assessment of generation temperatures of crude oils · pii: s0146-6380(00)00097-8 ... the maturity...

Assessment of generation temperatures of crude oils

Cs. SajgoÂ *

Laboratory for Geochemical Research, Hungarian Academy of Science, BudaoÈrsi uÂ t 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 maturationparameters. The oils have at least ®ve maturity stages, i.e. they have been generated under di�erent thermal conditions.

The highest reservoir temperature in each group was chosen as the best estimate of the groups' temperature just belowthe 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±135�C for the least matureoils to 210±215�C for the most mature oils. In the least mature oils cracking was not observed, hence carbon±carboncracking reactions had not taken place during their genesis. The most mature oils are intensively cracked oils; they arealmost condensates. Two major genetic groups (families) of oils were found in the area. Both are present in each

maturation level. The e�ects of migration were checked, and no in¯uence on maturation was found. A number of theoils are in overpressured reservoirs within, or just above, the zone of the present-day active oil generation, hence thepresent-day temperatures of the pools must have been maximum temperatures. Contrary to the traditionally accepted

temperature range for petroleum generation±maturation reactions (50±150�C), there is strong evidence from this studythat the onset of oil generation requires temperatures higher than 130�C and is still proceeding above 215�C. # 2000Published by Elsevier Science Ltd. All rights reserved.

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 geologicmaterials. Chemically, crude oils are mixtures of hydro-

carbons, containing small amounts of oxygen-, nitrogen-and sulphur-bearing compounds, and traces of metallicconstituents. The compositions of oils exhibit a con-

siderable variation (Tissot and Welte, 1978, pp. 379±410).Various petroleum classi®cations have been suggestedby geochemists and oil re®ners. Re®ners concentrate on

the chemical and physical properties of the distillationfractions. Geochemists attempt to correlate oils tosource 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 andbecause the compositions have not reached thermo-dynamic equilibrium, i.e. they can alter in reservoir (e.g.

Evans et al., 1971). Consequently, a given compositioncan be achieved through di�erent pathways. Petroleumcompositions 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 inreservoirs. The ®rst factor is a generic one, the second is

a genetic one. The e�ects of the third di�erent dependon the situation.Generally, thermal maturation, deasphalting, biode-

gradation and water-washing are considered to be

reservoir alteration processes. Each can seriously modifythe composition of oils. Reservoir thermal maturatione�ects parallel source maturation e�ects (second factor).

0146-6380/00/$ - see front matter # 2000 Published by Elsevier Science Ltd. All rights reserved.

PI I : S0146-6380(00 )00097-8

Organic Geochemistry 31 (2000) 1301±1323

www.elsevier.nl/locate/orggeochem

* Fax:+36-1-319-3137.

E-mail address: [email protected]

Consequently there is no analysis that could give reli-able evidence about place and time of generation. I havenot found any convincing case histories that show onlythermal degradation of reservoired oils. Evans et al.

(1971) and Rogers et al. (1974) gave reasonable expla-nations for formation of pyrobitumens and methanefrom thermocracked oils in reservoirs; but they could

provide no real evidence that the products had beenformed 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 catastropheshad occurred (crude oils not stable at any subsurfacedepth 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 ageological 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 o�er opportunities for overpressured

oils to leave reservoirs. This author cannot presentlyaccept 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 e�ects of a thermal alteration of the

oils studied in this paper would be theoretically negli-gible because the oils' genesis is young (Pliocene toQuaternary). Furthermore the oils have migrated verti-cally upward and therefore their reservoir temperatures

are less than their generation temperatures. Thus, in thisstudy, the maturity of a given oil will be related to thematurity of its source rock at the time of oil release.

Consequently, the generation temperature of a given oilcan possibly be inferred from its maturity. (This assumesthat the present reservoir temperature is so much lower

than the source temperature at the time of release that nofurther in-reservoir maturation of the oil occurs.)

2. Geology of the Pannonian Basin

Two books were published about Pannonian Basin

(Royden andHorvaÂ th, 1988; Teleki et al., 1994) containingnumerous studies, including tectonic, sedimentological,biostratigraphic, geothermal, maturation, petroleum

geological and geochemical studies. On the basis of theabove papers, I summarise some relevant statements onPannonian Basin.

The Pannonian Basin in Central Europe is a back-arcbasin superimposed on the Alpine compressional mega-structure, that resulted from continental collisionbetween Europe and smaller continental fragments fol-

lowing southward subduction of Thethyan ocean ¯oor.It represents one part of broad basin, which was formedby rising of the Alp, Carpathian and Dinaric mountains,

and by lowering of the terrain between their ranges. Aset 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 thatlie to and superimposed on thrust belts (Vienna basin, theTranscarpathian 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 platefragments juxtaposed by Cretaceous to Eocene tectonic

events make up the pre-Tertiary basement complex ofthe region. The largest subbasin is the Great HungarianPlain 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 morphologyis outlined by a system of troughs, which are divided bybasement highs. Extensive geophysical surveys and

numerous deep drillings have led to knowledge of thestructural characteristics and sedimentation record ofthe basin. The Neogene sediments are almost exclusively

shales and sandstones. The early Neogene sedimenta-tion resulted in mostly transgressive sequences, whichdeposited in deeper parts of the subbasins. In the

troughs ®ne-grained marls and calcareous marls wereaccumulated with a relatively high organic content(Corg=1±2%). At this time the area was a part ofParathethys sea (maximum water depth: 800±1000 m).

During the Sarmatian, the Pannonian basin was isolatedfrom 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 systemsprograding from north and northwest towards thesouth. The Pliocene sediments were deposited in delta

plain facies, their ¯uvio-lacustrine environment isdemonstrated by the characteristic presence of browncoal and lignite seams.The studied oils came from the area of the Great

Hungarian Plain, the majority came from region ofAlgyoÂ Â ®eld and BeÂ keÂ s basin. The oils generated in thedeeper units of the Great Hungarian Plain [MakoÂ

trough, BeÂ keÂ s depression, NagykunsaÂ g basin, Derecskebasin and JaÂ szsaÂ g basin: look on Maps I, II and IV inRoyden and HorvaÂ th (1988)].

3. Approach

The maturity of oils is an arti®cial term. Thermalmaturation increases the quantity of light hydrocarbonsand the para�nicity, while the percentage of NSO

compounds falls. The more mature oils are nearer to thestate of equilibrium than the less mature ones, based ontheir molecular compositions. In this study the oils are

1302 Cs. SajgoÂ / Organic Geochemistry 31 (2000) 1301±1323

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 oilsto have formed in the principal phase of oil generationduring catagenesis. Most of the biological marker iso-

merizations can take place prior to the onset or by theearly stage of the oil genesis (SajgoÂ , 1984; Mackenzie etal., 1988; SajgoÂ et al., 1988); thus the use of isomeriza-

tions is dubious in this case. The anomalies found by tenHaven 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 directlyre¯ect the maturity of the source rock at the time ofpetroleum expulsion. The application of tetracyclic aro-

matic hydrocarbon distributions as maturity indicatorsbegan with Tissot et al. (1974), who studied extracts ofToarcian 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 theC19±C21 aromatics with increasing depth of burial. This

shift in carbon number distribution, later attributed toscisson 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 extendedby Mackenzie (1980) and Mackenzie et al. (1981a). Twobasic families were observed: a monoaromatic one and a

triaromatic one (the structural types were inferred bymass spectral interpretation based on spectra observedfor similar compounds, but are by no means proven),

which both showed changes with increasing burialdepth. Within each family a number of structural types,thought to be due to variation in the number of nuclearmethyl substituents [the base peaks of monoaromatics

there were types: m/z 239: 1*CH3, m/z 253: 2*CH3 andm/z 267: 3*CH3; and the base peaks for the triaromaticswere types: m/z 217: 1*CH3, m/z 231:2*CH3, m/z 245:

3* CH3, m/z 259: 4* CH3; ``x* CH3''), x denotes numbermethyl groups of ABCD-ring system); see Figs. 1, 2, 5, 6and 8 in Mackenzie et al., (1981a)]. Their application as

maturity parameters became apparent even prior tospeci®c structural elucidation of the molecules involved.Later, most of the peaks in m/z 253, m/z 231 and some

of them in m/z 245 have been identi®ed (e.g. Hussler etal., 1981; Ludwig et al., 1981; Seifert et al., 1983; Rioloand Albrecht, 1985; Moldowan and Fago, 1986; Rioloet al., 1986). Mackenzie (1984) has reviewed the path of

sterol diagenesis and catagenesis (Figs. 14, 15, 17 and18) to various aromatic hydrocarbons. It seems to beobvious, to explain the enrichment of lower molecular

weight components within various aromatic steroidhydrocarbon homologous series in the case of: m/z 239:0*CH3 (probably C-ring monoaromatic, that have lost anuclear methyl group and some rearranged to aromatic

anthrasteroids; y* CH3, where y denotes the numbernuclear methyl groups of ABC-ring system), and m/z267: 2*CH3 (probably C-ring monoaromatic, derived

from 2-, 3-, and 4-methylsterols and some rearranged asdia-ones in m/z 253) m/z 217: 0*CH3 (triaromatic ster-oids, that have lost methyl group from C-17 position

too), m/z 245: 1* CH3 (triaromatic steroids that have amethyl group, which is rearranged from C-10 to eitherC-1, C-4 or other positions), m/z 259 2* CH3 (triaro-

matic steroids, that have two methyl groups probablyderived from 2-, 3-, and 4-methylsterols one of them isrearranged 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 beenused: 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.

SajgoÂ (1984), Wingert and Pomerantz (1986), Requejo(1994) and Requejo et al. (1997) found similar enrichmentof short-chain steranes and diasteranes in oils and sedi-

ments comparing to long-chain ones and the phenomenonwas explained on the basis of extent of maturation.Mackenzie et al. (1981a, 1983, 1988) and SajgoÂ et al.

(1984) found that the relative abundance of short-chain

biomarker homologs to the higher homologs increasedas sediments moved through the oil window. SajgoÂ

(1984), Hughes et al. (1985) and Riolo et al. (1986)

demonstrated the same phenomenon for oils of di�erentmaturities. Amongst the possible explanations given forthe increase of the ratio with maturation are as follows:

i. it re¯ects higher thermal stabilities of the lowermolecular 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 theside chain (long-chain compounds are more sus-ceptible to thermal cracking than short-chains

giving rise to a relative increase of the short-chaincomponents with maturity);

iii. the short-chain steroid species formed from the

kerogen at higher temperatures are in higher relativeabundance comparing to their lower relative abun-dance in products formed at lower temperatures;

iv. a mixture of the above.

Based on laboratory simulation experiments, Mack-enzie et al. (1981b) suggested the homolysis (radical

Cs. SajgoÂ / Organic Geochemistry 31 (2000) 1301±1323 1303

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 notobserved aromatic steroidal hydrocarbons under open

conditions of pyrolysis. Later, Rowland et al. (1986)found only Diels' hydrocarbon (C18 triaromatic steroidof m/z 217) in hydrous pyrolysis experiments, and they

suggested a product±precursor relationship between theC26ÿ28 aromatics 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 (for m/z 253 and m/z 231) in hydrous

pyrolysis experiments with increasing temperatures,emphasising that ratio increases due to preferentialdegradation of long-chain homologs rather than con-version of long- to short-chain homologs. Amongst

other reactions, the carbon±carbon bond cleavage inside-chains as well as the ring system during the thermaldegradation of 5a (H)-cholestane under closed-system

pyrolysis were observed by Abbott et al. (1995). Up tonow, the simulation experiments could not elucidatehow the aforementioned maturity indicators work.

In spite of these this con¯icting results, author acceptsthe concept of real or apparent side-chain cracking onthe basis of the fragmentograms of the eight homo-

logous series studied. The less mature oils display sim-pler homolog distributions than the mature and verymature oils [Figs. l and 2 and see also in Figs. 3.8 and6.10 of Mackenzie (1980); Mackenzie et al. (1983), in

Fig. 14 of Hughes et al. (1985), in Figs. 8, 10 and 11 ofRiolo 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 theresult 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 reactions athigher levels of maturity. Therefore, I have introducedhomologous maturation parameters. Theoretically, their

reliability should be greater than that of the molecularparameters, which show the same trends as the homo-logous parameters, but change only moderately. Per-

haps the molecular parameters re¯ect primarily/mainlythe 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 di�cult toexplain the preferential cracking of a given reactant toanother given product without considerable by-products

under severe enough thermal conditions.

4. Methods

After precipitation of asphaltenes with light petro-leum ether (30±50�C), the remaining was separated

chromatographically on a column of silicagel. Successiveelution with light petroleum, benzene and benzene±methanol (1:1, v/v) a�orded saturated hydrocarbon (Sat),aromatic hydrocarbon (Aro) and resin fractions, respec-

tively. The Sat fractions were analysed by gas chromato-graphy (GC) and computerised gas chromatography±massspectrometry (GC±MS). The Aro fractions were further

separated by thin layer chromatography, mono-triaromaticfractions were analysed by GC±MS. All samples wereanalysed using multiple ion detection. The appropriate

molecular components were identi®ed using priorknowledge of the basic distributions and molecular ionfragmentograms. The further details are described else-

where (SajgoÂ , 1980, 1984; Mackenzie et al., 1981a,b;SajgoÂ et al., 1983, 1988).The maturation ranking was based on quanti®cation

of nine biomarker families in GC±MS runs. In the case

of di�erent key±ion ratios the relative quantities ofmolecular components and homologs in two modes(each peak separately and/or humps/ranges conjointly)

were measured and calculated within the same massfragmentogram.

4.1. Molecular ratios

The following molecular ratios were calculated as

maturation parameters:

1. C20/C20+C28: triaromatic steroid HCs from m/z231, (e.g. Mackenzie et al., 1981a,b)

2. C23/C30=tricyclic diterpane/hopane from m/z 191,(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/z 217 (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 from m/z 245 (SajgoÂ , 1984)5. [C21+C22]/[C21+C22+C28+C29]: monoaromatic

steroid HCs from m/z 253 (e.g. Mackenzie et al.1981a,b; SajgoÂ , 1984)

6. Ts/Tm=18a(H)-trisnorneohopane/17a(H)-trisno-

rhopane from m/z 191 (e.g. Seifert and Moldowan,1978; SajgoÂ , 1984; Peters and Moldowan, 1993).

The sixth molecular parameter: Ts/Tm was suggestedby Seifert and Moldowan (1978) for oil maturityassessment. The reason that the ratio increases with

maturity is not clear.

4.2. Homologous ratios

Homologous ratios (conversions) were calculated forthree series of monoaromatic steroid hydrocarbons(base peaks: m/z 239, 253, 267) (HCs) and for four series


of triaromatic steroid hydrocarbons and (base peaks: m/z217, 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; and �C28±C30, respectively) are believed to

be reactants from which the majority of lower homologsin the samples of advanced maturity were produced.Under severe thermal conditions, some of the reactants

probably produce other cracking products as a result ofbond breaking in the ring systems (e.g. Abbott et al.,1995).

The oils were ranked according to each used maturityparameter and on the basis of rank orders obtained theoils formed ®ve groups of maturity. These groups havebeen 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

SajgoÂ (1984) described 23 crude oils (their locationshowed) from this area of SE Hungary. The 23 oils ofthat study are also part of the present study. Geological

conditions and other details of the 23 oils are describedin SajgoÂ (1984). Clayton et al. (1994) BeÂ keÂ s basin oils: Isupplied 17 of those (seven of them were a part of theabove 23) and Koncz and Etler (1994) also studied oils

from this area using biological marker data of mine intheir paper: 17 oils of their study are involved in thispaper (12 of them were also a part of the above 23).

Figs. l and 2 display the ®ve maturity groups in fourfragmentograms. The four fragmentogram series (m/z217saturates, 253, 231 and 245) best illustrate the ®ve

maturity groups in Figs. 1 and 2, the other fragmento-grams (m/z 191, 217aromatic, 239, 259 and 267) showedless smooth changes with maturity.

5.1. Independence of maturation parameters appliedfrom source control

Reservoir data and oil genetic and maturity groupingsare summarised in Table 1. Reservoir ages vary fromPliocene (Upper Pannonian) to Precambrian. Most of

the oils of this study originate from the south-westernmargin of MakoÂ -HoÂ dmezoÂ Â vaÂ saÂ rhely trench (nos. 1±18,6±33 and 52±53) and BeÂ keÂ s Basin (nos. 18±25, 33±44

and 49±51), two originate (nos. 45±46) from somewhatNorth of the above areas (30±50 km) and the two Oligo-cene oils (nos. 47±48) originate from about 100 kmNorth of the above areas. Oil±oil correlation methods

are described in SajgoÂ (1984); again and as in that study,the same three oil types (genetic groups) were found inthis study. The latter genetic classi®cations of 90 oils by

Clayton et al. (1994) and Koncz and Etler (1994) areconsistent with the interpretation of at least threegenetic oil types. Reservoir temperatures range from 37to 208�C, and many of them are unusually high. The

API gravities (26±50�) also indicate that oils wereexpelled over a range of thermal maturities. In somecases, relatively high-density oils (30±35�API) occur at

temperatures in excess of 100±150�C.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 geneticgroup I is homogeneous and all the maturity classes are

represented by this group. Genetic group II shows aconsiderable dispersion of pristane/phytane and C30-(hop.+mor.)/C29-steranes ratios (Fig. 4) and group II ishomogeneous only according to the oleanane/hopane

ratio (Fig. 3). The members of the maturity groups arescattered more or less independently of the sortingparameters. The small number of oils in the third group

prevents interpretation of their scatter. Thus, the inde-pendence of maturity ranking from source factors isproven for the oil families of this study.

In Fig. 4, a moderate relationship between pristane/phytane and C30 (hop.+mor.)/C29-steranes exists. Thereare at least two possible explanations:

i. both ratios are governed by redox processes in thesame 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

Bulk compositions of petroleums are frequently usedfor classi®cation. I prefer other indicators to the simple

ternary diagram, which in my opinion are subject to toomany other factors governing the position of an oil. Themedium and light studied oils are para�nic, with low

sulphur content. As can be seen in Fig. 5, the geneticgroups are not isolated, and maturity groups are notwell separated. For example, although the more mature

oils are enriched in saturated hydrocarbons, there areexceptions, e.g.: a mature oil is in the ®eld of the leastand low mature oils, and a least mature oil falls among

the very mature and mature oils. Crude oils would bewell-sorted by maturity in a ternary diagram of grosscomposition if the oils had the same source, the samelevel of maturation, the same e�ect of migration, and

the same alterations in reservoirs. Of course, analyticalveri®cation of these factors is rather di�cult, if possibleat all.


Fig. 1. Mass fragmentograms of steranes (m/z 217) in saturated fractions of oils and of ring-C monoaromatic steroid hydrocarbons

(m/z 253) 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 for m/z 217 and oil nos. 1, 4, 6,

a mixture of 11, 12 and 13 oils and 17 shown in Table 1 for m/z 253). 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±C10 side-chain of the higher molecular weight components); (ii) selective thermal

degradation of higher molecular weight components with increasing maturity; or a mixture of both.


Fig. 2. Mass fragmentograms of m/z 231 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 for m/z

231 and oil nos. 1, 4, 5, 9 and 18 shown in Table 1 for m/z 245). 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/z 231) and methylated (m/z

245) triaromatic steroids.


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. AlgyoÂ Â -119 2431±2434 L. Pannonian 122.5 I LtM 30

2. AlgyoÂ Â -261 2350±2360 L. Pannonian 122.5 I LtM 36

3. AlgyoÂ Â -245 1948±1961 U. Pannonian 94 I MM 37

4. AlgyoÂ Â -230 1950±1953.5 U. Pannonian 94 I LM 39

5. AlgyoÂ Â -298 1922±1927 U. Pannonian 92.5 I MM 44

6. AlgyoÂ Â -476 1886±1890 U. Pannonian 90.5 I MM 43

7. AlgyoÂ Â -290 1886±1890 U. Pannonian 90.5 I M 44

8. AlgyoÂ Â -380 1868.5±1871.5 U. Pannonian 88.5 I M 46

9. AlgyoÂ Â -426 1823.5±1828 U. Pannonian 83.5 I M 40

10. AlgyoÂ Â -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. OÈ ttoÈ moÈ s-22 990±992 U. Pannonian 58 I LtM 27

17. FerencszaÂ llaÂ s-61 2418±2420 Precam.-L. Panno. 125 I VM 44

18. Kiszombor-16 2252±2263 Precambrian 126 I VM 40

19. PusztafoÈ ldvaÂ r-177 1703±1706 L. Pannonian 122 I LM 29

20. PusztaszoÂ Â loÂ Â s-29 1740±1741.5 Triassic 115 I LM 30

21. SarkadkeresztuÂ r-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. PuÈ spoÈ kladaÂ ny-3 1733±1744 Miocene 124 I M 42

25. NaÂ dudvar-19 1528±1531 L. Pannonian 85 I LtM 26

26. Kelebia-20 851±860 Paleozoic 59 II LM 31

27. AÂ sotthalom-15 1060±1062 Miocene 83 II LM 32

28. AÂ sotthalom-27 1051±1061 Paleozoic 83 II LM 32

29. UÈ lleÂ s-26 2127±2140 Miocene 130 II M 45

30. UÈ lleÂ s-31 2770±2787 Triassic 159 II MM 35

31. Ruzsa-2 2301±2309 L. Pannonian 127 II VM 39

32. ForraÂ skuÂ t-5 3329.5±3337.5 Triassic 160 II M 29

33. MakoÂ -1 4142±4156 L. Pannonian 147 II VM 43

34. PusztafoÈ ldvaÂ r-114 1776±1777 L. Pannonian 125 II LtM 27

35. CsanaÂ dapaÂ ca-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. KomaÂ di-3 2527±2535 Miocene 148 II LM 38

40. KomaÂ di-6 2204±2212 Miocene 136 II MM 39

41. KomaÂ di-10 21342140 L. Pannonian 126 II M 44

42. MezoÂ Â sas±3 2568±2575 Precambrian 142 II M 40

43. FuÂ Â zesgyarmat-3 1796±1800 Miocene 116.8 II M 46

44. EndroÂ Â d-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. DemjeÂ nK-3 206±268 Oligocene 37 II LtM 30

48. MezuÂ Â keresztes-25 1415±1429 Oligocene 80/?/ II MM 42

49. Biharugra-3 2295±2303 Mesozoic 124 Mix.I.±II. LtM 44

50. MezuÂ Â hegyes-14 1188. 5±1190 L. Pannonian 89 III LM 35

51. ToÂ tkomloÂ s-26 1898.6±1899.5 Mesozoic 138 III M 38

52. UjszentivaÂ n-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;

maturity levels: least-mature (LtM), low-mature (LM), moderate-mature (MM), mature (M) and very-mature oils (VM).


5.3. Correlation with commonly used maturity indicators

A dozen indices used or suggested as maturationparameters (e.g. Mackenzie, 1984; Peters and Moldowan,

1993), were chosen to compare with the homologous-ratio maturity ranking established in this study. Thisserves to check the new maturity indices of this study. InFig. 6, four traditionally-used parameters are shown. (In

Fig. 3. Plot of oleanane/hopane ratios against C30 hop.+mor./C29-steranes ratios (C30 hop.+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 C30 hop.+mor./C29-steranes values (C30 hop.+mor.= hopane+moretane; C29-

steranes=(20R+20S)-5a(H),14b(H),17b(H)- and (20R+20S)-5a(H),14a(H),17a(H)-24-ethylcholestane). Both the source and matur-

ity 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).


Figs. 6±8, the mean values, the probable range ofoccurrence, 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, alsoshown in Fig. 5) shows a gradual increase with maturity,

nevertheless the ranges are much wider among the lessmature oils, than in the more mature ones, and thevalues for less mature petroleums overlap the values formore mature oils.

The two isoprenoid/n-alkane ratios (pr/nC17 and ph/nC18) run largely parallel each other, except in the lowmature oils. The change of these ratios indicates that n-

alkanes are more stable to thermal degradation thanisoprenoid hydrocarbons. The greatest change in thevalues is between the mature and very mature oils.

The pristane/phytane (pr/ph) ratio is not a maturityindicator, as is seen in the case of the least, low, andmoderately mature oils, but the ratio increases from the

moderately mature oils to the very mature oils. Thismeans that the pr/ph ratio is sensitive to maturationonly to under rather severe thermal conditions. Ofcourse, 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 C2920S

20S�20R 217� � and C2920S

20S�20R 218� �(from m/z 217 and 218 fragmentograms) represent the

same con®gurational isomerization at C-20 in the5a(H), 14a (H), 17a (H) C29-sterane SajgoÂ and Le¯er(1986) and SajgoÂ et al. (1988) found that the m/z 218

fragmentograms provided less dispersion in samples ofthe same area than the m/z 217 fragmentograms andtherefore m/z 218 is preferred to m/z 217. Some coelutionoccurs likely in the case of the m/z 217 fragmentograms

of the studied samples from the same part of the Pan-nonian basin. The two curves run more or less paralleland they suggest that complete epimerization has not

occurred in the least and low mature crude oils. Thechange of the m/z 218 fragmentograms is not signi®cantbetween the moderately and very mature oils. However,

in the case of m/z 217 fragmentograms, the completionwent on markedly. In the study of rocks of the HoÂ d-Iborehole (SajgoÂ et al., 1984, 1988; SajgoÂ and Le¯er,

1986), complete epimerization was observed before theonset of petroleum formation.The present results suggest that the completion of the

C-20 epimerization in steranes was reached after the

expulsion of petroleum from its source bed. Consequently,I suggest that the degree of isomerisation of oils usuallyre¯ects the thermal conditions in the source beds at the

Fig. 5. Ternary diagram depicting relative distributions of saturated hydrocarbons, aromatic hydrocarbons and NSO compounds

(asphaltenes and resines) for crude oils studied. Both the source and maturity groups are indicated (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).


time of primarymigration, and that further conversionmayoccur 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 thePannonian basin), or possibly by a long geologic time atthe same temperature (accepted by many scientists). It is

important to emphasise that the levels of maturation inthe source rocks and in the expelled petroleums will notnecessarily be the same, and it is likely that the extent of

maturation in source rocks usually exceeds that inexpelled petroleums. Consequently a reasonable di�er-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 di�erent reasons.According to present thought, the backbone rearrange-ment of the steroid system takes place during diagenesisunder mild thermal conditions (Seifert and Moldowan,

1978; Sieskind et al., 1979; Requejo et al., 1997; vanKaam-Peters et al., 1998). Diasteranes, the products ofthis rearrangement, have higher thermal stability than

the steranes, therefore their relative concentrationincreases 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. Therelative proportion of aa-con®guration is one of themost 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 paralleltrends. The ratios rise rapidly between the stages of theleast and the moderately-mature oils, and then increase

only slightly.Some hopanoid maturity indicators are displayed in Fig.

8. Three ratios (C3122S

22S�22R, C3222S

22S�22R and C3322S

22S�22R)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 increasebetween the least and the low mature oils, drop slightly

to mature oils and ®nally fall somewhat more betweenmature and very mature oils. The homohopane (C31hopane) ratio shows a minimal steady rise from low

Fig. 6. Other parameters [�CH% (the sum of Sat and Aro fractions) in C15+ fraction of oils; pristane/phytane, pristane/nC17 and

phytane/nC18 ratios] against the molecular and homolog maturity parameters applied for ranking.


mature oils to very mature oils. (In the case of the C31hopane some coelution of gammacerane with the 22R

isomer was observed). At present, this author has noexplanation for these observations. The extent of changesis 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 theC30 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 C29 hopane

is more resistant to maturation as compared to C30

hopane and/or the methyl group cleavage of the C30

hopane produces the C29 hopane during maturation.

During the cross-checking of the established maturityclassi®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 theascertainment of the generation temperatures of crudeoils in this study.

5.4. Independence on migration

The e�ects of migration were also checked. Shi Ji-yang et al. (1982), Ho�mann et al. (1984) and SajgoÂ

(1984) found that oils had much lower steroid aromati-

zation ratios (triaromatic/mono-+triaromatic steroids;see, e.g. Mackenzie, 1984) than would be expected onthe basis of their depth, and according to other maturityparameters. The phenomenon was explained as an e�ect

of migration, i.e. the relative enrichment of monoaro-matic steroid HCs was caused by the easier migration ofmonoaromatic steroids relative to triaromatics, as their

polarity is less than that of triaromatics [Carlson andChamberlain (1986) have proven applying adsorptionfree energy di�erences on clay mineral surface in liquid±

solid chromatography]. The crude oils of this study weredivided into six migration groups (on the basis of theirapparent aromatization ratios), in which there was no

evident correlation between the maturity and migrationgrouping. The members of each maturity group werealmost all present in each migration group, and no reg-ularities of migration were observed in the distributions

[Carslson and Chamberlain (1986) have not foundmigrational fractionation between the short-chain andlong-chain members within a homolog series: e.g. form/z

Fig. 7. Accepted maturity parameters of steranes (for key to the abbreviations see the text) against the molecular and homolog

maturity parameters applied for ranking.


253 monoaromatic and m/z 231 triaromatic steroidsapplying adsorption free energy di�erences on clay

mineral surface in liquid±solid chromatography).

5.5. Generation temperatures of crude oils

The reservoir temperatures of some the petroleums ofthis study are signi®cantly higher than both the tem-peratures traditionally thought necessary for main-stage

HC generation and the temperatures at which crude oilsare thought to be thermally-stable (so-called oil-dead-line is generally placed at temperatures of 150±175�C,where oils are destroyed, thermal cracking is gone tocompletion; e.g. Hunt, 1979). The reservoir temperaturesof this study demonstrate that petroleum are thermally

more stable than previously generally assumed, the topreservoir temperature in this study even exceeding200�C. Moreover, the generation temperatures for these

oils were higher, and perhaps even substantially higher,than the reservoir temperatures of the oils. Thus thedata of this study clearly demonstrate that an unsolvedproblem remains concerning the generation tempera-

tures for oils. There are several controversial opinionson this topic in the literature. The majority of petroleumgeoscientists believes in a kinetic description for oil-

generation reactions, i.e. both temperature and time areimportant in petroleum formation and interchangeable

to a certain extent. Thus, oil formed at lower tempera-tures in the Silurian and Devonian rocks of the easternSahara (50�C) as compared to the Miocene rocks of the

Los Angeles basin (115�C), because longer times wereavailable for heating the source rocks in the easternSahara (Tissot et al., 1975). This concept was propa-gated in popular simple versions by Karweil (1955),

Lopatin (1971), Connan (1974) and Waples (1980), andit 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 120/150�C (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 onboth 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 pre-exponential factors, and assigned di�erent fractions oforganic matter to each set of rate parameters for each of

Fig. 8. Accepted maturity parameters of hopanes (for key to the abbreviations see the text) against the molecular and homolog

maturity parameters applied for ranking.


the three main types of kerogen (I, II and III). Theirmodel may be valid under laboratory conditions, butthe application of kinetic parameters obtained in thelaboratory at high temperatures and short times to geo-

logical situations is untenable (e.g. Snowdon, 1979;Price, 1983; Barker, 1988; DomineÂ and Enguehard,1992; Price and Wenger, 1992; Price, 1993; DomineÂ et

al., 1998). These models generally use at least 10 ordersof magnitude in extrapolation for time and about a300�C di�erence for temperature. The estimation of

geologic temperatures and burial history is still some-what obscure. In many cases, present-day temperatureswere used, or temperatures from basin evolution models

produced by sophisticated computer models, whichconveyed 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 ofkinetic parameters obtained in the laboratory at high

temperatures and short times to an uncertain thermaland burial history.This author considers that the apparent low tem-

peratures of oil generation in old inactive basins onlyre¯ect basin cooling during the mature and ®nal stagesof sedimentary basin histories (Perrodon, 1983, p.34;

Price, 1983), instead of re¯ecting the e�ect of long burialtimes. This opinion is also a hypothesis; however, itsprobability 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 ofe�ective heating time. Hood et al. (1975) de®ned thee�ective-heating time of a rock as that period spent

within 15�C of the rock's maximum palaeotemperature.Gretener and Curtis (1982) modi®ed this idea. Theystated that time was not a signi®cant factor at tempera-

tures below 50±70�C and higher than 130�C. In the lattercase, they believed that source rocks would pass entirelythrough the oil window in little more than 10 Ma at140�C. They also calculated that time would operate

e�ectively between 70 and 100�C in Paleozoic sourcerocks and between 100 and 130�C in Mesozoic sourcerocks. The method of Hood et al. (1975) and its

improved version (in Bostick et al., 1978), are widelyused and give reasonably good correspondences withmeasured data (VetoÂ Â , 1980; Waples, 1984; SajgoÂ et al.,

1988).Another minority of geoscientists regards the e�ect

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; Ammosovet al., 1977; SajgoÂ , 1980; Suggate, 1982). Price (1983,1985) stated that petroleum formation-maturation

reactions were not ®rst-order, as had been presumedearlier, but instead were higher-ordered. Recently,DomineÂ et al. (1998) corroborated this observation. If

this is the case, the application of the Arrhenius equa-tion would be invalid and would produce deceptiveinterpretations.SajgoÂ and Le¯er (1986) pointed out that many pro-

blems in oil generation models originate from uncertain®eld data, untestable tectonic models, and transientthermal anomalies.

5.6. Implication of maturity ranking for oil generativetemperatures

The reservoir temperatures of the di�erent maturitygroups of the oils of this study were tabulated and a

gradual rise of the highest reservoir temperatures wasobserved (Table 2). The range of reservoir temperaturesalso 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 verticaloccurrence of traps in the area of this study. A shortvertical migration was conservatively assumed in the

case of each maturity group, hence the given distancesof this migration for each oil group re¯ect only theadditional temperature member to the highest reservoir

temperatures in the assumed minimum temperatures ofgeneration. The generation temperatures in Table 2 areminimum temperatures and are only approximate, buttheir reliability probably is no worse than that of the

kinetic methods. Table 2 contains vitrinite re¯ectancedata from the same area (SajgoÂ , 1980; SajgoÂ et al.,1988), and from Ammosov et al. (1977). Ammosov and

his co-workers gave a table of vitrinite re¯ectances andminimum burial paleotemperatures needed to attain tothe given re¯ectance. The agreement with measured Ro

values is very good except for very mature oils.The range of the ascertained minimum temperatures

of generation (130±215�C) for the oils of this study is ingood accordance with thresholds of intense petroleum

genesis in HoÂ d-I found by SajgoÂ (1980). SajgoÂ foundthat the principal phase of oil genesis started at 142�C inHoÂ d-I, with a second zone of generation which started

at 218�C and continued at 233�C (bottomhole).These high thresholds for generation temperatures

contradict the established concepts discussed above, but

concurrently several published and unpublished resultssupport the higher temperatures.Philippi (1965, 1975) found that the generation of

petroleum took place at about 150�C in Ventura andLos Angeles basins. In the case of light HCs from theCalifornia basins, he found the maximum similaritiesbetween extracts and ``normal'' oils occurred at about

160�C. Hood and Castano (1974) stated that the principalzone of oil generation (Vassoyevich et al., 1970) couldbe found in the temperature range of about 130±210�C


in San Joaquin basin. SajgoÂ (1980) discussed some otherexamples from the literature (Connan, 1974; LaPlante,1974; Dow, 1978; Gamintchi, 1979; TeichmuÈ ller, 1979).

Price (1982, 1983, 1993) summarised the observationsthat 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. Healso claimed they could not detect the threshold ofintense generation of oil even at minimum temperatures

of 160�C. It is important to emphasise that Price's con-clusions are based on studies of rocks that had burialtimes, in the main, of 40±250 Ma.Saxby (1982) pointed out that HC generation

required hotter conditions (>120�C) than that pro-posed in most previous schemes (60±110�C), based oncoali®cation studies and geochemical considerations in

Australian oil basins. He set the onset of oil formationat 1.0% Ro and proposed the end of oil generation at2.0% Ro. Recently, Grice et al. (2000) have estimated Ro

between 1.1 and 1.6% for the oils of Gippsland andCarnarvon Basins on the basis of diamondoid hydro-carbon ratios.Thompson (1983) studied light HCs of 76 petroleums

from di�erent parts of the USA. The oils were classi®edas normal, mature, supermature and biodegraded. Hegave a range of 138±149�C as generation temperatures

for mature for normal oils (42% of his sample base).For supermature oils, Thompson suggested temperaturesgreater than 190�C for HC generation, with certain

reservations. The least and low mature oils of this studyprobably 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 thevery mature oils may be the equivalent of his supermatureoils. Thompson's (1983) generation temperatures supportthe 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, thatfour or seven oils were mature and 16 or 13 oils were

supermature (on the basis of heptane or isoheptanevalues, 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 areahave been corroborated.Petrov (1984, p. 88) employed the concentration

ratios of epimeric 1,2-dimethyl cyclopentanes to estimateoil generation temperatures, assuming thermodynamicequilibrium, and obtained a range of 130±300�C , with

an average of 160�C.Cooles et al. (1986) stated that major oil generation

from kerogen occurred between 120 and 150�C in thesubsurface in the case of oil-prone source rocks. They

stated that gas-prone (refractory) kerogens generated oilfrom 180�C up to about 250�C. A mixture of oil- andgas-prone kerogens generated petroleum between 120

and 220�C. They studied 10 source rocks and dis-tinguished only two types of kerogen: (1) labile (oil-prone) and (2) refractory (gas-prone). I believe that the

nature of both labile and refractory kerogens is morecomplex, and that further subdivisions are necessary,which would result in a re®ned interpretation ofobserved oil generation temperatures. In a later study,

Quigley and Mackenzie (1988) stated that the in¯uenceof time was not great in subsurface petroleum formationand that most oils were formed between 100 and 150�C,and most gases between 150 and 220�C. They derivedequations from their work.Chen et al. (1996) found new maturity indices for

highly mature oils. Based on diamondoid hydrocarbonratios, they stated that crude oils of the Tarim Basin aregenerally very mature (Ro> 1.1%) and condensates

from Tarim and some other basins have maturitiesequivalent to Ro values of 1.6±2.0%. However, Li et al.(1999) gave much lower maturity values for oils fromsome areas of the Tarim Basin on the basis of methyl-

phenathrene indices and the ``Mango parameter'' (Ro of0.73±0.93 and of 0.62±0.92%, respectively), but they didnot mention the above di�erent 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

Low-mature

oils

Moderate-mature

oils

Mature-oils Very-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

Measured Ro at the given temperature range

in HoÂ d-I (%)

0.63±0.66 0.77±0.83 0.90±0.93 1.07±1.17 1.67±1.75

Assumed Ro values by Ammosov at the given

temperature range (%)

0.67±0.70 0.80±0.83 0.90±0.94 1.05±1.12 1.42±1.56


(1996) found three phases of oil generation and migra-tion corresponding to organic inclusion groups withhomogenisation temperatures of 200±240, of 160±200and of 80±130�C in the Tazhong petroleum system of

the Tarim Basin, which may be a possible explanationfor the above contradiction.Kissin (1998) studied aromatic compounds in the

middle of catagenesis and from this work, estimated thethermodynamic equilibrium in most crude oils atbetween 200 and 300�C, based on the distribution of

these types of aromatic compounds for a given carbonatom number.The above studies give a range of petroleum forma-

tion between 100 and 300�C. The majority stated thatthe genesis of oils occurred partly or entirely above150�C. Even this incomplete list reveals that the kineticmodels suggesting that oil genesis takes place between

50 and 150�C (Connan, 1974; Tissot and EspitalieÂ , 1975;Waples, 1980; Quigley and Mackenzie, 1988; Braun andBurnham, 1992; Ungerer, 1993), are unrealistic.

I suggest that their low temperature estimates stemfrom the overestimation of the role of time and from theneglect 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 apetroleum 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 andLopatin have used seams of the Ruhr district as a baseof their calculations. The temperature gradient in these

seams during the subsidence period is not known. It ispossible that it was lower or higher than at present''.Price (1983) studied Karweil's (1955) paper rigorously

and found several other inconsistencies, which havebeen ignored by proponents of kinetic modelling.Today, it is well-known that basins are the hottest duringtheir 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 stillfavoured by most petroleum geoscientists in spite of thenow widespread recognition of temperature changes

during basin evolution. Such researchers apparently alsodo not realise that the idea is based on doubling thereaction rates for a 10�C increase in temperature

(Lopatin, 1971; Connan, 1974) and was originallyestablished for ¯uids within about a temperature rangeof 100�C. Proponents and users of kinetic modellingalso assume stable heat-¯ow models (Tissot and Espita-

lieÂ , 1975) , which are untenable in the light of modernbasin evolution models. Waples (1984, p. 50) admitted:``In general, temperature data are by far the weakest

part of any time-temperature model.'' (This statementimplies that one of the two foundation-stones of kineticmodelling is weak or only moderately reliable.)Another important problem has arisen from the

ignorance of the role of pressure in oil genesis. With theexception of Sweeney et al. (1986) and Carr (1999), mostkinetic models neglect it, although Sweeney et al. (1986)

stated that they would study the e�ect of the variationof pressure because it was then incorporable to theirmodel. Neglecting pressure is unacceptable on the basis

of Le Chatelier's principle. During oil genesis kerogenbreakdown builds up an increasing internal pressurefrom volatile products because the volume of the products

from the reaction is larger than that of the reactants ifnone of the products escape in closed or quasi-closedsystems. This inhibits further thermal decomposition ofkerogen. 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; Go�eÂ and Willey, 1984). SajgoÂ et al.

(1986) found a di�erence in e�ect of static (load) andvolatile (product or ¯uid) pressures in the temperaturerange of 200±450�C. They found that high load pressures

(1.0 and 2.5 Kbar), in quasi-closed systems (which is thecase in Nature) retarded the coali®cation of lignite,hydrocarbon formation, and the maturation reactions

of biomarkers to considerable extents. These processeswere accelerated in a quasi-closed system under 0.06Kbar ¯uid pressure, relative to the open system of thesame static pressure. Later, Price and Wenger (1992)

documented that increasing ¯uid pressures retarded allaspects of HC generation and maturation in aqueous-pyrolysis experiments.

In Nature, compaction restrains the communicationof the products and the static pressure occurs, conse-quently the retardation works to some degree. The

majority of kinetic models of HC generation do notconsider static pressure, therefore these simulations areunrealistic. Some arti®cial maturations have been carriedout under more realistic conditions in closed systems,

where internal pressure buildups occur, which arecaused partly by volatile degradation products andpartly by the water contents of the starting sample.

Costa Neto (1991) has corroborated that pressure cancause acceleration or retardation of the maturationprocess on the basis of theoretical consideration (the

critical distances of reactants are controlled by pressurethe sediment is subjectedDomineÂ (1991), DomineÂ and Enguehard (1992), Price

(1993), Hao et al. (1995) and DomineÂ et al. (1998) pro-vided much evidence for the importance of pressure inprocess of petroleum generation reactions. The over-pressure retardation of organic maturation (based on

vitrinite re¯ectance data) was studied and proved byMcTavish (1998) and Carr (1999). McTavish (1998)underlined the pressure e�ect through heat ¯ow on


reaction and Carr (1999) emphasised the retention ofvolatiles within the molecular structure, which preventsthe molecular reorganisation. A kinetic model has beendeveloped and tested on two basins, suggesting that the

onset of HC generation di�ers signi®cantly from thosepredicted 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 pressureof 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 variesbetween 0.1 and 0.5. This author believes that variationsof the above ratio may cause di�erences in the progressof reaction. Moreover, such experiments are dissimilar

to Nature. In Nature, real closed systems are probablysubordinate as compared to quasi-closed systems duringpetroleum 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 recentlyactive oil and gas generation or generation in the lastfew million years in low permeability rock successions

that still contain organic matter capable of yieldingthermally generated HCs.'' He also stated that ``whereregional overpressuring occurs, it is most common inrocks with temperatures higher than 93�C''. Hunt (1990)

suggested the temperatures of 90±100�C for the top ofthe oil and gas generation compartment around theworld or for one seal of abnormally overpressuring

more correctly. These observations suggest that theonset of oil genesis must have occurred deeper at highertemperature, but they did not tell anything about the

bottom of this compartment. The seal in clastic sedi-ments is caused by carbonate precipitation along athermocline. The carbonate mineralisation is probablyresulted in by the decomposition of organic matter in

rocks. The CO2 generation from kerogens starts prior toHC generation, and does not build up overpressure,consequently, the formation of cementing carbonate

layer can represent the temperature of HC generationonly with an additive temperature member (the zone ofmaximum carbonization occurring at vitrinite re¯ec-

tance of 0.4±0.5%; Hunt, 1990). Mann and Mackenzie(1990) suggested somewhat deeper top seals for pressurecompartments than Hunt's observation). In over-

pressured basins, there were frequently observed twozones of overpressuring (e.g. Hunt, 1990; Mann andMackenzie, 1990; Hao et al., 1995). The considerableretardation of maturation occurs in the deeper pressure

compartments (Hao et al., 1995), indicating the presenceof HC generation in these deeper compartments.Another reservation, Spencer (1987) and Hunt (1990) do

not consider whether the applied temperature (presenttemperature) is the maximum temperature or it wasearlier higher. Dickey and Cox (1977) studied oil andgas 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 anda drop in reservoir temperature. The low pressures

occur in well-consolidated sediments in onshore basins,which have been uplifted in the geological past. TheGreen River Basin has been uplifted, eroded and cooled

somewhat, and its present-day high ¯uid pressures areactually caused by the fact that in the deep basin there isa closed-¯uid system where the high pressures were

caused by older HC generation and have not had timeto 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 (Inanet al., 1997). The estimation of the depth of oil windowin such cases is di�cult, because the deepest wells may

just penetrate into commencing zones of oil generation,and the only method is computer-aided basin modellingto outline the oil-¯oor. The place of oil window may

depend on the concept, parameters and hypothesis ofthe applied method, and observations would be requiredto prove the validity of the model.

It is important to be very cautious because otherpressure-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 phasespresent, and active petroleum formation has beendetected in a related source bed). Some data suggest that

high pore pressures can cause vertical fractures, whichwould allow HC migration. If this is true, in a sourcerock 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 isgoverned by the physical properties of source rocks ,such as permeability, fracturing stress and also by the

change of temperature during petroleum formation. If asource rock is impermeable, ¯uid pressure may evolve asa function of the generation rate. If oil genesis has ®n-

ished or has been interrupted, the pressure may dissipateor drop after a certain time. Pressure varies in the sameway as temperature during basin evolution, both having

the same trend.Possibly hydrolytic disproportionation may play a

role in hydrocarbon generation, with water hydro-genating kerogen, thus providing an extra hydrogen

source for hydrocarbon generation, suppressing ther-mal degradation of hydrocarbons (Seewald, 1994; Gig-genbach, 1997; Price, 1997; Price and McNeil, 1997).


However, ongoing hydrolytic disproportionation mayalso 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 compartmentsrequires further studies.That pressure is one of the causes of the thermal sta-

bility of hydrocarbons, was realised and accepted duringthe last decade only [e.g. Brigaud, 1988 (cited in Domineet al., 1998); Mango, 1991; Price and Wenger, 1992;

Pepper and Dodd, 1995; Planche, 1996; McNeil andBeMent, 1996], disproving traditional thought thathydrocarbons are unstable under catagenetic conditions

and progressively decompose to methane and pyrobitu-men between 150 and 200�C (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 forgeologic time in the 170±200�C temperature regime. At a

maximum, hydrocarbon-rich oils may be able to surviveat 200±250�C for geologic time.'' The higher thermalstability of crude oils implies that of kerogens in an

overpressured compartment, i.e. thus cracking in goodquality source rocks should be at least similar slow tocracking in deep petroleum pools (Pepper and Dodd,

1995). The higher thermal stability of kerogens impliesthe higher temperature window for oil formations.

5.7. Restrictions of the method applied

The method presented in this paper for maturityranking 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 verticalmigration opportunities;

3. relatively young genesis which limits the chance ofthe reservoir alterations and of the mixing ofhydrocarbons of di�erent maturity;

4. no communications among the pooled oils formedat di�erent level of maturation from the samesource bed;

5. application of the usual maturation parametersapplied for rock samples requires precaution,because of the organic matter extracted from

powdered rocks with solvents di�ers from that ofwhich is removed by primary migration. Studiesof SajgoÂ et al. (1983) and Price and Clayton (1992)have shown that the extractable biological markers

of the more open pores of a single sedimentarysample can di�er considerably from those of themore closed pores, the lower molecular weights

species having a greater ability to move from themore closed pores to more open ones.

This author has used these restraints and perhaps

others are also needed. Nevertheless, the restrictionsabove suggest that the method introduced cannot beapplied in general. In many cases, the generated oils

probably accumulated in large reservoirs and oils withdi�erent maturities were mixed so that they exhibit anaverage rank. Each case is unique, although there are

probably a lot of closely-related cases.

6. Conclusions

A new method was established for ranking maturityof oils. The method is based on homolysis of the side-

chains of di�erent biological marker homologs. Mole-cular and homologous maturity ratios were employedfor ranking. Maturity ranking was cross-checked

against maturity parameters introduced earlier and thenovel 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, di�erent extents of this epimerization betweensource rocks and crude oils is not negative evidence in

correlation work.Independence of the homologous-ratio method on

source and migration e�ects was suggested. The maturityranking and geological conditions in the Pannonian

basin have enabled the author to estimate minimumgeneration temperatures of the oils and place them into®ve groups. Minimum HC temperatures were deduced

from reservoir temperatures. The least mature oilsformed above 130±135�C and the most mature oilsabove 210±215�C. These data con®rmed SajgoÂ 's (1980)

observations, i.e. intense oil genesis starts at 142�C andcontinues at 233�C (at bottomhole) in HoÂ d-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 petroleumformation is examined and criticised, and several examplesare exhibited against low temperature (<100�C) 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 beingthe driving force for microfracturing.The author endorses the temperature range of 100±

300�C as the true temperature window for oil genesis,and based on his own observations, concludes that mostoils are generated between 130 and 250�C. The leastmature oils in this study were formed without carbon-

carbon bond cleavage above 135�C. The carbon±carbonbond ®ssion starts above 155�C and the intense crackingstarts above 185�C. The very mature oils were formed


above 215�C and this temperature coincides with theonset of second zone of oil genesis in HoÂ d-I (SajgoÂ ,1980). Gas generation starts together with the onset ofcracking (above 155�C).The generation temperature ranges of thresholds in

Table 2 are minimum values, which may be somewhathigher. Many questions have remained untouched in

this article, others require further elucidation. Hope-fully, this paper will encourage petroleum geoscientiststo expand this study into a fuller understanding of HC

generation and migration.

Acknowledgements

This work was funded through grant: OTKA T023213 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 O�ceof Geology) for encouraging me for this investigation.

The careful reading and improving of the manuscriptfrom Drs. O. Tomschey, G. Wol�, W.A. Young, L.-C.Kuo (reviewer) and S. Inan (co-editor) are highly

appreciated. Review by Leigh Price dramaticallyimproved the manuscript. Thanks are also due to Mrs.A. MaroÂ t, Mrs. V. Csontos, Mrs. I. Barta and Ms. K.DoÈ me for technical assistance.

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