Tracking Changes in Thermal Oil Maturity and Organofacies

Energy Fuels 2010, 24, 550–556 Published on Web 11/13/2009

: DOI:10.1021/ef900900z

Tracking Changes in Thermal Oil Maturity and Organofacies Heterogeneities Using Alkylthiophene Distributions in Asphaltene Pyrolysates Eric Lehne,* Volker Dieckmann,† and Brian Horsfield Helmholtz Centre Potsdam, GFZ German Research Centre for Geosciences, D-14473 Potsdam, Germany †Present address: Shell International and Production, EPT-RXD, 2288 GS Rijswijk, The Netherlands. Received August 18, 2009. Revised Manuscript Received October 29, 2009

Alkylthiophenes in source rock pyrolysates are used to estimate the relative content of organic sulfur with respect to variations in organofacies and maturity. For the present study, we investigated the applicability of alkylthiophene distributions in oil asphaltene pyrolysates for oil-source and oil-oil correlations. The study shows that the distribution of thiophenic moieties in pyrolysates of oil asphaltenes can be used to distinguish between oil subfamilies and to study a source-specific genetic relationship, although asphaltene pyrolysates show much lower amounts of organic sulfur compounds than found in related whole rock pyrolysates. Further, certain distributions among alkylthiophenes allow us to estimate the relative thermal maturity of oils on the basis of asphaltene pyrolysates. This provides a tool for reconstructing original organofacies and oil maturity characteristics of heavily altered oils when biomarkers have been degraded. Asphaltenes from type II-S and type II petroleum systems show remarkable differences in the evolutional trend of increasing thermal maturity compared to their related source rocks. An explanation might be that asphaltenes from reactive source rocks are generated at a much earlier stage of conversion during oil generation than asphaltenes formed from marine type II organic matter.

sulfurization process or biogenic inputs originally present at deposition.1,4-14 Alkylated thiophenes are the major sulfur-containing moieties upon pyrolysis of kerogens and asphaltenes. Therefore, thiophenic moieties in source rock pyrolysates are routinely used to estimate the relative content of organic sulfur with respect to variations in organofacies and thermal oil maturity.1,7-9,15 Appropriate correlations of oil maturity and organofacies based on alkylthiophenes in asphaltene pyrolysates are still missing. However, these structural moieties in asphaltene pyrolysates provide a potential tool for oil-oil and oil-source correlations. Because alkylthiophenes are ubiquitous in nearly all asphaltene pyrolysates in abundant concentrations, they may be of use for a broad range of petroleum systems. Previously, we have shown that pyrolysates of asphaltenes from different petroleum systems show lower concentrations of alkylthiophenes than pyrolysates of related whole rocks.16,17 In this study, we compare the distribution of alkylthiophenes in whole rock and asphaltene pyrolysates of samples from southern Italy and the Duvernay Formation in Canada. We will show that certain distributions of alkylthiophene compounds upon pyrolysis of oil asphaltenes can be

1. Introduction Under anaerobic conditions, sulfate-reducing bacteria reduce sulfate to hydrogen sulfide using organic compounds or hydrogen as an electron donor. The hydrogen sulfide formed is then converted into organic sulfur compounds, such as in functionalized lipids or carbohydrates during early diagenesis.1,2 Especially in evaporitic environments, hydrogen sulfide generated by sulfate-reducing bacteria binds to the organic molecules, increasing their potential for preservation.3 The composition of the formed organic sulfur molecules has been studied in various previous works in terms of the *To whom correspondence should be addressed. Present address: Schlumberger, DBR Technology Center, Edmonton, Alberta T6N 1M9, Canada. Telephone: þ1-780-463-8638. Fax: þ1-780-450-1668. E-mail: [email protected]. (1) Sinninghe Damst
e, J. S.; Eglinton, T. I.; de Leeuw, J. W.; Schenck, P. A. Geochim. Cosmochim. Acta 1989, 53, 873–889. (2) van Kaam-Peters, H. M. E.; Schouten, S.; K€ oster, J.; Sinninghe Damst
e, J. S. Geochim. Cosmochim. Acta 1998, 62, 3259–3284. (3) Sinninghe Damst
e, J. S.; Eglinton, T. I.; Rijpstra, W. I. C.; de Leeuw, J. W. Geochemistry of Sulfur in Fossil Fuels; American Chemical Society: Washington, D.C., 1990; Vol. 429, pp 468-528. (4) Sinninghe Damst
e, J. S.; Kock-van Dalen, A. C.; de Leeuw, J. W.; Schenck, P. A. J. Chromatogr. 1990, 435, 435–452. (5) Sinninghe Damst
e, J. S.; de las Heras, F. X. C.; van Bergen, P. F.; de Leeuw, J. W. Geochim. Cosmochim. Acta 1993, 57, 389–415. (6) Sinninghe Damst
e, J. S.; Kohnen, M. E. L.; Horsfield, B. Org. Geochem. 1998, 29, 1891–1903. (7) de Leeuw, J. W.; Sinninghe Damst
e, J. S. Geochemistry of Sulfur in Fossil Fuels; American Chemical Society: Washington, D.C., 1990; Vol. 429, pp 417-443. (8) Eglinton, T. I.; Sinninghe Damst
e, J. S.; Kohnen, M. E. L.; de Leeuw, J. W. Fuel 1990, 69, 1394–1404. (9) Eglinton, T. I.; Sinninghe Damst
e, J. S.; Kohnen, M. E. L.; de Leeuw, J. W.; Larter, S. R.; Patience, R. L. Geochemistry of Sulfur in Fossil Fuels; American Chemical Society: Washington, D.C., 1990; Vol. 429, pp 529-565. (10) Kohnen, M. E. L.; Sinninghe Damst
e, J. S.; de Leeuw, J. W. Nature 1991, 349, 775–778. r 2009 American Chemical Society

(11) Kohnen, M. E. L.; Sinninghe Damst
e, J. S.; Baas, M.; van Dalen, A. C. K.; de Leeuw, J. W. Geochim. Cosmochim. Acta 1993, 57, 2515– 2528. (12) Stankiewicz, B. A.; Kruge, M. A.; Mastalerz, M.; Salmon, G. L. Org. Geochem. 1996, 24, 495–509. (13) de las Heras, F. X.; Grimalt, J. O.; Lopez, J. F.; Albaig
es, J.; Sinninghe Damst
e, J. S.; Schouten, S.; de Leeuw, J. W. Org. Geochem. 1997, 27, 41–63. (14) Russel, M.; Grimalt, J. O.; Hartgers, W. A.; Taberner, C.; Rouchy, J. M. Org. Geochem. 1997, 26, 605–625. (15) di Primio, R.; Horsfield, B. Org. Geochem. 1996, 24, 999–1016. (16) Lehne, E.; Dieckmann, V. Org. Geochem. 2007, 38, 1657–1679. (17) Lehne, E.; Dieckmann, V. Fuel 2007, 86, 887–901.

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used to determine either the relative thermal maturity or organofacies variations of related oils. This has an important aspect for oil-source correlations using oil asphaltenes and its related characterization of petroleum composition in petroleum system analysis. In addition, it allows for the reconstruction of original oil maturity and organofacies characteristics of severely altered oils, even when biomarkers in oils have been changed by the alteration process.

However, the maturity of the levels of thermal maturity. organic-rich rocks from southern Italy varies a great deal from area to area and is related to the geodynamic evolutions during Tertiary tectonics.23,34 Source rocks often reached maturity only when buried under thick foredeep sediments and when involved in compactional tectonics.29 The deposition of the Devonian Duvernay Formation in western Canada occurred during the Laramide orogeny as the result of subsidence.35,36 The formation comprises two principal lithofacies: a limestone with varying degrees of bioturbation, indicating relatively oxygenated conditions, and organicrich laminated mudstones deposited in deepwater euxinic conditions.36-40 The marine source rock organic matter (type II kerogen) shows slight organofacies variations.38,40 The Duvernay Formation occurs widely throughout Alberta, with increasing maturity from the northeast to the southwest. Large areas of the Duvernay Formation are oil-prone, but light oils and gas were also generated at high maturity. The petroleum reservoirs along the Rimbey-Meadowbrook reef tend to belong to the Late Devonian Woodbend Group. In the eastern region of the Rimbey-Meadowbrook reef (East Shale basin), the Duvernay Formation overlies platform carbonates of the Cooking Lake Formation with minor discontinuity and is surrounded by lower Leduc Formation reefs. In the West Shale basin, the Duvernay Formation conformably overlies rocks of the Majeau Lake Member, which predates reef growth.36

2. Petroleum Geology For the present study, we investigated source rocks, source rock bitumen asphaltenes, and oil asphaltenes from an oil field of southern Italy and from the Duvernay Formation in the Western Canada Sedimentary Basin (WCSB). Most crude oil accumulations in southern Italy are sourced from Upper Triassic formations.18 The Norian and Rhaetian of southern Italy were characterized by the occurrence of carbonate platforms, which in turn might have been bridged with depositional platforms in northern Italy by the Abruzzo Platform, and later separated by hemipelagic troughs.19 In these troughs, deep-sea pelagic facies were deposited, with the uppermost Triassic often represented by radiolarites. The Triassic carbonate platform successions of southern Italy are normally organic-lean and dominated by shallowing-up peritidal cycles.18 During the Late Triassic, important source facies were deposited in the form of organic-rich “lenses” in different portions of the platform and lithofacies vary often where clays and carbonates alternate at different scales.18,20 These depositional variations result in different oil types, for example, mainly shaly or carbonate sourced,21 and oils sourced from organofacies of variable hypersaline conditions.18,22 The oils generated from these facies intervals contain significant amounts of sulfur and are generally thought to be thermally immature.15,23,24 Organic-rich, carbonate-evaporitic, and carbonate-siliceous rocks worldwide are the sources of large quantities of heavy-oil deposits.15,25-32 It is generally assumed that high-viscosity heavy oils form at low

3. Experimental Section 3.1. Sample Set. The samples from southern Italy used in the present study have been described with relevant screening data previously by Lehne and Dieckmann.16 The studied source rocks comprise shales and laminated mudstones with organic matter originating from microbial mats in a hypersaline carbonate lagoon.15,16 The source rocks consist of 16 samples from cores in different wells. The shale samples contain type II-S or type I-S organic matter, and they show high total organic carbon (TOC) values ranging from 2.9 to 11.8% TOC and hydrogen indices (HI) ranging from 613 to 909 mg of HC/g of TOC. The mudstones are connected to type II-S organic matter. They have lower TOC values, which range between 0.4 and 1.4%, and HI values ranging from 471 to 691 mg of HC/g of TOC. In addition, 12 oils from southern Italy with American Petroleum Institute (API) gravities ranging from 3° to 33° have been studied.16 These are heavy crudes with high sulfur content (up to 7.2 wt %) and high proportions of polar and asphaltene fractions (53-86% of the C15þ fraction). The sample set includes two heavy biodegraded oils with 3° and 10° API.

(18) Stefani, M. M.; Burchell, M. T. Generation, Accumulation and Production of Europe’s Hydrocarbons, EAPG Special Publication; Springer: Berlin, Germany, 1993; pp 169-178. (19) di Stefano, P. Boll. Soc. Geol. Ital. 1990, 109, 21–37. (20) Brosse, E.; Riva, A.; Santucci, S.; Bernon, M.; Loreau, J. P.; Frixa, A.; Laggoun, D. F. Advances in organic geochemistry 1989. Proceedings of the 14th International Meeting on Organic Geochemistry; Part II, Molecular Geochemistry, 1990; Vol. 16, pp 715-734. (21) Ruvo, L.; Aldegheri, A.; Galimberti, R.; Nembrini, E.; Rossi, L.; Ruspi, R. Pet. Geosci. 2003, 9, 265–276. (22) Peterson, J. A. U.S. Geological Survey Open File Report, 1994; pp 94-166. (23) Novelli, L.; Welte, D. H.; Mattavelli, L.; Yalcin, M. N.; Cinelli, D.; Schmitt, K. J. Org. Geochem. 1988, 13, 153–164. (24) Moretti, I.; Brosse, E.; Delahaye, S.; Roure, F.; Mattavelli, L. Book of abstracts. AAPG Annual Convention, Tulsa, OK; 1990; p 725. (25) Zumberge, J. E. In Petroleum Geochemistry and Source Rock Potential of Carbonate Rocks; Palacas, J. G., Ed.; AAPG Studies in Geology: Tulsa, OK, 1984; pp 127-134. (26) Powell, T. G. In Petroleum Geochemistry and Source Rock Potential of Carbonate Rocks; Palacas, J. G., Ed.; AAPG Studies in Geology: Tulsa, OK, 1984; pp 45-62. (27) Tannenbaum, E.; Aizenshtat, Z. Org. Geochem. 1985, 8, 181–192. (28) Riboulleau, A.; Derenne, S.; Sarret, G.; Largeau, C.; Baudin, F.; Connan, J. Org. Geochem. 2000, 31, 1641–1661. (29) Mattavelli, L.; Pieri, M.; Groppi, G. Mar. Pet. Geol. 1993, 10, 410–425. (30) Khavari-Khorasani, G.; Dolson, J. C.; Michelsen, J. K. Org. Geochem. 1998, 29, 255–282. (31) Hetenyi, M.; Brukner-Wein, A.; Sajgo, C.; Haas, J.; Hamor-Vido, M.; Szanto, Z.; Toth, M. Org. Geochem. 2002, 33, 1571–1591. (32) Hetenyi, M.; Sajgo, C.; Veto, I.; Brukner-Wein, A.; Szanto, Z. Org. Geochem. 2004, 35, 1201–1219.

(33) Baskin, D. K.; Peters, K. E. Bull. Am. Assoc. Pet. Geol. 1992, 76, 1–13. (34) Lentini, F.; Catalano, S.; Carbone, S. Pet. Geosci. 1996, 2, 333– 342. (35) Deroo, G.; Powell, T. G.; Tissot, B.; McCrossen, R. G. Bull. Geol. Surv. Can. 1977, 262. (36) Creaney, S.; Allan, J. Hydrocarbon Generation and Migration in the Western Canada Sedimentary Basin. Classic Petroleum Provinces; Geological Society of London: London, U.K., 1990; pp 189-202. (37) Requejo, A. G.; Allan, J.; Creaney, S.; Gray, N. R.; Cole, K. S. Advances in organic geochemistry 1991. Proceedings of the 15th International Meeting on Organic Geochemistry; Part I, Advances and Applications in Energy and the Natural Environment, 1992; Vol. 19, pp 245-264. (38) Chow, N.; Wendte, J.; Stasiuk, L. D. Bull. Can. Pet. Geol. 1995, 43, 433–460. (39) Li, M.; Yao, H.; Stasiuk, L. D.; Fowler, M. G.; Larter, S. R. Org. Geochem. 1997, 26, 731–744. (40) Li, M.; Yao, H.; Fowler, M. G.; Stasiuk, L. D. Advances in organic geochemistry 1997. Proceedings of the 18th International Meeting on Organic Geochemistry; Part I, Petroleum Geochemistry, 1998; Vol. 29, pp 163-182.

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The samples from the Duvernay Formation have been described with relevant screening data previously by Lehne and Dieckmann.17 For the study on the Duvernay Formation source rocks, we used a series of 33 core samples from a number of different wells containing variations in facies types. The TOC of studied rocks varies from 0.61 to 14.8%. HI values for these source rocks range from 631 to 14 mg of HC/g of TOC. Changing HI values are associated with an increase in thermal maturity indicated by Tmax values, which range from 414 to 465 °C. Investigated Duvernay oils consists of five black oils with API gravities from 36° to 44°. The content of the polar fraction of the crude oils varies between 8 and 23% based on medium-pressure liquid chromatography (MPLC) analysis.17 3.2. Analytical Methods. 3.2.1. Asphaltene Precipitation. Asphaltenes were separated from crude oils by precipitation with n-hexane. A 60-fold excess of n-hexane was added to 10 mL of crude oil dissolved in 2 mL of dichloromethane. The mixture was stirred for 5 min in an ultrasonic bath and allowed to settle for 48 h. Precipitated asphaltenes were vacuum-filtered and washed with n-hexane. After drying under a gentle stream of nitrogen gas, the asphaltenes were weighed and further purified in a second and third step by reprecipitation with n-hexane from the solution in dichloromethane. Source rocks were powdered and extracted for 24 h by Soxhlet (with a mixture of dichloromethane and ethanol in ratio of 99:1) to yield bitumen. After the bitumen was dried under nitrogen gas, it was redissolved in 1 mL of dichloromethane and asphaltenes were precipitated with a 60-fold excess of n-hexane as described above. 3.2.2. Open-System Pyrolysis-Gas Chromatography (GC) and GC-Mass Spectrometry (MS). Asphaltenes were mixed with powdered thermally precleaned quartz sand in the weight ratio of 1:5, and 5 mg of this mixture was weighed in the glass capillary. Products released over a temperature range of up to 300 °C were vented to remove volatile or occluded compounds. Pyrolysis products were released over the temperature range of 300-0 °C (40 °C/min) and collected in a liquid nitrogen-cooled trap at -196 °C. By heating the trap to 300 °C, the products were released onto a dimethylpolysiloxane-coated column (0.52 μm film thickness) fitted into an Agilent GC 6890A gas chromatograph equipped with a flame ionization detector (FID) and measured online by GC. Helium was employed as the carrier gas, regulated at 30 mL/min with a split ratio of 1:15. n-Butane was used as a standard to quantify generated products. Identification of peaks based on reference chromatograms was performed using Agilent ChemStation software. GC-MS was performed on selected samples of asphaltene pyrolysates. The pyrolysis products were measured by a Thermo Finnigan Trace GC with Trace DSQ-MS (electron energy of 70 eV) equipped with a dimethylpolysiloxane-coated column of 0.25 μm film thickness. Peaks were integrated from the total ion current trace using the software Xcalibur (version 1.3) by Thermo Finnigan.

Figure 1. (Top) Variation of the gammacerane index with increasing biogenic input of nonmarine strata for oils from southern Italy. (Bottom) Alkylthiophene concentration of oil asphaltene pyrolysates versus the gammacerane index of related crude oils.

studied oils can be divided into two families on the basis of their gammacerane index (Figure 1). The heavy oils associated with a metasaline source depositional environment show low gammacerane indices of 0.05-0.12. Those related to a more hypersaline source depositional environment show values between 0.30-0.36 for the gammacerane index. Besides, from the top of Figure 1, it is obvious that the gammacerane index increases with a decreasing impact of nonmarine strata, exemplarily shown here as % RRRC29 sterane. The varying salinity of the depositional environments also influence the abundance of alkylthiophenes in pyrolysates of asphaltenes isolated from the heavy oils (bottom of Figure 1). Pyrolysates of asphaltenes from the low-gammacerane oils show lower yields of these alkylthiophenes than those from the crude oils associated with a more hypersaline environment. Organofacies characteristics have a large impact on the distribution of alkylthiophenes upon pyrolysis, as noted in earlier studies. Sinninghe Damst
e et al.3 explained the generation of alkylthiophenes by pyrolysis depending upon the type of bond between the thiophene structure and kerogens and, hence, the biological precursor of individual thiophenes. According to the authors, precursor molecules with a linear carbon skeleton derived from sulfurized normal fatty acids or monosaccharides yield upon pyrolysis mainly 2-methylthiophene or 2,5-dimethylthiophene. The isoprenoid thiophenes and thiophenes with branched carbon

4. Results and Discussion 4.1. Abundance of Alkylthiophenes and Their Paleoenvironmental Implication. Sulfur-rich source rocks from southern Italy show variations in lithofacies (mainly shales and mudstones), as well as the occurrence of type I-S and type IIS organic matter.15,16 As mentioned before, within the regional context, the organic matter was deposited in “lenses” in different portions of the carbonate platform. These organic-rich lenses are characterized by variations of depositional environments and, hence, by different assemblages of organisms, resulting in remarkable differences in organofacies characteristics for kerogen pyrolysates from the same petroleum system.16 Similarly, the organofacies characteristics of crude oils from southern Italy show variations. In substance, the 552

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skeletons, which originated from isoprenoid precursor molecules, will probably form 3-methylthiophene, 2,3- or 2,4-dimethylthiophene, and trimethylthiophenes upon pyrolysis. The steroidal carbon skeletons from steroids of higher plants and algae form thiophenes with more complex side chains found in pyrolysates. For example, pyrolysates of kerogens from the North Sea, such as the Kimmeridge Clay and Draupne Formation, are dominated by 2-methylthiophene, 2,5-dimethylthiophene, and 2-ethyl-5-methylthiophene.41,42 In contrast, pyrolysates of the Permian Phosphoria Shale of the western United States are particularly rich in isoprenoid thiophenes.1 Similar, kerogen pyrolysates from the Devonian Duvernay Formation in Canada show comparatively lower concentrations of thiophenes related to precursors with a linear carbon skeleton but relatively higher yields of 2,4- and 2, 3-dimethylthiophenes linked to branched isomer precursors.17 This makes clear that the distribution of certain alkylthiophenes in pyrolysates reflects the distribution of precursor molecules in the organic matter and, therefore, also the biological input found in kerogens and asphaltenes. 4.2. Distribution of Alkylthiophenes in Whole Rocks and Asphaltenes from Southern Italy. 4.2.1. Organofacies Indication. Pyrolysates from open-system pyrolysis experiments of whole rock and asphaltene samples from southern Italy are dominated by thiophenes, such as 2-methylthiophene and 2,5-dimethylthiophene, linked to precursors with a linear carbon skeleton. Also, whole rock and asphaltene pyrolysates are enriched in 2,3,5-trimethylthiophene, which exceed the concentrations of adjacent alkane/-ene C9 and C10 doublets. Several further 2,5-dialkylthiophenes, such as 2-ethyl-5-methylthiophene, 2-methyl-5-propylthiophene, and 2-ethyl-5-propylthiophene, are also apparent in enhanced concentrations. The co-occurrence of these thiophenes in relatively high abundance points to an unusual biogenic precursor. Although the source rocks and oils indicate stronger organofacies variations,16 the distribution of certain alkylthiophenes in whole rock and asphaltene pyrolysates show remarkable similarities. This indicates that the biogenic precursors of certain alkylthiophenes in pyrolysates are the same even for those source rocks of varying organofacies and depositional environments related to oils from the petroleum system in southern Italy. Figure 2 shows the ternary diagram using 2-ethyl5-methylthiophene, 2-methyl-5-propylthiophene, and 2-ethyl5-propylthiophene. Most whole rock pyrolysates plot along a linear trend of increasing proportions of 2-ethyl-5-propylthiophene. Oil asphaltene pyrolysates show similar 2, 5-dialkylthiophene distribution and similar trend and, thus, an excellent match to the whole rock pyrolysates. Previously, we showed that the oil-source correlation based on biomarkers from oils and source rock bitumen could not be performed in a straightforward manner for the samples from southern Italy.16 For the samples, the diagram in Figure 2, however, can be used to correlate oils based on asphaltene pyrolysate composition with related source rocks from a very heterogeneous petroleum system. In contrast, bitumen asphaltene pyrolysates show generally higher proportions of

Figure 2. Ternary diagram using 2-ethyl-5-methylthiophene, 2-methyl-5-propylthiophene, and 2-ethyl-5-propylthiophene for pyrolysates of whole rock, bitumen asphaltenes, and oil asphaltenes from southern Italy.

Figure 3. Variation of the 2,5-dialkylthiophene ratio [2-ethyl-5propylthiophene/(2-ethyl-5-propyl- þ 2-ethyl-5-methy- þ 2-methyl5-propylthiophene)] of oil asphaltene pyrolysates with increasing facies variation of related crude oils.

2-ethyl-5-methylthiophene, and their 2,5-dialkylthiophene distribution does not reflect those of oil asphaltenes and whole rocks. The observed trends for whole rock and oil asphaltene pyrolysates are related to changes in organofacies, as shown for oil asphaltenes in Figure 3. Here, the 2, 5-dialkylthiophene ratio of asphaltene pyrolysates is plotted versus the % RRRC29 sterane of related crude oils. The 2,5-dialkylthiophene ratio was calculated using the ratio of 2-ethyl-5-propylthiophene/(2-ethyl-5-propyl- þ 2-ethyl-5methy- þ 2-methyl-5-propylthiophene). First, in this diagram, asphaltenes of both oil families are distinguishable by higher values of a calculated 2,5-alkylthiophene ratio for asphaltenes from the low-gammacerane oils (oil family B). Second, asphaltene pyrolysates of both oil families show a decreasing 2,5-dialkylthiophene ratio with an increasing input of nonmarine strata. This indicates that the biogenic precursor of 2-ethyl-5-propylthiophene is rather associated

(41) Eglinton, T. I.; Sinninghe Damst
e, J. S.; Pool, W.; de Leeuw, J. W.; Eijkel, G.; Boon, J. J. Geochim. Cosmochim. Acta 1992, 56, 1545– 1560. (42) Keym, M.; Dieckmann, V.; Horsfield, B.; Erdmann, M.; Galimberti, R.; Kua, L.-C.; Leith, L.; Podlaha, O. Org. Geochem. 2006, 37, 220–243.

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Figure 4. Ternary diagram using 2-methylthiophene, 3-methylthiophene, and 2,5-dimethylthiophene for pyrolysates of whole rock, bitumen asphaltenes, and oil asphaltenes from southern Italy.

with a marine environment. This example also shows that the distribution of alkylthiophenes with the same arrangements of side chains has the potential for organofacies correlation as well as the potential to link oils to their generic sources. 4.2.2. Thermal Maturity Indication. Figure 4 shows ternary diagrams using 2-methylthiophene, 3-methylthiophene, and 2,5-dimethylthiophene for pyrolysates of whole rocks, bitumen asphaltenes, and oil asphaltenes. The whole rock pyrolysates show higher proportions of 2-methylthiophene than pyrolysates of oil and bitumen asphaltenes. In addition, the whole rock pyrolysates show a nice trend, which can be related to the HI based on Rock-Eval data (top of Figure 5). With a decreasing HI for the whole rocks, the proportion of 2,5-dimethylthiophene first starts to decrease, while at the same time, the proportion of 3-methylthiophene continuously increases. The sample with the highest HI value of 909 mg of HC/g of TOC (G000654) displays with less than 10% of the lowest proportion of 3-methylthiophene. The sample G000646 shows a HI of 471 mg of HC/g of TOC, and in this diagram, the content of 3-methylthiophene is about 30% for this sample. Previous studies by Eglinton et al.9 have reported decreasing concentrations of 2-methylthiophene versus 3-methylthiophene, with increasing maturity pointing to increasing proportions of branched versus linear isomers during maturation. However, as seen from Figure 4, the ratio of 2-methylthiophene/3-methylthiophene of whole rock pyrolysates does not reflect a linear trend for thermal maturity, especially not for the least mature source rocks. Such a linear trend as a maturity parameter can, however, be built using the proportion of 3-methylthiophene within the sum of 3methyl-, 2-methyl-, and 2,5-dimethylthiophene (Figure 5). The ratio of 3-methylthiophene/(3-methyl- þ 2-methyl- þ 2,5-dimethylthiophene) is referred to here as the 3-methylthiophene ratio in Figure 5. Asphaltene pyrolysates show a similar distribution of these alkylthiophenes compared to least mature source rocks. This supports the assumption that oil and asphaltene generation occurs at very low levels of thermal stress for type II-S organic matter.15,33 With increasing maturity, the pyrolysates of oil asphaltenes also show increasing proportions of 3-methylthiophene, but the maturity trend for these asphaltene pyrolysates differs with that of whole rock pyrolysates in the ternary diagram of

Figure 5. 3-Methylthiophene ratio [3-methylthiophene/(3-methylþ 2-methyl- þ 2,5-dimethylthiophene)] (top) versus HI for whole rock pyrolysates and (bottom) versus API for oil asphaltene pyrolysates.

Figure 4. However, the 3-methylthiophene ratio versus the API gravity of related oils shows a near exponential trend for asphaltenes from non-altered heavy oils (bottom of Figure 5). The values of this ratio for asphaltenes from the two heavily biodegraded oils can thus be used to predict the former API gravity of the original, nondegraded oils. On the basis of the 3-methylthiophene ratio, the strongly biodegraded oils in this sample set point to original APIs of 18° (10° biodegraded) and 23° (3° biodegraded). The distribution of alkylthiophenes in pyrolysates of the bitumen asphaltenes does not correlate with thermal maturity. However, we later see that bitumen asphaltenes from marine type II organic matter show a similar maturity trend as related to whole rocks. It is thus imaginable that type II-S bitumen asphaltenes lack information on maturity differences because of their early generation from reactive source rocks. Because type II-S oil asphaltenes show a correlation of the distribution of alkylthiophenes with increasing maturity, this would mean that oil and bitumen asphaltene generation would probably not occur syngenetically from type II-S kerogens. 4.3. Distribution of Alkylthiophenes in Whole Rocks and Asphaltenes from the Duvernay Formation (WCSB). The distribution of alkylthiophenes in whole rock and asphaltene 554

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Figure 6. Ternary diagram using 2-methylthiophene, 3-methylthiophene, and 2,5-dimethylthiophene for pyrolysates of whole rock, bitumen asphaltenes, and oil asphaltenes from the Duvernay Formation (WCSB).

pyrolysates from the Duvernay Formation differs from the Italian samples. Duvernay source rock and asphaltene pyrolysates show significantly lower proportions of 2-methylthiophene and 2,5-dimethylthiophene, and 2-ethyl-5methylthiophene is the only 2,5-dialkylthiophene occurring in these pyrolysates. The distribution of the alkylthiophenes in Figure 6, thus, differs from the diagram for the Italian samples (Figure 4). Similar to the Italian source rocks, the Duvernay source rocks first show a decrease of 2,5-dimethylthiophene followed by a decrease of 2-methylthiophene content with increasing thermal maturity. This is also illustrated on the top of Figure 7, showing an increasing 3-methylthiophene ratio with increasing Tmax for studied source rocks. In addition, Duvernay source rock asphaltene pyrolysates show higher ratios of 2-methyl- versus 3-methylthiophene than related whole rock pyrolysates. In clear contrast to the Italian sample set, the Duvernay source rock asphaltenes show a trend of the 3-methylthiophene ratio with increasing thermal maturity (top of Figure 7). Plus, oil asphaltenes show a clear trend of this ratio with increasing maturity and plot within the source rock pyrolysates in Figure 6. This differentiates the Duvernay type II oil asphaltenes from the Italian type II-S oil asphaltenes, which did not plot congruently with the related source rocks. An explanation might be that asphaltenes from reactive sources, such as in southern Italy, are generated much earlier during oil generation, and with increasing maturity, they follow a slightly different trend than related source rocks. The Duvernay oil asphaltenes seemed to be generated at a later stage of conversion, and they still reflect compositional characteristics of their kerogen related to the same stage of conversion. This hypothesis correlates with our observation in bulk kinetic measurements. Previously, we showed that oil asphaltenes from southern Italy are more reactive than related source rocks.16 The reason is likely related to the fact that asphaltenes contain higher proportions of more labile sulfur bonds, such as polysulfide bridges, than the source rock kerogen. These labile bonds are released at the early stage of conversion. This also means that asphaltenes containing such labile sulfur bonds are released at this earliest stage of hydrocarbon formation.

Figure 7. 3-Methylthiophene ratio [3-methylthiophene/(3-methylþ 2-methyl- þ 2,5-dimethylthiophene)] versus Tmax (top) for whole rock and bitumen asphaltene pyrolysates from different wells and (middle) for whole rock pyrolysates from three selected wells and (bottom) versus API for oil asphaltene pyrolysates.

Obviously, the whole rock and source rock asphaltene pyrolysates show stronger variations on the top of Figure 7. Therefore, the middle of Figure 7 compares the 3-methylthiophene ratio for source rocks from three different wells. The source rock pyrolysates from the Sarcee Pibroch well (northern part of the Rimbey-Meadowbrook reef) show generally lower values for the 3-methylthiophene ratio, and the ratio increases only slightly with increasing thermal maturity. Source rock pyrolysates from the wells Ferrybank 555

Energy Fuels 2010, 24, 550–556

: DOI:10.1021/ef900900z

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(southern part of the reef) and Imperial Kingman (East Shale basin) show a stronger increase of the thiophenes ratio with increasing maturity. In addition, the source rocks from both wells show similar values for the 3-methylthiophene ratio, but the maturity for source rocks from the well Ferrybank is higher. The diverse values in thiophenic ratios for organic matter from different wells point to organofacies variations, and this explains the spreading of data in Figure 6 and the top of Figure 7. The oil asphaltene pyrolysates plot closely to more mature whole rock pyrolysates, showing Rock-Eval Tmax values between 427 and 442 °C (Figure 6). This corresponds to the relatively high maturity or high API gravity of related Duvernay crude oils. Interestingly, the alkylthiophene distribution of oil asphaltenes pyrolysates does not correlate with source rocks of a single well. This indicates that all oils are likely mixtures sourced from various organic matter facies in similar proportions. Remarkably, the concentration of non-shielded 3-methylthiophene is higher in oil asphaltenes than in source rock bitumen asphaltenes. On the basis of the concept that shielded isomers are rather expelled and non-shielded isomers are retained in source rock bitumen, we would expect higher concentrations of 3-methylthiophene in source rock asphaltenes. However, this is not the case. Source rock asphaltenes show higher relative concentrations of the shielded 2-methylthiophene. Although, it is still unknown if these methylthiophene isomers in pyrolysates are also linked to the precursor, showing shielded and non-shielded characteristics. The asphaltenes from four oils with lower API (from the three wells Redwater, Judy Creek, and Leduc Woodbend) show a linear trend in the 3-methylthiophene ratio with increasing API (bottom of Figure 7). These four oils are from up-dip reservoirs in the northern part of the RimbeyMeadowbrook reef. The asphaltenes from the oil with API of 44° do not follow the trend in this diagram. The related oil (well Homeglen-Rimbley) is from a down-dip reservoir in the southern part of the Rimbey-Meadowbrook reef. Li et al.40 classifies all oils of the present study as petroleums of the same oil subfamily based on C23 tricyclic terpane/trisnorhopane ratios. Although the authors pointed to variations in tricyclic terpanes for the oils from Homeglen-Rimbley, these oils are not divided from the oils in up-dip reservoirs because of their similar Ts/(Ts þ Tm) ratios. However, the alkylthiophene distribution of the oil asphaltenes suggests that the oil from Homeglen-Rimbley is sourced from different organofacies than the oils in the northern part of the reef.

in timing of formation. The distribution of alkylthiophenes in asphaltene pyrolysates, however, provides a powerful tool for correlating oils and its sources and determining source heterogeneities. In addition, both case studies showed that the alkylthiophene distribution for type II and type II-S oil asphaltenes can be used to define thermal oil maturity differences. (2) Pyrolysates of oil asphaltenes from the low-gammacerane oils from southern Italy show lower yields of alkylthiophenes than those from the crude oils associated with a more hypersaline environment. (3) Source rocks and oils from southern Italy indicate stronger facies variations; however, the distribution of certain alkylthiophenes in whole rock and asphaltene pyrolysates shows remarkable similarities. (4) The distribution of alkylthiophenes with the same arrangements of side chains has the potential for facies correlation and linking oils to their generic sources. For example, the ratio of 2-ethyl-5-propylthiophene/(2-ethyl-5propyl- þ 2-ethyl-5-methy- þ 2-methyl-5-propylthiophene) for the Italian oil asphaltenes allows us to distinguish between oil subfamilies. In addition, the ratio shows a linear change with an increasing biogenic input of nonmarine strata. (5) The ratio of 3-methylthiophene/(3-methyl- þ 2-methyl- þ 2,5dimethylthiophene) related to branched versus linear precursors allows us to estimate the relative thermal maturity of oils based on asphaltene pyrolysates. This provides a tool for reconstructing original maturity characteristics of severely altered oils when biomarkers have been degraded. (6) In the ternary diagram, the type II oil asphaltene pyrolysates from the Duvernay Formation plot closely to more mature whole rock pyrolysates, which corresponds to the relative high maturity of related Duvernay crude oils. In contrast, the Italian type II-S oil asphaltenes do not plot congruently with the related source rocks in the same ternary diagram using alkylthiophene distribution. An explanation might be that asphaltenes from reactive sources are formed much earlier during oil generation, and with increasing maturity, they follow a slightly different trend than related source rocks. (7) Source rock bitumen asphaltenes from the type II-S petroleum system in southern Italy lack any correlation to related whole rocks or oil asphaltenes based on the alkythiophene distribution of their pyrolysates. However, source rock bitumen asphaltene pyrolysates from the Duvernay Formation show a different distribution of alkylthiophenes than related whole rock pyrolysates but similar trends with changing organofacies and thermal maturity. Acknowledgment. This study is part of the research within the Industry Partnership Programme “Asphaltenes as Geochemical Markers” at the GFZ-Potsdam. We are grateful to Shell, Eni E&P Division, StatoilHydro, and ConocoPhillips for financial support. We also thank Schlumberger internal reviewers for technical edits and two anonymous reviewers for their valuable comments.

5. Conclusions (1) Oil asphaltenes generated from marine type II organic matter differ from those related to a type II-S organic matter

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