Aspects of hydrocarbon charge of the petroleum system of the Yamal Peninsula, West Siberia basin

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International Journal of Coal Geology 54 (2003) 155–164

Aspects of hydrocarbon charge of the petroleum system

of the Yamal Peninsula, West Siberia basin

B.J. Katza, C.R. Robisona,*, A. Chakhmakhchevb

aChevronTexaco Corp., 4800 Fournace Place, Bellaire, TX 77401-2324, USAbHouston, TX, USA

Abstract

The Yamal peninsula is located in the northern portion of the West Siberia basin adjacent to the Kara Sea. The sedimentary

succession is composed of between 2.5 and 9 km of Jurassic through Paleogene sediment, deposited within lacustrine through

deep marine settings. Although the region is remote and hydrocarbon exploration has been limited, a number of discoveries

have been made. Components of the region’s petroleum system are, however, poorly known. This study examines aspects of

hydrocarbon charge through the integration of new data obtained on core samples from the Malygin field and from 10 oils from

five fields (Bovanenkov, Malygin, Kharasavey, Pyasedaysk, and New Port) with published data.

Source rock screening data from the Malygin field reveal the presence of organic-rich intervals (TOCs approaching 6%)

within the Cretaceous and Jurassic sequences. These data also indicate that at the sampling location these intervals are gas-

prone (hydrogen index values less than 300 mg HC/g TOC). Within the Cretaceous interval, the gas-prone character

appears to be largely depositional. In contrast, in the Jurassic portion of the sequence the hydrogen indices appear to have

been reduced as a result of an advanced level of thermal maturity. Elsewhere on the peninsula where the thermal maturity

of the Jurassic is less advanced, data suggest that the Jurassic sequence includes oil-prone intervals.

Preliminary review of the oil data suggests that the examined oils belong to a single family (i.e., were derived from a

common source) and that much of the variation is a result of different alteration and migration histories. Although the data from

this study were incapable of establishing a definitive correlation, published information and the lack of an effective Cretaceous

liquid hydrocarbon source suggests that these oils were derived from the Jurassic sequence.

D 2003 Elsevier Science B.V. All rights reserved.

Keywords: Hydrocarbon charge; Source rocks; Thermal maturation; Oil characterization; Yamal Peninsula; West Siberia

1. Introduction

The Yamal Peninsula is located in the northern

portion of the West Siberia basin adjacent to the Kara

Sea (Fig. 1). Although several supergiant oil and gas–

0166-5162/03/$ - see front matter D 2003 Elsevier Science B.V. All right

doi:10.1016/S0166-5162(03)00029-6

* Corresponding author.

E-mail address: [email protected]

(C.R. Robison).

condensate fields have been discovered (Telnaes et al.,

1994), the region because of its remoteness remains

largely an exploration frontier and one of the least

explored regions of Western Siberia (Chakhmakhchev

et al., 1994). Additionally, the peninsula may provide

information relevant to exploration within the Kara

Sea.

On the peninsula, the sedimentary sequence thick-

ens from south to north, going from about 2.0 km to a

s reserved.

Fig. 1. Index map of the Yamal Peninsula, Western Siberia, showing

major oil and oil–condensate fields (after Chakhmakhchev et al.,

1994).

B.J. Katz et al. / International Journal of Coal Geology 54 (2003) 155–164156

maximum of nearly 9 km (Telnaes et al., 1994;

Chakhmakhchev et al., 1994, 1995). The Jurassic

through Paleogene sedimentary sequence rests on

Paleozoic and Precambrian basement (Fig. 2). In the

southern part of the peninsula, the Lower and Middle

Jurassic (Tymen Formation) was deposited under

alluvial-lacustrine and shallow marine conditions

(Kontorovich et al., 1975, 1980; Nemchenko and

Rovenskaya, 1987; Sokolova et al., 1992; Telnaes et

al., 1994). In the northern and central portions of the

peninsula, these sediments were deposited in a deep

marine setting (Kontorovich et al., 1975, 1980; Nem-

chenko and Rovenskaya, 1987; Peterson and Clarke,

1989; Sokolova et al., 1992; Telnaes et al., 1994;

Moskvin et al., 1995). The Upper Jurassic organic-

rich Bazhanov Formation was deposited under this

deep marine condition throughout the study area. The

Lower Cretaceous (Megion, Tanopchin, Khanty-

Mans, Pokur, and Kuznetsov Formations) all repre-

sent non-marine deposition (Kontorovich et al., 1975,

1980; Chakhmakhchev et al., 1994, 1995; Telnaes et

al., 1994).

This study examines the hydrocarbon charge com-

ponents of the region’s petroleum system to better

define exploration risks within the region.

2. Samples and analyses

Forty samples from Malygin field, representing a

composite Cretaceous and Jurassic sequence, were

made available to this study. Each sample was geo-

chemically characterized to determine source rock

potential, product type, thermal maturity, and possible

relationship with known oil/condensate accumula-

tions. These analyses included the basic screening

analyses (organic carbon and ‘‘Rock-Eval’’ pyrolysis)

and more detailed characterization of the extracted

bitumen (gas chromatography, gas chromatography-

mass spectrometry of the saturate fraction, and stable

carbon isotope analysis).

Ten oil samples from five fields were also exam-

ined. These samples were characterized using high

performance liquid chromatography, ‘‘whole-oil’’ gas

chromatography, gas chromatography-mass spectrom-

etry of both the saturate and aromatic fractions, and

stable carbon isotope analysis.

3. Source rock potential and character

Total organic carbon (TOC) content of the Creta-

ceous samples ranged from 0.77% to 5.83%; with

TOC ranging from 0.31% to 4.09% in the Jurassic

samples (Fig. 3). About 75% of the samples display

above-average levels of organic enrichment (TOC>

1.0 wt.%). Therefore, much of the examined

sequence warrants further study as being representa-

tive of possible source rock candidates. Above-

average levels of organic enrichment are considered

one of the prerequisites for classification as a

possible petroleum source rock (Tissot and Welte,

1984).

Elevated organic carbon content, however, is not

alone sufficient to establish the presence of a hydro-

carbon source. If thermally immature to mature, a

rock must yield above-average (>2.5 mg HC/g rock)

Fig. 3. Composite organic carbon profile.

Fig. 2. A generalized cross-section that extends from the NW to the SE across the Yamal Peninsula and showing various wells and labeled

stratigraphic horizons (after Chakhmakhchev et al., 1994).

B.J. Katz et al. / International Journal of Coal Geology 54 (2003) 155–164 157

quantities of hydrocarbons to be considered a poten-

tial or effective source rock. In contrast to the organic

carbon data, only f 25% of the samples had an

above-average hydrocarbon yield (Fig. 4).

The low hydrogen and oxygen index values (Fig.

5) indicate that both the Cretaceous and Jurassic

samples are, at best, gas-prone. These low values

may be a reflection of the initial character of the

sediment (i.e., poor organic preservation resulting

from deposition under oxic conditions and/or signifi-

cant terrestrial input) or an advanced level of thermal

maturity.

The maximum temperature of generation during

pyrolysis or Tmax data suggest the presence of a

regular thermal maturation profile (Fig. 6). The top

of the ‘‘oil-window’’ is positioned near 3 km. The

base of the ‘‘oil-window’’ is located near 4 km. The

Cretaceous section is immature, approaching the main

the stage of hydrocarbon generation. The Jurassic

Fig. 6. Composite thermal maturity (Tmax) profile.

0 4 8 12 16Total Generation Potential (S1+S2; mg HC/ g rock)

4500

4000

3500

3000

2500

2000

1500

Dep

th (

m)

Cre

tace

ou

sJu

rass

ic

Fig. 4. Composite total hydrocarbon generation potential (S1 + S2)

profile.


sequence is thermally mature to post-mature. The

cause for the rapid increase in Jurassic maturity is

not known but could be related to kinetic parameters

or the interval’s thermal history.

The gas chromatographic signature of extracted

bitumens (Fig. 7) supports this thermal maturity

Fig. 5. Modified van Krevlen-type diagram.

assessment. The shallow Cretaceous interval is repre-

sented by chromatograms with a bimodal character

and a strong odd predominance. The upper portion of

the Jurassic sequence displays a harmonic decrease in

n-alkane abundance, with increasing carbon number.

Detectable quantities of n-alkanes extend beyond

nC35. The chromatograms from the deeper Jurassic

also display a harmonic decrease in n-alkane abun-

dance, but the chromatogram is strongly skewed

toward the ‘‘light-ends’’.

These data (Fig. 8) indicate that the low hydrogen

indices associated with the Cretaceous samples repre-

sent the initial character of the sediment. In contrast,

the low hydrogen indices of the Jurassic sequence

appear to be the result of an advanced level of thermal

maturity. These samples may have had some liquid

generating potential prior to achieving their current

level of maturity.

Limited published data also indicate that signifi-

cantly more oil-prone and higher generation poten-

tials may exist within the Jurassic sequence (Kontor-

ovich et al., 1980; Nemchenko and Rovenskaya,

1987). Although the relative importance of marine

and terrigenous organic matter appears to differ

between the Cretaceous and Jurassic intervals, the

isotopic composition of the bitumens appears similar

(Fig. 9).


4. Oil/condensate character

The API gravity of the studied oils/condensates

ranges from 32j to 50j. No clear relationship was

observed between API gravity and depth (Fig. 10).

The lack of a clear relationship suggests that some-

thing other than thermal maturity (e.g., phase segre-

gation, alteration history, etc.) is controlling API

gravity.

The majority of the oils studied are classified as

naphthenic (Fig. 11). Naphthenic crude oils and con-

densates are rather unusual, representing only about

5% of the global population. They may, however, be

locally important. Naphthenic crudes form generally

Fig. 7. Representative C15 + saturated

through the biodegradation of paraffinic or paraf-

finic–naphthenic oils, although they may also be

source-related.

An examination of the ‘‘whole-oil’’ gas chromato-

grams reveals the presence of three general signatures

(Fig. 12). In one group (including Malygin #4, and

Malygin #16), the n-alkanes are truncated and virtu-

ally undetected beyond nC27. In the second group

(including Pyasedaysk #209, Bovanenkov #201,

Bovanenkov #203, Newport #167 and Bovanenkov

#144), a full suite of n-alkanes are present extending

beyond nC35. The third group (including Bovanenkov

#133, and Kharasavey #61) appears intermediate. The

longer chain n-alkanes are present but are much

fraction gas chromatograms.

Fig. 10. API gravity as a function of mean reservoir depth.Fig. 8. The relationship between the hydrogen index (HI) and Tmax

values.


depleted. Such a chromatographic signature is sug-

gestive of marine crudes that have experienced differ-

ent degrees of thermal stress or different degrees of

fractionation.

The C7 hydrocarbons (Fig. 13) indicate that only

three oils have been altered or transformed (Bovanen-

Fig. 9. Stable carbon isotope composition of the saturated and

aromatic hydrocarbon fractions.

kov #201 and 203 and Pyasedaysk #209). These data

also indicate an important terrestrial component was

present in the source.

The relationship between the pristane/nC17 and

phytane/nC18 ratios also suggests a mixed source rock

character (Fig. 14). Such a source rock system is often

observed in source rocks deposited under oxic con-

Fig. 11. Oil classification following the scheme of Tissot and Welte

(1984).

Fig. 12. Representative ‘‘whole-oil’’ gas chromatograms.


ditions and in more proximal marine settings. The

pristane/phytane ratios range from 1.00 to 2.23 (Fig.

15), with all but two samples having ratios less than

2.0. These ratios are suggestive of an open marine

depositional setting for the source rock.

An examination of the saturate fraction biomarker

compositions reveals differences in both the absolute

and relative concentrations (Fig. 16). These differ-

ences exist not only when oils from different fields are

examined, but also when oils from a single field are

examined. Although some of these differences may be

the result of differences in source rock character they

may also be a reflection of the nature of their alter-

ation and/or migration histories. Part of the differences

observed among the oils appears to be a reflection of

analytical error associated with low absolute bio-

marker abundances.

The ‘‘whole-oil’’ stable carbon isotope values

range from � 30.76xto � 28.25x(Fig. 17). This

range in values extends slightly beyond the limits

associated with a common origin. However, various

alteration processes may result in greater isotopic

fractionation.

Estimates of thermal maturity for the oils suggest

that the majority of the oils reflect thermal maturity

levels consistent with the main stage of hydrocarbon

generation (Table 1). Only two samples, Pyasedaysk

209 and Bovanenkov 203, display thermal maturity

levels consistent with thermal degradation or cracking

of petroleum (Table 1).

Differences among the available methylphenan-

threne indices suggest that phase segregation (or

evaporative fraction) has taken place. The nature

of these differences suggests that the degree of

fractionation varies within individual fields, which

is consistent with the findings of Chakhmakhchev et

al. (1990). Such an interpretation is also consistent

with the absolute biomarker concentrations and the

Fig. 13. (a,b) Gasoline-range hydrocarbon ternary diagrams. (a)

Transformed versus Primary C7 hydrocarbons). (b) Environment of

deposition as defined by the distribution and amount of C7

hydrocarbons.

Fig. 14. Phytane to nC18 versus pristane to nC17 illustrating both the

maturity of the oils and their possible organic matter origin.


relative abundance of tricyclic and pentacyclic ter-

panes.

Fig. 15. Histogram of pristane/phytane ratios.

5. Conclusions

The Cretaceous sequence appears to be largely gas-

prone. Its limited hydrocarbon generation potential is

a reflection of the rock’s depositional setting. In

contrast, the Jurassic appears to have been, at least

in part, originally oil-prone. The Jurassic sequence’s

currently limited generation potential is largely a

reflection of an advanced level of thermal maturity.

Limited published data suggest that some oil-prone

Jurassic material is present where the level of thermal

maturity is less advanced.

The main stage of liquid hydrocarbon generation

and expulsion occurs at a depth between 3 and 4 km.

The region’s liquid hydrocarbons are somewhat

unusual, being classified as naphthenic condensates.

No clear relationship exists between API gravity and

depth.

Fig. 16. End-member m/z 191 (terpane) mass fragmentograms.

Table 1

Estimated thermal maturity of oils based on the MPI-3 methyl-

phenanthrene index

Well Depth (m) Requ.,

MPI-3 (%)

Malygin #4 2776–2782 0.90

Bovanenkov #133 2857–2966 0.97

Pyasedaysk #209 2804–2808 1.42

Bovanenkov #201 3425–3443 0.98

Bovanenkov #203 3396–3405 1.44

Bovanenkov #133 3020–3010 0.97

Kharasavey #61 2420 0.99

Malygin #16 2734–2744 0.91


The oils appear to share a common source. This

source appears to be of marine nature, with some

terrestrial input.

Fig. 17. Histogram of ‘‘whole-oil’’ stable carbon isotope compo-

sitions.

Thermal stress does not appear to be the primary

cause for the elevated API gravities of the samples.

Phase segregation appears to be a more likely

formation mechanism. Oils within individual fields

appear to have undergone different degrees of

fractionation.

Acknowledgements

The authors would like to thank ChevronTexaco

for permission to present this work. Dr. A. Chakh-

makhchev provided samples for this study while

employed at Lukoil. Mike Darnell and Ewa Szymczyk

provided analytical assistance. Graphic assistance was

provided by the ChevronTexaco Graphics Art Depart-

ment. Our thanks go to two anonymous reviewers

whose critiques helped improve the original manu-

script.

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Aspects of hydrocarbon charge of the petroleum system of the Yamal Peninsula, West Siberia basin