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Aspects of hydrocarbon charge of the petroleum system of the Yamal Peninsula, West Siberia basin
International Journal of Coal Geology 54 (2003) 155 – 164 www.elsevier.com/locate/ijcoalgeo
Aspects of hydrocarbon charge of the petroleum system of the Yamal Peninsula, West Siberia basin B.J. Katz a, C.R. Robison a,*, A. Chakhmakhchev b a
ChevronTexaco Corp., 4800 Fournace Place, Bellaire, TX 77401-2324, USA b Houston, 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 gasprone (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 – * 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 thickens from south to north, going from about 2.0 km to a
0166-5162/03/$ - see front matter D 2003 Elsevier Science B.V. All rights reserved. doi:10.1016/S0166-5162(03)00029-6
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B.J. Katz et al. / International Journal of Coal Geology 54 (2003) 155–164
sent non-marine deposition (Kontorovich et al., 1975, 1980; Chakhmakhchev et al., 1994, 1995; Telnaes et al., 1994). This study examines the hydrocarbon charge components of the region’s petroleum system to better define exploration risks within the region.
2. Samples and analyses
Fig. 1. Index map of the Yamal Peninsula, Western Siberia, showing major oil and oil – condensate fields (after Chakhmakhchev et al., 1994).
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; Nemchenko and Rovenskaya, 1987; Peterson and Clarke, 1989; Sokolova et al., 1992; Telnaes et al., 1994; Moskvin et al., 1995). The Upper Jurassic organicrich Bazhanov Formation was deposited under this deep marine condition throughout the study area. The Lower Cretaceous (Megion, Tanopchin, KhantyMans, Pokur, and Kuznetsov Formations) all repre-
Forty samples from Malygin field, representing a composite Cretaceous and Jurassic sequence, were made available to this study. Each sample was geochemically characterized to determine source rock potential, product type, thermal maturity, and possible relationship with known oil/condensate accumulations. These analyses included the basic screening analyses (organic carbon and ‘‘Rock-Eval’’ pyrolysis) and more detailed characterization of the extracted bitumen (gas chromatography, gas chromatographymass spectrometry of the saturate fraction, and stable carbon isotope analysis). Ten oil samples from five fields were also examined. These samples were characterized using high performance liquid chromatography, ‘‘whole-oil’’ gas chromatography, gas chromatography-mass spectrometry 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 Cretaceous 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 representative of possible source rock candidates. Aboveaverage 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 hydrocarbon source. If thermally immature to mature, a rock must yield above-average (>2.5 mg HC/g rock)
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157
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).
Fig. 3. Composite organic carbon profile.
quantities of hydrocarbons to be considered a potential 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 significant 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
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Cretaceous
1500
2000
3000 Jurassic
Depth (m)
2500
3500
4000
4500 0
4
8
12
16
Total Generation Potential (S1+S2; mg HC/ g rock)
Fig. 4. Composite total hydrocarbon generation potential (S1 + S2) profile.
Fig. 6. Composite thermal maturity (Tmax) 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
assessment. The shallow Cretaceous interval is represented 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 abundance, 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 represent 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 significantly more oil-prone and higher generation potentials may exist within the Jurassic sequence (Kontorovich 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).
Fig. 5. Modified van Krevlen-type diagram.
B.J. Katz et al. / International Journal of Coal Geology 54 (2003) 155–164
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 something other than thermal maturity (e.g., phase segregation, alteration history, etc.) is controlling API gravity. The majority of the oils studied are classified as naphthenic (Fig. 11). Naphthenic crude oils and condensates are rather unusual, representing only about 5% of the global population. They may, however, be locally important. Naphthenic crudes form generally
159
through the biodegradation of paraffinic or paraffinic – naphthenic oils, although they may also be source-related. An examination of the ‘‘whole-oil’’ gas chromatograms reveals the presence of three general signatures (Fig. 12). In one group (including Malygin #4, and Malygin #16), the n-alkanes are truncated and virtually 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
Fig. 7. Representative C15 + saturated fraction gas chromatograms.
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Fig. 8. The relationship between the hydrogen index (HI) and Tmax values.
Fig. 10. API gravity as a function of mean reservoir depth.
depleted. Such a chromatographic signature is suggestive of marine crudes that have experienced different 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-
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. 9. Stable carbon isotope composition of the saturated and aromatic hydrocarbon fractions.
Fig. 11. Oil classification following the scheme of Tissot and Welte (1984).
B.J. Katz et al. / International Journal of Coal Geology 54 (2003) 155–164
161
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 differences 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 alteration and/or migration histories. Part of the differences observed among the oils appears to be a reflection of analytical error associated with low absolute biomarker 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 methylphenanthrene 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
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Fig. 14. Phytane to nC18 versus pristane to nC17 illustrating both the maturity of the oils and their possible organic matter origin.
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. 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.
relative abundance of tricyclic and pentacyclic terpanes.
5. Conclusions The Cretaceous sequence appears to be largely gasprone. 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
Fig. 15. Histogram of pristane/phytane ratios.
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Table 1 Estimated thermal maturity of oils based on the MPI-3 methylphenanthrene index Well
Depth (m)
Requ., MPI-3 (%)
Malygin #4 Bovanenkov #133 Pyasedaysk #209 Bovanenkov #201 Bovanenkov #203 Bovanenkov #133 Kharasavey #61 Malygin #16
2776 – 2782 2857 – 2966 2804 – 2808 3425 – 3443 3396 – 3405 3020 – 3010 2420 2734 – 2744
0.90 0.97 1.42 0.98 1.44 0.97 0.99 0.91
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
Fig. 16. End-member m/z 191 (terpane) mass fragmentograms.
The oils appear to share a common source. This source appears to be of marine nature, with some terrestrial input.
The authors would like to thank ChevronTexaco for permission to present this work. Dr. A. Chakhmakhchev 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 Department. Our thanks go to two anonymous reviewers whose critiques helped improve the original manuscript.
References
Fig. 17. Histogram of ‘‘whole-oil’’ stable carbon isotope compositions.
Chakhmakhchev, A.V., Vinogradova, T.L., Dashko, A.S., 1990. Prediction of phase-genetic types of hydrocarbon pools of the Yamal. Geol. Nefti Gaza 4, 4 – 6 (in Russian). Chakhmakhchev, A., Sampei, Y., Suzuki, N., 1994. Geochemical characteristics of oils and source rocks in the Yamal peninsula, West Siberia, Russia. Org. Geochem. 22, 311 – 322. Chakhmakhchev, A.V., Suzuki, N., Chakhmakhchev, V.A., et al., 1995. Biomarker hydrocarbons in evaluating Yamal petroleum prospects. Geochem. Int. 33, 16 – 27 (translated from Geokhimiya 5: 665 – 676; 1995). Kontorovich, A.Eh., Nesterov, I.I., Salmanov, S.K., et al., 1975. Petroleum Geology of Western Siberia. Nedra, Moscow (in Russian).
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Kontorovich, A.Eh., Bogorodakaya, L.I., Golyshev, S.I., 1980. Geochemical criteria for presence of oil and gas accumulations in Mesozoic formation sediments in North of West Siberia. Publ. SNIGGMS 283, 86 – 122 (in Russian). Moskvin, V.I., Melenevskiy, V.N., Fonin, A.N., 1995. Estimate of generating potential of organic matter of deeply subsided oil – gas source beds of Lower Jurassic of West Siberia. Pet. Geol. 31, 327 – 329. Nemchenko, N.N., Rovenskaya, A.S., 1987. Origin of gas – condensate fields and forecast of the phase state of hydrocarbons in the Northern part of West Siberia. Geol. Nefti Gaza 2, 25 – 31 (in Russian).
Peterson, J.A., Clarke, J.W., 1989. West Siberian Oil – Gas Province. U.S. Geol. Survey Open-file Report 89-112. United States Dept. of the Interior. Sokolova, I.M., Abryutina, N.N., Punanov, V.G., Petrov, Al.A., 1992. Chemical classification of naphthenic condensates and oils. In: Eckardt, C.B., et al. (Eds.), Advances in Organic Geochemistry 1991. Org. Geochem., vol. 19, pp. 1 – 11. Telnaes, N., Isaksen, G.H., Douglas, A.G., 1994. A geochemical investigation of samples from the Volgian Bazhenov Formation, Western Siberia, Russia. Org. Geochem. 21, 545 – 558. Tissot, B.P., Welte, D.H., 1984. Petroleum Formation and Occurrence. Springer, Berlin. 699 pp.
Aspects of hydrocarbon charge of the petroleum system of the Yamal Peninsula, West Siberia basin B.J. Katz a, C.R. Robison a,*, A. Chakhmakhchev b a
ChevronTexaco Corp., 4800 Fournace Place, Bellaire, TX 77401-2324, USA b Houston, 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 gasprone (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 – * 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 thickens from south to north, going from about 2.0 km to a
0166-5162/03/$ - see front matter D 2003 Elsevier Science B.V. All rights reserved. doi:10.1016/S0166-5162(03)00029-6
156
B.J. Katz et al. / International Journal of Coal Geology 54 (2003) 155–164
sent non-marine deposition (Kontorovich et al., 1975, 1980; Chakhmakhchev et al., 1994, 1995; Telnaes et al., 1994). This study examines the hydrocarbon charge components of the region’s petroleum system to better define exploration risks within the region.
2. Samples and analyses
Fig. 1. Index map of the Yamal Peninsula, Western Siberia, showing major oil and oil – condensate fields (after Chakhmakhchev et al., 1994).
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; Nemchenko and Rovenskaya, 1987; Peterson and Clarke, 1989; Sokolova et al., 1992; Telnaes et al., 1994; Moskvin et al., 1995). The Upper Jurassic organicrich Bazhanov Formation was deposited under this deep marine condition throughout the study area. The Lower Cretaceous (Megion, Tanopchin, KhantyMans, Pokur, and Kuznetsov Formations) all repre-
Forty samples from Malygin field, representing a composite Cretaceous and Jurassic sequence, were made available to this study. Each sample was geochemically characterized to determine source rock potential, product type, thermal maturity, and possible relationship with known oil/condensate accumulations. These analyses included the basic screening analyses (organic carbon and ‘‘Rock-Eval’’ pyrolysis) and more detailed characterization of the extracted bitumen (gas chromatography, gas chromatographymass spectrometry of the saturate fraction, and stable carbon isotope analysis). Ten oil samples from five fields were also examined. These samples were characterized using high performance liquid chromatography, ‘‘whole-oil’’ gas chromatography, gas chromatography-mass spectrometry 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 Cretaceous 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 representative of possible source rock candidates. Aboveaverage 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 hydrocarbon source. If thermally immature to mature, a rock must yield above-average (>2.5 mg HC/g rock)
B.J. Katz et al. / International Journal of Coal Geology 54 (2003) 155–164
157
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).
Fig. 3. Composite organic carbon profile.
quantities of hydrocarbons to be considered a potential 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 significant 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
158
B.J. Katz et al. / International Journal of Coal Geology 54 (2003) 155–164
Cretaceous
1500
2000
3000 Jurassic
Depth (m)
2500
3500
4000
4500 0
4
8
12
16
Total Generation Potential (S1+S2; mg HC/ g rock)
Fig. 4. Composite total hydrocarbon generation potential (S1 + S2) profile.
Fig. 6. Composite thermal maturity (Tmax) 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
assessment. The shallow Cretaceous interval is represented 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 abundance, 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 represent 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 significantly more oil-prone and higher generation potentials may exist within the Jurassic sequence (Kontorovich 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).
Fig. 5. Modified van Krevlen-type diagram.
B.J. Katz et al. / International Journal of Coal Geology 54 (2003) 155–164
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 something other than thermal maturity (e.g., phase segregation, alteration history, etc.) is controlling API gravity. The majority of the oils studied are classified as naphthenic (Fig. 11). Naphthenic crude oils and condensates are rather unusual, representing only about 5% of the global population. They may, however, be locally important. Naphthenic crudes form generally
159
through the biodegradation of paraffinic or paraffinic – naphthenic oils, although they may also be source-related. An examination of the ‘‘whole-oil’’ gas chromatograms reveals the presence of three general signatures (Fig. 12). In one group (including Malygin #4, and Malygin #16), the n-alkanes are truncated and virtually 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
Fig. 7. Representative C15 + saturated fraction gas chromatograms.
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B.J. Katz et al. / International Journal of Coal Geology 54 (2003) 155–164
Fig. 8. The relationship between the hydrogen index (HI) and Tmax values.
Fig. 10. API gravity as a function of mean reservoir depth.
depleted. Such a chromatographic signature is suggestive of marine crudes that have experienced different 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-
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. 9. Stable carbon isotope composition of the saturated and aromatic hydrocarbon fractions.
Fig. 11. Oil classification following the scheme of Tissot and Welte (1984).
B.J. Katz et al. / International Journal of Coal Geology 54 (2003) 155–164
161
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 differences 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 alteration and/or migration histories. Part of the differences observed among the oils appears to be a reflection of analytical error associated with low absolute biomarker 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 methylphenanthrene 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
162
B.J. Katz et al. / International Journal of Coal Geology 54 (2003) 155–164
Fig. 14. Phytane to nC18 versus pristane to nC17 illustrating both the maturity of the oils and their possible organic matter origin.
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. 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.
relative abundance of tricyclic and pentacyclic terpanes.
5. Conclusions The Cretaceous sequence appears to be largely gasprone. 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
Fig. 15. Histogram of pristane/phytane ratios.
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163
Table 1 Estimated thermal maturity of oils based on the MPI-3 methylphenanthrene index Well
Depth (m)
Requ., MPI-3 (%)
Malygin #4 Bovanenkov #133 Pyasedaysk #209 Bovanenkov #201 Bovanenkov #203 Bovanenkov #133 Kharasavey #61 Malygin #16
2776 – 2782 2857 – 2966 2804 – 2808 3425 – 3443 3396 – 3405 3020 – 3010 2420 2734 – 2744
0.90 0.97 1.42 0.98 1.44 0.97 0.99 0.91
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
Fig. 16. End-member m/z 191 (terpane) mass fragmentograms.
The oils appear to share a common source. This source appears to be of marine nature, with some terrestrial input.
The authors would like to thank ChevronTexaco for permission to present this work. Dr. A. Chakhmakhchev 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 Department. Our thanks go to two anonymous reviewers whose critiques helped improve the original manuscript.
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Fig. 17. Histogram of ‘‘whole-oil’’ stable carbon isotope compositions.
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