
4. Methods
After precipitation of asphaltenes with light petro-leum ether (30±50C), the remaining was separated
chromatographically on a column of silicagel. Successive elution with light petroleum, benzene and benzene± methanol (1:1, v/v) aorded saturated hydrocarbon (Sat), aromatic hydrocarbon (Aro) and resin fractions, respec-tively. The Sat fractions were analysed by gas chromato-graphy (GC) and computerised gas chromatochromato-graphy±mass spectrometry (GC±MS). The Aro fractions were further separated by thin layer chromatography, mono-triaromatic fractions were analysed by GC±MS. All samples were analysed using multiple ion detection. The appropriate molecular components were identi®ed using prior knowledge of the basic distributions and molecular ion fragmentograms. The further details are described else-where (SajgoÂ, 1980, 1984; Mackenzie et al., 1981a,b; Sajgo et al., 1983, 1988).
The maturation ranking was based on quanti®cation of nine biomarker families in GC±MS runs. In the case of dierent key±ion ratios the relative quantities of molecular components and homologs in two modes (each peak separately and/or humps/ranges conjointly) were measured and calculated within the same mass fragmentogram.
4.1. Molecular ratios
The following molecular ratios were calculated as maturation parameters:
1. C20/C20+C28: triaromatic steroid HCs fromm/z
231, (e.g. Mackenzie et al., 1981a,b)
2. C23/C30=tricyclic diterpane/hopane fromm/z191,
(e.g. Seifert and Moldowan, 1978; SajgoÂ, 1984; Philp et al., 1991)
3. C21/C29=5a(H)-pregnane/20R-24ethyl-aaa
-choles-tane from m/z217 (e.g. Wingert and Pomerantz, 1986; Huang et al., 1994; Requejo, 1994; Requejo et al., 1997)
4. [C21+C22]/[C21+C22+C28+C29]: triaromatic
ster-oid HCs fromm/z245 (SajgoÂ, 1984)
5. [C21+C22]/[C21+C22+C28+C29]: monoaromatic
steroid HCs from m/z253 (e.g. Mackenzie et al. 1981a,b; SajgoÂ, 1984)
6. Ts/Tm=18a(H)-trisnorneohopane/17a (H)-trisno-rhopane fromm/z191 (e.g. Seifert and Moldowan, 1978; SajgoÂ, 1984; Peters and Moldowan, 1993).
The sixth molecular parameter: Ts/Tmwas suggested
by Seifert and Moldowan (1978) for oil maturity assessment. The reason that the ratio increases with maturity is not clear.
4.2. Homologous ratios
of triaromatic steroid hydrocarbons and (base peaks:m/z
217, 231, 245, 259). The lighter hydrocarbons (C18±C24; C19±C25; C20±C26; C17±C23; C18±C24; C19±C25 and C20±C26, respectively) are believed to be the products of the heavier homologs. The heavier HCs (C26±C28;C27±C29;C28±C30;C25±C27;C26±C28; C27±C29; andC28±C30, respectively) are believed to be reactants from which the majority of lower homologs in the samples of advanced maturity were produced. Under severe thermal conditions, some of the reactants probably produce other cracking products as a result of bond breaking in the ring systems (e.g. Abbott et al., 1995).
The oils were ranked according to each used maturity parameter and on the basis of rank orders obtained the oils formed ®ve groups of maturity. These groups have been named as a function of maturity as follows: least mature (Ltm), low maturity (Lm), moderate maturity (Mm), mature (M) and very mature oils (Vm).
5. Results and discussion
Sajgo (1984) described 23 crude oils (their location showed) from this area of SE Hungary. The 23 oils of that study are also part of the present study. Geological conditions and other details of the 23 oils are described in Sajgo (1984). Clayton et al. (1994) BeÂkeÂs basin oils: I supplied 17 of those (seven of them were a part of the above 23) and Koncz and Etler (1994) also studied oils from this area using biological marker data of mine in their paper: 17 oils of their study are involved in this paper (12 of them were also a part of the above 23).
Figs. l and 2 display the ®ve maturity groups in four fragmentograms. The four fragmentogram series (m/z
217saturates, 253, 231 and 245) best illustrate the ®ve
maturity groups in Figs. 1 and 2, the other fragmento-grams (m/z191, 217aromatic, 239, 259 and 267) showed
less smooth changes with maturity.
5.1. Independence of maturation parameters applied from source control
Reservoir data and oil genetic and maturity groupings are summarised in Table 1. Reservoir ages vary from Pliocene (Upper Pannonian) to Precambrian. Most of the oils of this study originate from the south-western margin of MakoÂ-HoÂdmezoÂÂvaÂsaÂrhely trench (nos. 1±18, 6±33 and 52±53) and BeÂkeÂs Basin (nos. 18±25, 33±44 and 49±51), two originate (nos. 45±46) from somewhat North of the above areas (30±50 km) and the two Oligo-cene oils (nos. 47±48) originate from about 100 km North of the above areas. Oil±oil correlation methods are described in Sajgo (1984); again and as in that study, the same three oil types (genetic groups) were found in this study. The latter genetic classi®cations of 90 oils by
Clayton et al. (1994) and Koncz and Etler (1994) are consistent with the interpretation of at least three genetic oil types. Reservoir temperatures range from 37 to 208C, and many of them are unusually high. The
API gravities (26±50) also indicate that oils were
expelled over a range of thermal maturities. In some cases, relatively high-density oils (30±35API) occur at
temperatures in excess of 100±150C.
It is important to check independence of the maturity groupings from source in¯uence. In Figs. 3 and 4, dia-grams of the three crucial sorting parameters are dis-played. It is obvious from Figs. 3 and 4 that the genetic group I is homogeneous and all the maturity classes are represented by this group. Genetic group II shows a considerable dispersion of pristane/phytane and C30
-(hop.+mor.)/C29-steranes ratios (Fig. 4) and group II is
homogeneous only according to the oleanane/hopane ratio (Fig. 3). The members of the maturity groups are scattered more or less independently of the sorting parameters. The small number of oils in the third group prevents interpretation of their scatter. Thus, the inde-pendence of maturity ranking from source factors is proven for the oil families of this study.
In Fig. 4, a moderate relationship between pristane/ phytane and C30(hop.+mor.)/C29-steranes exists. There
are at least two possible explanations:
i. both ratios are governed by redox processes in the same way;
ii the numerators represent bacterial input and the denominators re¯ect the contribution of ¯ora.
This relationship is worthy of further study because it may lead to a better understanding of the facies in¯u-ence on oil-source characteristics.
5.2. Dependence on bulk composition
Fig. 1. Mass fragmentograms of steranes (m/z217) in saturated fractions of oils and of ring-C monoaromatic steroid hydrocarbons (m/z253) in aromatic fractions of oils showing the distributions of short-chain homologs and long-chain homologs as a function of the established maturity ranking: least-mature (LtM), low-mature (LM), moderate-mature (MM), mature (M) and very-mature oils (VM). Some carbon numbers designated in fragmentograms of oils (oil nos. 1, 4, 6, 9 and 18 shown in Table 1 form/z217 and oil nos. 1, 4, 6, a mixture of 11, 12 and 13 oils and 17 shown in Table 1 form/z253). Notice the relative enrichment of short-chain homologs relative to long-chain homologs with maturity. It is not proved whether the enrichment is the result of: (i) conversion of long-chain homologs to short-chain ones (thermal bond cleavage in the C8±C10side-chain of the higher molecular weight components); (ii) selective thermal
Fig. 2. Mass fragmentograms ofm/z231 and 245 for the ABC-ring triaromatic steroid hydrocarbons of in aromatic fractions of oils as a function of the established maturity ranking: least-mature (LtM), low-mature (LM), moderate-mature (MM), mature (M) and very-mature oils (VM). Some carbon numbers designated in fragmentograms of oils (oil nos. 1, 4, 6, 9 and 17 shown in Table 1 form/z
231 and oil nos. 1, 4, 5, 9 and 18 shown in Table 1 form/z245). The ratio of short-chain triaromatics to their long-chain homologs increased with increased extent of catagenesis as a maturation parameter both in case of demethylated (m/z231) and methylated (m/z
Table 1
Reservoir data and groupings of the oils studieda
Nos. Well Reservoir depth
(m)
Reservoir age
Reservoir temperature (C)
Oil type
Maturity level
API gravity ()
1. AlgyoÂÂ-119 2431±2434 L. Pannonian 122.5 I LtM 30
2. AlgyoÂÂ-261 2350±2360 L. Pannonian 122.5 I LtM 36
3. AlgyoÂÂ-245 1948±1961 U. Pannonian 94 I MM 37
4. AlgyoÂÂ-230 1950±1953.5 U. Pannonian 94 I LM 39
5. AlgyoÂÂ-298 1922±1927 U. Pannonian 92.5 I MM 44
6. AlgyoÂÂ-476 1886±1890 U. Pannonian 90.5 I MM 43
7. AlgyoÂÂ-290 1886±1890 U. Pannonian 90.5 I M 44
8. AlgyoÂÂ-380 1868.5±1871.5 U. Pannonian 88.5 I M 46
9. AlgyoÂÂ-426 1823.5±1828 U. Pannonian 83.5 I M 40
10. AlgyoÂÂ-495 1775±1777 U. Pannonian 85.5 I M 46
11. Szeged-6 2675±2679 Precam.-Mes.-Mioc. 144 I M 43
12. Szeged-26 2740±2748 Precam.-Mes.-Mioc.- 144 I M 42
13. Szeged-28 2608±2622 Precam.-Mes.-Mioc.- 144 I M 43
14. Dorozsma-6 1614.5±1618.5 U. Pannonian 96 I MM 35
15. Dorozsma-7 2821±2829 Paleozoic 147 I M 39
16. OÈttoÈmoÈs-22 990±992 U. Pannonian 58 I LtM 27
17. FerencszaÂllaÂs-61 2418±2420 Precam.-L. Panno. 125 I VM 44
18. Kiszombor-16 2252±2263 Precambrian 126 I VM 40
19. PusztafoÈldvaÂr-177 1703±1706 L. Pannonian 122 I LM 29
20. PusztaszoÂÂloÂÂs-29 1740±1741.5 Triassic 115 I LM 30
21. SarkadkeresztuÂr-16 2852±2865 U. Pannonian 136 I VM 51
22. Szeghalom-3 2101±2105 Miocene 130 I M 43
23. Szeghalom-13 2089±2093 Miocene 130.6 I MM 40
24. PuÈspoÈkladaÂny-3 1733±1744 Miocene 124 I M 42
25. NaÂdudvar-19 1528±1531 L. Pannonian 85 I LtM 26
26. Kelebia-20 851±860 Paleozoic 59 II LM 31
27. AÂsotthalom-15 1060±1062 Miocene 83 II LM 32
28. AÂsotthalom-27 1051±1061 Paleozoic 83 II LM 32
29. UÈlleÂs-26 2127±2140 Miocene 130 II M 45
30. UÈlleÂs-31 2770±2787 Triassic 159 II MM 35
31. Ruzsa-2 2301±2309 L. Pannonian 127 II VM 39
32. ForraÂskuÂt-5 3329.5±3337.5 Triassic 160 II M 29
33. MakoÂ-1 4142±4156 L. Pannonian 147 II VM 43
34. PusztafoÈldvaÂr-114 1776±1777 L. Pannonian 125 II LtM 27
35. CsanaÂdapaÂca-3 1911±1930 L. Pannonian 130.6 II LM 35
36. Kaszaper-D-8 1628.5±1631 L. Pannonian 103.8 II LM 30
37. Battonya-70 1028.5±1030 L. Pannonian 74 II LM 46
38. Battonya-K-63 1035.6±1041 L. Pannonian 66 II LM 45
39. KomaÂdi-3 2527±2535 Miocene 148 II LM 38
40. KomaÂdi-6 2204±2212 Miocene 136 II MM 39
41. KomaÂdi-10 21342140 L. Pannonian 126 II M 44
42. MezoÂÂsas±3 2568±2575 Precambrian 142 II M 40
43. FuÂÂzesgyarmat-3 1796±1800 Miocene 116.8 II M 46
44. EndroÂÂd-5 2595±2603 Miocene 143 II M 29
45. Kismarja-21 1011±1020 Paleozoic 70 II LtM 25
46. Szolnok-1 1816±1821 L. Pannonian 95 II LM 33
47. DemjeÂnK-3 206±268 Oligocene 37 II LtM 30
48. MezuÂÂkeresztes-25 1415±1429 Oligocene 80/?/ II MM 42
49. Biharugra-3 2295±2303 Mesozoic 124 Mix.I.±II. LtM 44
50. MezuÂÂhegyes-14 1188. 5±1190 L. Pannonian 89 III LM 35
51. ToÂtkomloÂs-26 1898.6±1899.5 Mesozoic 138 III M 38
52. UjszentivaÂn-1 3348±3767 L. Pannonian 157 III M 39
53. MakoÂ-2 4807±4815 Miocene 208 III VM 50
a L., lower; U., upper; Precam.-Mes.-Mioc, Precambrian±Mesozoic-Miocene; Precam.-L. Panno., Precambrian-L. Pannonian;
5.3. Correlation with commonly used maturity indicators
A dozen indices used or suggested as maturation parameters (e.g. Mackenzie, 1984; Peters and Moldowan,
1993), were chosen to compare with the homologous-ratio maturity ranking established in this study. This serves to check the new maturity indices of this study. In Fig. 6, four traditionally-used parameters are shown. (In
Fig. 3. Plot of oleanane/hopane ratios against C30hop.+mor./C29-steranes ratios (C30hop.+mor.= hopane+moretane; C29
-ster-anes=(20R+20S)-5a(H),14b(H),17b(H)- and (20R+20S)-5a(H),14a(H),17a(H)-24-ethylcholestane). Both the source and maturity groups are indicated in the ®gure (for source/genetic groups see text and Table 1; least-mature=Ltm, low-mature=Lm, moderate-mature=Mm, mature (M) and very-mature oils=Vm).
Fig. 4. Plot of the pristane/phytane ratios against C30hop.+mor./C29-steranes values (C30hop.+mor.= hopane+moretane; C29
Figs. 6±8, the mean values, the probable range of occurrence, and the extreme values of the traditionally-employed ratios are exhibited.) The average of CH (the sum of Sat and Aro fractions in the% of oils, also shown in Fig. 5) shows a gradual increase with maturity, nevertheless the ranges are much wider among the less mature oils, than in the more mature ones, and the values for less mature petroleums overlap the values for more mature oils.
The two isoprenoid/n-alkane ratios (pr/nC17and ph/ nC18) run largely parallel each other, except in the low
mature oils. The change of these ratios indicates thatn -alkanes are more stable to thermal degradation than isoprenoid hydrocarbons. The greatest change in the values is between the mature and very mature oils.
The pristane/phytane (pr/ph) ratio is not a maturity indicator, as is seen in the case of the least, low, and moderately mature oils, but the ratio increases from the moderately mature oils to the very mature oils. This means that the pr/ph ratio is sensitive to maturation only to under rather severe thermal conditions. Of course, this observation should be tested in other groups of oils.
Four sterane maturity parameters are shown in Fig. 7, however, really, there are only three parameters in the
®gure two of them C2920S20S20R 217and C2920S20S20R 218
(fromm/z217 and 218 fragmentograms) represent the same con®gurational isomerization at C-20 in the 5a(H), 14a (H), 17a (H) C29-sterane Sajgo and Le¯er (1986) and Sajgo et al. (1988) found that the m/z 218 fragmentograms provided less dispersion in samples of the same area than the m/z 217 fragmentograms and thereforem/z218 is preferred tom/z217. Some coelution occurs likely in the case of them/z217 fragmentograms of the studied samples from the same part of the Pan-nonian basin. The two curves run more or less parallel and they suggest that complete epimerization has not occurred in the least and low mature crude oils. The change of them/z218 fragmentograms is not signi®cant between the moderately and very mature oils. However, in the case ofm/z217 fragmentograms, the completion went on markedly. In the study of rocks of the HoÂd-I borehole (Sajgo et al., 1984, 1988; Sajgo and Le¯er, 1986), complete epimerization was observed before the onset of petroleum formation.
time of primary migration, and that further conversion may occur only occasionally in high-temperature reservoirs. Sterane epimerization in source rocks can probably attain equilibrium later, driven by increasing tempera-ture from further subsidence (this is the case in the Pannonian basin), or possibly by a long geologic time at the same temperature (accepted by many scientists). It is important to emphasise that the levels of maturation in the source rocks and in the expelled petroleums will not necessarily be the same, and it is likely that the extent of maturation in source rocks usually exceeds that in expelled petroleums. Consequently a reasonable dier-ence in maturity between source-rock bitumens and expelled oils is not a negative factor in correlation work. The percentage of C27-diasteranes (C27rear%) relative
to the C27-steranes exhibits a similar change as the above isomerization, although for dierent reasons. According to present thought, the backbone rearrange-ment of the steroid system takes place during diagenesis under mild thermal conditions (Seifert and Moldowan, 1978; Sieskind et al., 1979; Requejo et al., 1997; van Kaam-Peters et al., 1998). Diasteranes, the products of this rearrangement, have higher thermal stability than
the steranes, therefore their relative concentration increases with maturity.
The relative amounts of the C29-14a(H), 17a (H)-steranes to their 14b(H), 17b(H)-counterparts (C29)
also show a gradual rise as a function of maturity. The relative proportion of aa-con®guration is one of the most commonly-used maturity parameters, although its application is sometimes problematic (Mackenzie, 1984; Peters and Moldowan, 1993; van Kaam-Peters et al., 1998).
The four graphs (indices) in Fig. 7 exhibit parallel trends. The ratios rise rapidly between the stages of the least and the moderately-mature oils, and then increase only slightly.
Some hopanoid maturity indicators are displayed in Fig. 8. Three ratios (C3122S22S22R, C3222S22S22R and C3322S22S22R)
represent the same phenomenon, that is the con®gura-tional isomerization at C-22 in 17b(H), 21a(H)-hopanes. The C32 and C33 hopanes show a minimal increase
mature oils to very mature oils. (In the case of the C31 hopane some coelution of gammacerane with the 22R
isomer was observed). At present, this author has no explanation for these observations. The extent of changes is not characteristic, consequently the application of these parameters is not appropriate in this study.
The moretane/hopane ratio (mor/hop) represents a con®gurational isomerization at C-17 and C-21 in the C30 hopanes (Seifert and Moldowan, 1980). The ratio
shows a minimal decrease with increasing maturity (Fig. 8).
Among hopanoid parameters, the norhopane/hopane ratio (norhop/hop) exhibits the most obvious change, rising markedly as a function of increasing maturity. This rise can be explained either because the C29hopane
is more resistant to maturation as compared to C30
hopane and/or the methyl group cleavage of the C30
hopane produces the C29hopane during maturation.
During the cross-checking of the established maturity classi®cation, several novel homologous maturity para-meters which applied to the zone of petroleum forma-tion provided further support for the method of this study, consequently the method is well-founded for the ascertainment of the generation temperatures of crude oils in this study.
5.4. Independence on migration
The eects of migration were also checked. Shi Ji-yang et al. (1982), Homann et al. (1984) and Sajgo (1984) found that oils had much lower steroid aromati-zation ratios (triaromatic/mono-+triaromatic steroids; see, e.g. Mackenzie, 1984) than would be expected on the basis of their depth, and according to other maturity parameters. The phenomenon was explained as an eect of migration, i.e. the relative enrichment of monoaro-matic steroid HCs was caused by the easier migration of monoaromatic steroids relative to triaromatics, as their polarity is less than that of triaromatics [Carlson and Chamberlain (1986) have proven applying adsorption free energy dierences on clay mineral surface in liquid± solid chromatography]. The crude oils of this study were divided into six migration groups (on the basis of their apparent aromatization ratios), in which there was no evident correlation between the maturity and migration grouping. The members of each maturity group were almost all present in each migration group, and no reg-ularities of migration were observed in the distributions [Carslson and Chamberlain (1986) have not found migrational fractionation between the short-chain and long-chain members within a homolog series: e.g. form/z
253 monoaromatic and m/z 231 triaromatic steroids applying adsorption free energy dierences on clay mineral surface in liquid±solid chromatography).
5.5. Generation temperatures of crude oils
The reservoir temperatures of some the petroleums of this study are signi®cantly higher than both the tem-peratures traditionally thought necessary for main-stage HC generation and the temperatures at which crude oils are thought to be thermally-stable (so-called oil-dead-line is generally placed at temperatures of 150±175C,
where oils are destroyed, thermal cracking is gone to completion; e.g. Hunt, 1979). The reservoir temperatures of this study demonstrate that petroleum are thermally more stable than previously generally assumed, the top reservoir temperature in this study even exceeding 200C. Moreover, the generation temperatures for these
oils were higher, and perhaps even substantially higher, than the reservoir temperatures of the oils. Thus the data of this study clearly demonstrate that an unsolved problem remains concerning the generation tempera-tures for oils. There are several controversial opinions on this topic in the literature. The majority of petroleum geoscientists believes in a kinetic description for
oil-generation reactions, i.e. both temperature and time are important in petroleum formation and interchangeable to a certain extent. Thus, oil formed at lower tempera-tures in the Silurian and Devonian rocks of the eastern Sahara (50C) as compared to the Miocene rocks of the
Los Angeles basin (115C), because longer times were
available for heating the source rocks in the eastern Sahara (Tissot et al., 1975). This concept was propa-gated in popular simple versions by Karweil (1955), Lopatin (1971), Connan (1974) and Waples (1980), and it has become a routinely-used method among geos-cientists. However, other investigators pointed out sig-ni®cant problems with this method (e.g. Snowdon, 1979; Koncz, 1983). Nonetheless, classic textbooks on petro-leum formation state that the temperature range of oil genesis is between 50 and 120/150C (e.g. Perrodon,
1983, p. 71; Hunt, 1979; Tissot and Welte, 1984). Tissot and his co-workers worked out a more exact and sophisticated kinetic method, which was based on both geological reconstructions and laboratory studies (Tissot, 1969; Tissot and Pelet, 1971; Tissot and Espita-lieÂ, 1975). They used a series of activation energies between 10 and 80 Kcal molÿ1, and appropriate
the three main types of kerogen (I, II and III). Their model may be valid under laboratory conditions, but the application of kinetic parameters obtained in the laboratory at high temperatures and short times to geo-logical situations is untenable (e.g. Snowdon, 1979; Price, 1983; Barker, 1988; Domine and Enguehard, 1992; Price and Wenger, 1992; Price, 1993; Domine et al., 1998). These models generally use at least 10 orders of magnitude in extrapolation for time and about a 300C dierence for temperature. The estimation of
geologic temperatures and burial history is still some-what obscure. In many cases, present-day temperatures were used, or temperatures from basin evolution models produced by sophisticated computer models, which conveyed only a false sense of accuracy. Additionally, some of these models were based on hypotheses some-times not divorced from speculation. Finally, such hypothetical models would be ``proved'' through a ®t-ting process, which used a deceptive interpolation of kinetic parameters obtained in the laboratory at high temperatures and short times to an uncertain thermal and burial history.
This author considers that the apparent low tem-peratures of oil generation in old inactive basins only re¯ect basin cooling during the mature and ®nal stages of sedimentary basin histories (Perrodon, 1983, p.34; Price, 1983), instead of re¯ecting the eect of long burial times. This opinion is also a hypothesis; however, its probability is at least as solid as the trading of tem-perature for time in geological case histories.
A minority of geoscientists has introduced the idea of eective heating time. Hood et al. (1975) de®ned the eective-heating time of a rock as that period spent within 15C of the rock's maximum palaeotemperature.
Gretener and Curtis (1982) modi®ed this idea. They stated that time was not a signi®cant factor at tempera-tures below 50±70C and higher than 130C. In the latter
case, they believed that source rocks would pass entirely through the oil window in little more than 10 Ma at 140C. They also calculated that time would operate
eectively between 70 and 100C in Paleozoic source
rocks and between 100 and 130C in Mesozoic source
rocks. The method of Hood et al. (1975) and its improved version (in Bostick et al., 1978), are widely used and give reasonably good correspondences with measured data (VetoÂÂ, 1980; Waples, 1984; Sajgo et al., 1988).
Another minority of geoscientists regards the eect of time after a certain period to be negligible in coali-®cation and oil genesis (Barker, 1983, 1988; Price, 1983, 1993; Neruchev and Parparova, 1972; Ammosov et al., 1977; SajgoÂ, 1980; Suggate, 1982). Price (1983, 1985) stated that petroleum formation-maturation reactions were not ®rst-order, as had been presumed earlier, but instead were higher-ordered. Recently, Domine et al. (1998) corroborated this observation. If
this is the case, the application of the Arrhenius equa-tion would be invalid and would produce deceptive interpretations.
Sajgo and Le¯er (1986) pointed out that many pro-blems in oil generation models originate from uncertain ®eld data, untestable tectonic models, and transient thermal anomalies.
5.6. Implication of maturity ranking for oil generative temperatures
The reservoir temperatures of the dierent maturity groups of the oils of this study were tabulated and a gradual rise of the highest reservoir temperatures was observed (Table 2). The range of reservoir temperatures also showed a marked increase. This observation sug-gested that at the least, the hottest oils of the groups migrated only limited extents from their source rocks, and the coldest oils migrated greater vertical extents. The temperature ranges of the reservoirs (i. e. the depths of reservoirs) represent the probability of vertical occurrence of traps in the area of this study. A short vertical migration was conservatively assumed in the case of each maturity group, hence the given distances of this migration for each oil group re¯ect only the additional temperature member to the highest reservoir temperatures in the assumed minimum temperatures of generation. The generation temperatures in Table 2 are minimum temperatures and are only approximate, but their reliability probably is no worse than that of the kinetic methods. Table 2 contains vitrinite re¯ectance data from the same area (SajgoÂ, 1980; Sajgo et al., 1988), and from Ammosov et al. (1977). Ammosov and his co-workers gave a table of vitrinite re¯ectances and minimum burial paleotemperatures needed to attain to the given re¯ectance. The agreement with measuredRo
values is very good except for very mature oils. The range of the ascertained minimum temperatures of generation (130±215C) for the oils of this study is in
good accordance with thresholds of intense petroleum genesis in HoÂd-I found by Sajgo (1980). Sajgo found that the principal phase of oil genesis started at 142C in
HoÂd-I, with a second zone of generation which started at 218C and continued at 233C (bottomhole).
These high thresholds for generation temperatures contradict the established concepts discussed above, but concurrently several published and unpublished results support the higher temperatures.
Philippi (1965, 1975) found that the generation of petroleum took place at about 150C in Ventura and
Los Angeles basins. In the case of light HCs from the California basins, he found the maximum similarities between extracts and ``normal'' oils occurred at about 160C. Hood and Castano (1974) stated that the principal
in San Joaquin basin. Sajgo (1980) discussed some other examples from the literature (Connan, 1974; LaPlante, 1974; Dow, 1978; Gamintchi, 1979; TeichmuÈller, 1979).
Price (1982, 1983, 1993) summarised the observations that he and his co-workers found in many deep US bore-holes, and stated that time was irrelevant after one million years in petroleum generation-maturation reactions. He also claimed they could not detect the threshold of intense generation of oil even at minimum temperatures of 160C. It is important to emphasise that Price's
con-clusions are based on studies of rocks that had burial times, in the main, of 40±250 Ma.
Saxby (1982) pointed out that HC generation required hotter conditions (>120C) than that
pro-posed in most previous schemes (60±110C), based on
coali®cation studies and geochemical considerations in Australian oil basins. He set the onset of oil formation at 1.0% Roand proposed the end of oil generation at
2.0%Ro. Recently, Grice et al. (2000) have estimatedRo
between 1.1 and 1.6% for the oils of Gippsland and Carnarvon Basins on the basis of diamondoid hydro-carbon ratios.
Thompson (1983) studied light HCs of 76 petroleums from dierent parts of the USA. The oils were classi®ed as normal, mature, supermature and biodegraded. He gave a range of 138±149C as generation temperatures
for mature for normal oils (42% of his sample base). For supermature oils, Thompson suggested temperatures greater than 190C for HC generation, with certain
reservations. The least and low mature oils of this study probably are equivalent to the normal class of Thomp-son's (1983) oils. The moderate-mature and mature oils of this study may correspond to his mature oils, and the very mature oils may be the equivalent of his supermature oils. Thompson's (1983) generation temperatures support the temperatures in this study. Koncz and Etler (1994) studied the Thompson' values of 20 oils from this area (nine oils of this study were involved). They found, that four or seven oils were mature and 16 or 13 oils were
supermature (on the basis of heptane or isoheptane values, respectively). Their results suggest certain reser-vations of comparing the maturity groups, but the con-siderable level of maturity of the oils in the studied area have been corroborated.
Petrov (1984, p. 88) employed the concentration ratios of epimeric 1,2-dimethyl cyclopentanes to estimate oil generation temperatures, assuming thermodynamic equilibrium, and obtained a range of 130±300C , with
an average of 160C.
Cooles et al. (1986) stated that major oil generation from kerogen occurred between 120 and 150C in the
subsurface in the case of oil-prone source rocks. They stated that gas-prone (refractory) kerogens generated oil from 180C up to about 250C. A mixture of oil- and
gas-prone kerogens generated petroleum between 120 and 220C. They studied 10 source rocks and
dis-tinguished only two types of kerogen: (1) labile (oil-prone) and (2) refractory (gas-(oil-prone). I believe that the nature of both labile and refractory kerogens is more complex, and that further subdivisions are necessary, which would result in a re®ned interpretation of observed oil generation temperatures. In a later study, Quigley and Mackenzie (1988) stated that the in¯uence of time was not great in subsurface petroleum formation and that most oils were formed between 100 and 150C,
and most gases between 150 and 220C. They derived
equations from their work.
Chen et al. (1996) found new maturity indices for highly mature oils. Based on diamondoid hydrocarbon ratios, they stated that crude oils of the Tarim Basin are generally very mature (Ro> 1.1%) and condensates
from Tarim and some other basins have maturities equivalent toRovalues of 1.6±2.0%. However, Li et al.
(1999) gave much lower maturity values for oils from some areas of the Tarim Basin on the basis of methyl-phenathrene indices and the ``Mango parameter'' (Roof
0.73±0.93 and of 0.62±0.92%, respectively), but they did not mention the above dierent results. Xiao et al. Table 2
The most important properties of the ranked crude oils, which were considered during the ascertainment of generation temperatures
Maturity groups of oils Least-mature
oils
Reservoir temperature range (C) 37±125 59±148 80±159 83.5±160 125±208
Highest reservoir temperature (C) 125 148 159 160 208
Reservoir depth range (m) 260±2430 860±2530 1420±2780 1770±3330 2660±4810
Probable minimum temperature range of generation (C)
130±135 150±155 165±170 180±190 210±215
Assumed minimum vertical migration (m) 100±200 40±140 120±220 400±600 40±140
MeasuredRoat the given temperature range
in HoÂd-I (%)
0.63±0.66 0.77±0.83 0.90±0.93 1.07±1.17 1.67±1.75
AssumedRovalues by Ammosov at the given
temperature range (%)
(1996) found three phases of oil generation and migra-tion corresponding to organic inclusion groups with homogenisation temperatures of 200±240, of 160±200 and of 80±130C in the Tazhong petroleum system of
the Tarim Basin, which may be a possible explanation for the above contradiction.
Kissin (1998) studied aromatic compounds in the middle of catagenesis and from this work, estimated the thermodynamic equilibrium in most crude oils at between 200 and 300C, based on the distribution of
these types of aromatic compounds for a given carbon atom number.
The above studies give a range of petroleum forma-tion between 100 and 300C. The majority stated that
the genesis of oils occurred partly or entirely above 150C. Even this incomplete list reveals that the kinetic
models suggesting that oil genesis takes place between 50 and 150C (Connan, 1974; Tissot and EspitalieÂ, 1975;
Waples, 1980; Quigley and Mackenzie, 1988; Braun and Burnham, 1992; Ungerer, 1993), are unrealistic.
I suggest that their low temperature estimates stem from the overestimation of the role of time and from the neglect of the role of pressure. The overestimation of time originates from the use of present-day tempera-tures to represent the complete temperature history of a petroleum basin. From the 1950s to the end of the 1970s, geochemists had little knowledge of basin for-mation and thermal history. Therefore, they used pre-sent-day burial temperatures in their kinetic models. Karweil (1955) was the ®rst to take this path and, in a later publication, Karweil (1975) wrote ``Karweil and Lopatin have used seams of the Ruhr district as a base of their calculations. The temperature gradient in these seams during the subsidence period is not known. It is possible that it was lower or higher than at present''. Price (1983) studied Karweil's (1955) paper rigorously and found several other inconsistencies, which have been ignored by proponents of kinetic modelling. Today, it is well-known that basins are the hottest during their juvenile stage, then they cool during their mature stage, and do not change during the ®nal stage (Perrodon, 1983).
Unfortunately, the widespread, and I believe erro-neous, idea of temperature-traded-for-time is still favoured by most petroleum geoscientists in spite of the now widespread recognition of temperature changes during basin evolution. Such researchers apparently also do not realise that the idea is based on doubling the reaction rates for a 10C increase in temperature
(Lopatin, 1971; Connan, 1974) and was originally established for ¯uids within about a temperature range of 100C. Proponents and users of kinetic modelling
also assume stable heat-¯ow models (Tissot and Espita-lieÂ, 1975) , which are untenable in the light of modern basin evolution models. Waples (1984, p. 50) admitted: ``In general, temperature data are by far the weakest
part of any time-temperature model.'' (This statement implies that one of the two foundation-stones of kinetic modelling is weak or only moderately reliable.)
Another important problem has arisen from the ignorance of the role of pressure in oil genesis. With the exception of Sweeney et al. (1986) and Carr (1999), most kinetic models neglect it, although Sweeney et al. (1986) stated that they would study the eect of the variation of pressure because it was then incorporable to their model. Neglecting pressure is unacceptable on the basis of Le Chatelier's principle. During oil genesis kerogen breakdown builds up an increasing internal pressure from volatile products because the volume of the products from the reaction is larger than that of the reactants if none of the products escape in closed or quasi-closed systems. This inhibits further thermal decomposition of kerogen. Very few studies have been done to elucidate the role of pressure; most of them failed to give de®ni-tive answers or they were neglected for a while (e.g. Cecil et al., 1977; Goe and Willey, 1984). Sajgo et al. (1986) found a dierence in eect of static (load) and volatile (product or ¯uid) pressures in the temperature range of 200±450C. They found that high load pressures
(1.0 and 2.5 Kbar), in quasi-closed systems (which is the case in Nature) retarded the coali®cation of lignite, hydrocarbon formation, and the maturation reactions of biomarkers to considerable extents. These processes were accelerated in a quasi-closed system under 0.06 Kbar ¯uid pressure, relative to the open system of the same static pressure. Later, Price and Wenger (1992) documented that increasing ¯uid pressures retarded all aspects of HC generation and maturation in aqueous-pyrolysis experiments.
In Nature, compaction restrains the communication of the products and the static pressure occurs, conse-quently the retardation works to some degree. The majority of kinetic models of HC generation do not consider static pressure, therefore these simulations are unrealistic. Some arti®cial maturations have been carried out under more realistic conditions in closed systems, where internal pressure buildups occur, which are caused partly by volatile degradation products and partly by the water contents of the starting sample.
Costa Neto (1991) has corroborated that pressure can cause acceleration or retardation of the maturation process on the basis of theoretical consideration (the critical distances of reactants are controlled by pressure the sediment is subjected
reaction and Carr (1999) emphasised the retention of volatiles within the molecular structure, which prevents the molecular reorganisation. A kinetic model has been developed and tested on two basins, suggesting that the onset of HC generation diers signi®cantly from those predicted by other models (Carr, 1999).
During the last decade, hydrous pyrolysis experiments became popular (e.g. Lewan, 1985). In these experi-ments the pressure is controlled by the vapour pressure of the aqueous phase and by temperature applied. A general uncertainty of closed-vessel pyrolysis experi-ments is the unrestricted relative volume of such vessels (the ratio of dead volume to sample volume). The ratio between the volume of sample and vessel usually varies between 0.1 and 0.5. This author believes that variations of the above ratio may cause dierences in the progress of reaction. Moreover, such experiments are dissimilar to Nature. In Nature, real closed systems are probably subordinate as compared to quasi-closed systems during petroleum formation. Otherwise, HC expulsion from the generation site could not take place.
Spencer (1987) studied overpressuring in Rocky Mountain region and concluded that ``most high pres-sures in the region are caused by present-day or recently active oil and gas generation or generation in the last few million years in low permeability rock successions that still contain organic matter capable of yielding thermally generated HCs.'' He also stated that ``where regional overpressuring occurs, it is most common in rocks with temperatures higher than 93C''. Hunt (1990)
suggested the temperatures of 90±100C for the top of
the oil and gas generation compartment around the world or for one seal of abnormally overpressuring more correctly. These observations suggest that the onset of oil genesis must have occurred deeper at higher temperature, but they did not tell anything about the bottom of this compartment. The seal in clastic sedi-ments is caused by carbonate precipitation along a thermocline. The carbonate mineralisation is probably resulted in by the decomposition of organic matter in rocks. The CO2generation from kerogens starts prior to
HC generation, and does not build up overpressure, consequently, the formation of cementing carbonate layer can represent the temperature of HC generation only with an additive temperature member (the zone of maximum carbonization occurring at vitrinite re¯ec-tance of 0.4±0.5%; Hunt, 1990). Mann and Mackenzie (1990) suggested somewhat deeper top seals for pressure compartments than Hunt's observation). In over-pressured basins, there were frequently observed two zones of overpressuring (e.g. Hunt, 1990; Mann and Mackenzie, 1990; Hao et al., 1995). The considerable retardation of maturation occurs in the deeper pressure compartments (Hao et al., 1995), indicating the presence of HC generation in these deeper compartments. Another reservation, Spencer (1987) and Hunt (1990) do
not consider whether the applied temperature (present temperature) is the maximum temperature or it was earlier higher. Dickey and Cox (1977) studied oil and gas reservoirs with abnormally-low pressures. The cause of pressures was related to the removal of overburden, which has resulted in a dilation of the pore volume and a drop in reservoir temperature. The low pressures occur in well-consolidated sediments in onshore basins, which have been uplifted in the geological past. The Green River Basin has been uplifted, eroded and cooled somewhat, and its present-day high ¯uid pressures are actually caused by the fact that in the deep basin there is a closed-¯uid system where the high pressures were caused by older HC generation and have not had time to bleed o (Leigh C. Price, pers. comm.).
The overpressure is also present in ``cold basins'' (basins with lower than normal geothermal gradients), for example Lower Kura Depression, Azerbaijan (Inan et al., 1997). The estimation of the depth of oil window in such cases is dicult, because the deepest wells may just penetrate into commencing zones of oil generation, and the only method is computer-aided basin modelling to outline the oil-¯oor. The place of oil window may depend on the concept, parameters and hypothesis of the applied method, and observations would be required to prove the validity of the model.
It is important to be very cautious because other pressure-causing factors are also known , for example, dewatering of clay diagenesis and aquathermal heating (there is no problem in case of abnormally high pore-¯uid pressures where HCs are the only moveable phases present, and active petroleum formation has been detected in a related source bed). Some data suggest that high pore pressures can cause vertical fractures, which would allow HC migration. If this is true, in a source rock cell, the maximum possible attained pressure will be controlled by the minimum pressure needed for frac-turing the source rock in question.
The author maintains that pressure plays an impor-tant role in hydrocarbon generation. Pressure is built up by thermal degradation of kerogen. However, its scale is governed by the physical properties of source rocks , such as permeability, fracturing stress and also by the change of temperature during petroleum formation. If a source rock is impermeable, ¯uid pressure may evolve as a function of the generation rate. If oil genesis has ®n-ished or has been interrupted, the pressure may dissipate or drop after a certain time. Pressure varies in the same way as temperature during basin evolution, both having the same trend.
However, ongoing hydrolytic disproportionation may also destroy petroleums, oxidising hydrocarbons, pro-ducing CO2 and CH4 end products (Helgeson et al.,
1993; Price et al., 1998). The role of hydrolytic dis-proportionation in overpressured compartments requires further studies.
That pressure is one of the causes of the thermal sta-bility of hydrocarbons, was realised and accepted during the last decade only [e.g. Brigaud, 1988 (cited in Domine et al., 1998); Mango, 1991; Price and Wenger, 1992; Pepper and Dodd, 1995; Planche, 1996; McNeil and BeMent, 1996], disproving traditional thought that hydrocarbons are unstable under catagenetic conditions and progressively decompose to methane and pyrobitu-men between 150 and 200C (Tissot and Welte, 1984;
Quigley and Mackenzie, 1988; Braun and Burnham, 1992; Ungerer, 1993). Burnham et al. (1997) revised their earlier opinion: ``At a minimum, the kinetic para-meters . . . indicate that crude oil should survive for geologic time in the 170±200C temperature regime. At a
maximum, hydrocarbon-rich oils may be able to survive at 200±250C for geologic time.'' The higher thermal
stability of crude oils implies that of kerogens in an overpressured compartment, i.e. thus cracking in good quality source rocks should be at least similar slow to cracking in deep petroleum pools (Pepper and Dodd, 1995). The higher thermal stability of kerogens implies the higher temperature window for oil formations.
5.7. Restrictions of the method applied
The method presented in this paper for maturity ranking of crude oils probably requires particular con-ditions for estimating generation temperatures:
1. the present-day temperature must be close to the maximum temperature;
2. several relatively small traps should be present not far from the source beds with short vertical migration opportunities;
3. relatively young genesis which limits the chance of the reservoir alterations and of the mixing of hydrocarbons of dierent maturity;
4. no communications among the pooled oils formed at dierent level of maturation from the same source bed;
5. application of the usual maturation parameters applied for rock samples requires precaution, because of the organic matter extracted from powdered rocks with solvents diers from that of which is removed by primary migration. Studies of Sajgo et al. (1983) and Price and Clayton (1992) have shown that the extractable biological markers of the more open pores of a single sedimentary sample can dier considerably from those of the more closed pores, the lower molecular weights
species having a greater ability to move from the more closed pores to more open ones.
This author has used these restraints and perhaps others are also needed. Nevertheless, the restrictions above suggest that the method introduced cannot be applied in general. In many cases, the generated oils probably accumulated in large reservoirs and oils with dierent maturities were mixed so that they exhibit an average rank. Each case is unique, although there are probably a lot of closely-related cases.
6. Conclusions
A new method was established for ranking maturity of oils. The method is based on homolysis of the side-chains of dierent biological marker homologs. Mole-cular and homologous maturity ratios were employed for ranking. Maturity ranking was cross-checked against maturity parameters introduced earlier and the novel method was graded. It is believed that the epi-merization at C-20 in steranes attained equilibrium in source rocks after expulsion of hydrocarbons. Conse-quently, dierent extents of this epimerization between source rocks and crude oils is not negative evidence in correlation work.
Independence of the homologous-ratio method on source and migration eects was suggested. The maturity ranking and geological conditions in the Pannonian basin have enabled the author to estimate minimum generation temperatures of the oils and place them into ®ve groups. Minimum HC temperatures were deduced from reservoir temperatures. The least mature oils formed above 130±135C and the most mature oils
above 210±215C. These data con®rmed SajgoÂ's (1980)
observations, i.e. intense oil genesis starts at 142C and
continues at 233C (at bottomhole) in HoÂd-I borehole,
which was drilled in the area of the studied oils. The fallacy, in my opinion, of trading time for tem-perature on a large scale in kinetic models for petroleum formation is examined and criticised, and several examples are exhibited against low temperature (<100C) oil
genesis and against time as a maturation factor on geo-logical scale.
This author ®rmly believes that pressure has an important role in formation of oils beyond that of being the driving force for microfracturing.
The author endorses the temperature range of 100± 300C as the true temperature window for oil genesis,
and based on his own observations, concludes that most oils are generated between 130 and 250C. The least
mature oils in this study were formed without carbon-carbon bond cleavage above 135C. The carbon±carbon
bond ®ssion starts above 155C and the intense cracking
above 215C and this temperature coincides with the
onset of second zone of oil genesis in HoÂd-I (SajgoÂ, 1980). Gas generation starts together with the onset of cracking (above 155C).
The generation temperature ranges of thresholds in Table 2 are minimum values, which may be somewhat higher. Many questions have remained untouched in this article, others require further elucidation. Hope-fully, this paper will encourage petroleum geoscientists to expand this study into a fuller understanding of HC generation and migration.
Acknowledgements
This work was funded through grant: OTKA T 023213 from the Hungarian National Science Founda-tion. I thank Mr. K. Balla (Petroleum Explor. Co.) for providing support and permission to publish this study. I should also like to thank Dr. V. Dank (Central Oce of Geology) for encouraging me for this investigation. The careful reading and improving of the manuscript from Drs. O. Tomschey, G. Wol, W.A. Young, L.-C. Kuo (reviewer) and S. Inan (co-editor) are highly appreciated. Review by Leigh Price dramatically improved the manuscript. Thanks are also due to Mrs. A. MaroÂt, Mrs. V. Csontos, Mrs. I. Barta and Ms. K. DoÈme for technical assistance.
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