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Geochemical analysis and familial association of Red River and Winnipeg reservoired oils of the Williston Basin, Canada
Organic Geochemistry 35 (2004) 443–452 www.elsevier.com/locate/orggeochem
Geochemical analysis and familial association of Red River and Winnipeg reservoired oils of the Williston Basin, Canada Mauri Smith*, Stephen Bend Department of Geology, University of Regina, Regina Saskatchewan, Canada, S4S 0A2
Abstract Light oils reservoired in the Lower Ordovician Winnipeg Formation, Williston Basin, have a unique geochemical signature separating them from previously recognized oil families, most importantly they are geochemically distinct from the stratigraphically adjacent Upper Ordovician Red River Formation oils. Winnipeg oils are characterized in the gasoline fraction by very high paraffin indices (4–16) and variations in C7 parameters. The saturate fraction is distinguished by a high abundance of C20+ n-alkanes, low carbon preference index and low amounts of pristane and phytane. Sterane biomarkers show a predominance of C27 > C28C29 suggesting an algal source different from that contributing to Red River oils. In addition, the terpane biomarkers of Winnipeg oils show a high abundance of rearranged hopanes including an unknown C30 compound labelled UC30 and 17 (H) C30-diahopanes (C*30), Moreover, these oils have unambiguous amounts of 18 (H)-30-norneohopanes (C29Ts) which are in low abundance in Red River Formation oils. Geochemical analysis of Lower Ordovician Winnipeg Formation reservoired oils from the Williston Basin suggests that an additional hydrocarbon source, not yet defined, may exist. # 2004 Elsevier Ltd. All rights reserved.
1. Introduction The area commonly referred to as the Williston Basin represents a significant petroleum province. The basin contains pooled hydrocarbons that exhibit a range of characteristics, through which their familial relationships have been defined and subsequently refined (e.g., Williams, 1974; Zumberge, 1983; Osadetz et al., 1992). The Upper Ordovician Red River Formation has been identified as the main source of Ordovician oils in the Williston Basin (Osadetz et al., 1992; Obermajer et al., 1998). However, little is known about the Ordovician oils reservoired in the Winnipeg Formation, specifically their geochemical characteristics, the location of their source (or sources), and the petroleum system to which they may belong. This is because few exploration wells have met with economic success, or have failed to detect the presence of hydrocarbons (i.e., light oils) within the
* Corresponding author. Tel.: +1-306-585-4147; fax: +1306-585-5433.
Winnipeg Formation hence, few samples and little impetus to study the oils. Recently, the Berkley et al. Midale 16a-20-6-11W2 well in southeast Saskatchewan initially produced 1719 m3 of clean 55 API gravity oil at 1150 psi tubing pressure from the Ordovician Winnipeg sand (Oil & Gas Journal, February 8, 1999). Current production from the Winnipeg sand (Lower Black Island Member) includes the Berkley et al. Midale 8-16-6-11W2 (15,699+ m3 cum. prod.), Berkley et al. Midale 15A-206-11W2 (1,700+ m3 cum. prod.) and Berkley et al. Harthaven 7-2-10-9W2 (28,000+ m3 cum. prod.). Moreover, recent studies indicate that there is source rock potential in the Winnipeg and Deadwood formations, that had been previously overlooked, providing more reason to revisit the petroleum potential of these formations (Jarvie, 2001; Seibel, 2002). Together, this has promoted renewed interest concerning the origin of these oils and their familial association. The objective of this study is to define the geochemical signature of the Lower Ordovician Winnipeg reservoired oils through gasoline range, saturate fraction and
0146-6380/$ - see front matter # 2004 Elsevier Ltd. All rights reserved. doi:10.1016/j.orggeochem.2004.01.008
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Fig. 1. Regional setting of the Williston Basin and a location map of the study area with the location of the analysed wells. Red River Formation oil—open circles, Winnipeg Formation oil—filled circles.
biomarker analysis. In addition, identification of key biomarkers, allows to determine if Winnipeg oils are compositionally distinct from previously defined oils in the Williston Basin.
2. Geological setting The study area is located within the Williston Basin and extends from Southeast Saskatchewan into the Western edge of Manitoba and south into North Dakota (Fig. 1). Oils used for analysis consisted of Lower Ordovician Winnipeg reservoired oils and stratigraphically younger Upper Ordovician Red River Formation oils (Fig. 2). The Winnipeg Formation was deposited during the initial progradation of the Tippecanoe transgression in response to early subsidence within the basin (Sloss,
Fig. 2. Stratigraphic section of the Williston Basin.
1963). It lies unconformably above the Cambrian to Lower Ordovician Deadwood Formation, except in the extreme eastern part of the basin where it unconformably lies on Precambrian basement (LeFever, 1996; Greggs and Hein, 2000). The Winnipeg Formation is separated into three members, in ascending order; the Black Island, Icebox and Roughlock members. The Black Island member consists primarily of well-topoorly sorted quartzose sandstone (Vigrass, 1971; LeFever, 1996; Nimegeers, 2000) and represents the principal hydrocarbon reservoir in the Winnipeg Formation (Podruski et al., 1988). The Black Island member is conformably overlain by shales of the Icebox member interpreted as an extensive flooding surface that becomes increasingly silty towards the North (Kessler, 1991; Seibel, 2002). The Roughlock member was deposited in a marine environment and conformably overlies the Icebox member in North Dakota but is absent throughout most of Saskatchewan. When present, it is considered to be a transitional facies between the Icebox member shales and overlying Red River Formation carbonates, becoming less argillaceous and increasingly calcareous upwards (LeFever, 1996). The Roughlock member of the Winnipeg Formation is considered transitional between the Red River and Winnipeg Formation, however, where the Roughlock is absent the contact is sharp and unconformable (Nimegeers, 2000). The overlying Red River Formation is primarily composed of a carbonate sequence that was deposited during an inundation of the eastern North American epeiric seaway (Vigrass, 1971; Kreis and Kent, 2000) and is subdivided in Canada into the Yeoman and Herald members. The Yeoman member is the lowermost member of the Red River Formation and is composed of dolomitized to undolomitized, burrowmottled to unmottled lime mudstones and wackestones (Kent, 1999). The presence of thin kukersite layers
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within the Yeoman member have been identified as the major source for oils reservoired within the Yeoman and Herald members in the Williston Basin (Fowler, 1992; Osadetz et al., 1992; Kent, 1999). The overlying Herald member is composed of laminated dolomite and anhydrite and is not associated with the production of hydrocarbons in Saskatchewan and is not directly referred to in the study.
3. Previous studies The possible existence of multiple petroleum systems in Cambrian-Ordovician strata in the Williston Basin has been a subject of discussion for numerous years (e.g., Williams, 1974; Zumberge, 1983; Brooks et al., 1987; Osadetz et al., 1992). Early oil-to-oil and oil-tosource correlation studies utilized gas chromatography, carbon-isotope ratios and optical-rotation data (e.g., Williams, 1974). C15+ saturate fraction gas chromatography (SFGC) of Winnipeg shale extracts were considered to match the odd-even predominance of C15–C19 n-alkanes associated with Ordovician Red River Formation oils (Williams, 1974). In addition, Rock-Eval, TOC data was used to assess the source potential of Winnipeg shales, and although low, Williams (1974) concluded that the Lower Ordovician Winnipeg Formation shale was the sole source of Ordovician oil. Later studies (Zumberge, 1983; Leenheer and Zumberge, 1987) using carbon-isotope ratios and biomarker analysis, focusing on tricyclic diterpane distributions, also suggested that the Winnipeg Formation was the source of Ordovician reservoired oils. Zumberge (1983) noted the predominance of C19 and C20 diterpanes and a low abundance of C29 steranes in the Red River Formation oils. Leenheer and Zumberge (1987) subsequently noted the distinct C15+ SFGC signature of the Red River oils and, like Williams (1974), attributed the origin of the Red River oils to a Winnipeg shale source. Brooks et al. (1987), using gross geochemical characteristics in conjunction with SFGC of the C15+ fraction and biomarker analyses, concluded that the unique geochemical signature shown in Ordovician Red River oils could not be correlated with a Winnipeg Formation source. Several researchers noted that the geochemical signature associated with the Red River Formation oils is typical of oils sourced by organic matter containing abundant Gloeocapsomorpha Prisca (Longman and Palmer, 1987; Fowler, 1992), geochemically and petrographically defined as a kukersite (Fowler, 1992; Stasiuk and Osadetz, 1993; Stasiuk, 1999). Red River Formation kukersites were proven to be the main source of Ordovician oils (Longman and Palmer, 1987; Fowler, 1992; Osadetz et al., 1992). Osadetz et al. (1992) empirically separated the known oils of the Williston Basin into five oil families based on whole oil characteristics
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and biomarkers. This is the most commonly used oil classification scheme for oils of the Williston Basin. However, recently discovered Cambrian and Ordovician oils appear to be geochemically distinct and do not conform to any of the oil families previously defined by Osadetz et al. (1992). For example, the Cambrian oils from Newporte, North Dakota have a higher abundance of C20+ n-alkanes, low pristane/phytane ratios and a higher abundance of acyclic isoprenoids relative to n-alkanes (Fowler et al., 1998; Jarvie, 2001). Moreover, no studies to date have successfully shown that the geochemical signature of Winnipeg oils is significantly different from Red River oils proving that they are from two different sources (e.g., Jarvie, 2001). In high gravity oils with relatively low concentrations of high molecular weight biomarkers, the application of light hydrocarbon correlation parameters for oil-to-oil and oil-to-source correlations have been found to be extremely useful (Thompson, 1983; Obermajer et al., 2000; Jarvie, 2001). Therefore, in this study, gasoline range hydrocarbons in conjunction with biomarker analyses are used to distinguish between oils of different famial association to determine if Winnipeg reservoired oils represent a separate oil from a unique source.
4. Analytical methods Gasoline range hydrocarbons (i-C5–i-C8) were analyzed using a HP5890 gas chromatograph (GC) with a 60m DB-1 fused silica column connected to an OI Analytical 4560 Purge and Trap sample concentrator. The initial oven temperature was held at 30 C for 10 min then increased at 1 C/min to 40 C and held for 25 min with a total run time of 45 min. Eluting hydrocarbons were detected using a flame ionization detector (FID). Saturated hydrocarbons were analyzed using GC-MS. Saturate fraction gas chromatograms were obtained using a Varian 3700 FID GC with a 30 m DB-1 column and helium as the carrier gas. The initial oven temperature (60 C) was increased at 6 C/min to 300 C and held for 30 min with a total run time of 70 min. Saturate fraction biomarker data was collected using an Agilent 6890 GC directly coupled to a Micromass Autospec double focusing mass spectrometer with a 30 m DB-5MS fused silica column. Helium was used as the carrier gas. The oven was programmed at 100 C for 2 min, ramped at 40 C/min to 180 C, and then ramped at 4 C/min to 320 C and held for 7 min. The mass spectrometer was operated in electron impact mode with an ionization voltage of 40eV and a source temperature of 300 C and data was recorded by selected ion monitoring mode of eight ions. Terpane and sterane ratios were calculated from the resulting m/z 191, m/z 217, and m/z 218 mass fragmentograms. The aromatic fraction was analyzed using an HP 6890 GC coupled to an HP 5973MSD with
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a 30m DB-5MS fused silica column. The oven was programmed from 100 C at 3 C/min to 300 C and held for 10 min. The instrument was operated in selected ion monitoring mode.
sample locations are given in Table 1. Representative gasoline range chromatograms, saturate fraction chromatograms, and mass fragmentograms are displayed in Figs. 3–6. There are no apparent signs or suggestion of biodegradation or water washing for any of the oils studied.
5. Results Oils used for the study consisted of eight early Ordovician Winnipeg reservoired oils and six stratigraphically younger Ordovician Red River Formation oils. The
Table 1 Sample locations for Red River and Winnipeg Formation reservoired oils used in the study
RED RIVER
WINNIPEG
GSC Sample
Sample location
L00549 L00550 L01018 L01720 L02270 L02468 L02610 L02807 L02808 L02893 L02899 L03180 L03182
4-22-315W2 7-23-1-17W2 SW33-163N-101W2 T157N-R100W 16-03-07-11W2 07-16-06-11W2 11-16-07-07W2 16-20-06-11W2 08-16-06-11W2 08-16-06-11W2 16-20-06-22W2 11-14-07-10W2 11-14-07-10W2
Fig. 3. Representative gasoline range chromatograms of Ordovician Winnipeg and Red River Formation oils of the Williston Basin area.
Fig. 4. Representative saturate fraction gas chromatograms showing distributions of n-alkanes and isoprenoids for Winnipeg Formation and Red River Formation reservoired oils.
Fig. 5. Representative m/z 218 fragmentograms of C27, C28 and C29 steranes for Winnipeg and Red River reservoired oils in the Williston Basin area.
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5.1. Geochemistry of Winnipeg Formation oils Winnipeg Formation oils are typically high API oils (40–54 ), with a high saturate/aromatic hydrocarbon ratio (average 6.7) with the saturate+aromatic fraction combining to account for over 92% of the total oil composition. The gasoline range signature of Winnipeg oils indicates high amounts of methylhexanes exemplified by extremely high Paraffin Index 1 (PI 1) values ranging from 3.95 up to 16.64 with an average of 11.24 (Fig. 3). The saturate fraction of the Lower Ordovician Winnipeg Formation oils is characterized by a high abundance of long chain n-alkanes (C20+) and low carbon preference index (CPI) of 1.0–1.5 (Fig. 4). The n-alkane profile displays a slight odd/even predominance of nalkanes between C15–C19 with a smooth envelope from C20+ onward. In addition, these oils are associated with low concentrations of pristane and phytane and a low pristane/phytane ratio (average 1.3). The GC trace has a smooth baseline and abundance of low molecular weight n-alkanes, commonly used to indicate that the effects of biodegradation and/or water washing, were negligible (Peters and Moldowan, 1993). Sterane and terpane biomarkers appear to be quite distinct and are comparable throughout the sample set for all Winnipeg reservoired oils. Sterane biomarkers have a normalized distribution of C27 > C28C29 (45:28:27) regular steranes, based on abb isomers, as derived from the m/z 218 mass fragmentogram (Fig. 5). Terpane biomarkers have a high relative abundance of C23 and C24 triterpanes and a smooth extended hopane profile from C31–C35. Winnipeg oils typically have Ts/ Tm values greater then 1, with an average of 1.28. In addition, terpane biomarkers of Winnipeg oils show a high abundance of rearranged hopanes including an unknown C30 compound labelled UC30 (Philp and Oung, 1992; Li et al., 1999) and 17 (H) C30-diahopanes (peaks 4 and 8 in Fig. 6). Moreover, these oils have unambiguous amounts of 18 (H)-30-norneohopanes (C29Ts) (peak 7 in Fig. 6) not present in other oils found in the basin.
of C20+ n-alkanes, a high carbon preference index (CPI) (1.5–2.0), a low pristane/phytane ratio and low concentrations of acyclic isoprenoids (i.e. pristane and phytane) (Fig. 4). In addition, the GC traces show an abundance of low molecular weight n-alkanes and a smooth baseline. Sterane and hopane distributions indicate that Red River oils have a relatively high abundance of steranes and show a predominance of C29 >C27 >C28 (49:34:17) on the m/z 218 mass fragmentogram. The hopane signature for the oils shows no predominance of C23 or C24 triterpanes and Ts/Tm values are typically < 1. More importantly rearranged hopanes are not present in these oils as they are in the other Lower Palaeozoic oils.
5.2. Geochemistry of Red River Formation oils
5.3. Maturity
Oils reservoired in the Red River Formation have relatively high saturate/aromatic hydrocarbon ratios (average 2.36) with the saturate+aromatic fraction combining to account for over 78% of the total oil composition. Gasoline range parameters of Red River Formation oils exhibit very low abundance of methylhexanes, specifically 2-methylhexane and 3-methylhexane (Fig. 3). The saturate fraction of Red River Formation oils is consistent with previous studies (Longman and Palmer, 1987; Fowler, 1992). The SFGC exhibits a predominance of n-alkanes up to C19, a low concentration
Aromatic hydrocarbons were examined to determine the maturity of Winnipeg and Red River Formation oils. The Methylphenanthrene Index (MPI 1), in combination with calculated vitrinite reflectance equivalent indices (%Rc) (Radke and Welte, 1983), suggests that the Red River oils are of low maturity, equivalent to a vitrinite reflectance of 0.62%, whereas Winnipeg oils are slightly more mature with an average vitrinite reflectance equivalent of 0.82%. This is consistent with Winnipeg and Red River triaromatic sterane cracking ratios of 0.74 and 0.45, respectively, also suggesting that Winnipeg oils are more mature.
Fig. 6. Representative m/z 191 fragmentograms of Red River Formation and Winnipeg Formation oils.
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Fig. 7. Cross-plot of the normalized percentage peak area of 3-methylhexane+2, 4-dimethylpentane vs. 2-methylhexane+2, 3-dimethylpentane showing invariance of Mango K1 parameters and separation of Winnipeg and Red River oils.
6. Discussion Light hydrocarbon ratios effectively differentiate between Winnipeg and Red River Formation oils particularly using C7 ‘‘Mango’’ Parameters (Mango, 1987, 1990) and Paraffin Indices (Thompson, 1983). According to ten Haven (1996) the K1 parameter (2-methylhexane+2, 3-dimethylpentane)/(3-methylhexane+2, 4dimethylpentane), remains consistent within co-genetic oil families. Winnipeg and Red River Formation oils separate into two groups suggesting they stem from two distinct sources (Fig. 7). Despite an apparent similarity in the slope of K1, the concentration of methylhexanes is much higher in Winnipeg oils than in Red River oils (peaks 9 and 11 in Fig. 3). Moreover, high concentrations of methylhexanes provide strong evidence for the source environment, suggesting a high abundance of clastic input (Jarvie et al., 2001; Jarvie, 2001). In addition, geochemical plots of P3 versus P2+N2 (Fig. 8a) and P2 versus N2/P3 (Fig. 8b) commonly used to
determine homologous sets of oils, clearly differentiate between Winnipeg and Red River Formation oils. The application of Paraffin Indices provides a preliminary means of separating the oils into families (Fig. 9). Variations in Paraffin Indices are not totally dependent on maturity as first suggested by Thompson (1983), but are also dependent on source material and kerogen type, typically increasing in more aliphatic Type I kerogens (Obermajer et al., 1998, 2000). High PI 1 values of Winnipeg oils separate them from all the other oil families defined by Obermajer et al. (2000) for the Williston basin suggesting a unique source. According to Thompson (1983), high Paraffin Indices indicate supermature oils originating in deep basin-center locations where oils are trapped in the source, or a reservoir in close proximity, for an extended period of time and are therefore subjected to extreme thermal conditions increasing the degree of paraffinicity. This may indicate that Winnipeg oils come from an older, deeper source then Red River oils. The C15+ saturate fraction of Upper Ordovician Red River Formation oils is associated with a geochemical signature typical of kukersite source rocks containing organic matter dominated by Gloeocapsomorpha Prisca (Longman and Palmer, 1987; Fowler, 1992). The oils exhibit a predominance of n-alkanes up to C19, a low concentration of C20+ n-alkanes, a high carbon preference index (CPI) (1.5–2.0), a low pristane/phytane ratio and low concentrations of acyclic isoprenoids (i.e. pristane and phytane) (Longman and Palmer, 1987; Fowler, 1992) (Fig. 4). In contrast, Winnipeg oils appear to be ‘‘waxier’’ than Red River oils, containing a higher abundance of C20+ n-alkanes indicated by the low ratio of medium-chain to long-chain n-alkanes (Fig. 10). Jacobson et al. (1988) showed two distinct organic matter assemblages within the Red River Formation, stating that one of the assemblages had extended paraffin contents in the nC20+ range. However, it appears that neither assemblage contained the high paraffin content
Fig. 8. Cross-plot of normalized % peak areas of ‘‘Mango’’ parameters of a) P2+N2 versus P3 and b) N2/P3 versus P2 showing good separation between oil families. P2=2-methylhexane+3-methylhexane, P3=2,2-dimethylpentane+2,4-dimethylpentane+3,3 dimethylentane+2,3-dimethylpentane, N2=1,1-dimethylpentane+1c3-dimethylcyclopentane+1t3-dimethylcyclopentane.
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Fig. 9. Cross-plot of Paraffin Index 1 versus Paraffin Index 2. PI 1- (Isoheptane value)=(2-methylhexane+3-methylhexane)/ sum of 1c3-, 1t3-, 1t2- dimethylcyclopentanes; PII 2- (Heptane value)=(n-heptane100)/sum of compounds eluting between cyclohexane and methylcyclohexane.
Fig. 10. Cross-plot of Carbon Preference Index (CPI) versus the ratio of Medium-Chain (C15-C19)/Long-Chain (C20-C25) n-alkanes for Winnipeg and Red River Formation oils.
shown by Winnipeg Formation oils. High abundance of long-chain n-alkanes is typically associated with terrestrial input however because of the possible age of Winnipeg oils it is likely related to algal contributions. In addition, Winnipeg oils can be distinguished from Red River oils by lower CPI values and from other, younger oils in the basin (Osadetz et al., 1992) by low abundance of pristane and phytane and low pristane/phytane ratios. The geochemical difference between Winnipeg and Red River Formation oils is not only evident in the gasoline range and saturate fraction but extends into the biomarker fingerprints as well. Winnipeg oils exhibit a predominance of C27 over C28 and C29 steranes (Fig. 11). Bend and Seibel (2000) also noted a predominance of C27 steranes for Winnipeg oils in Saskatchewan.
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Consistent with previous observations, Red River oils show a predominance of C29 over C27 and C28 steranes representing the algal input of G. prisca (Fig. 11)(Fowler, 1992). Variation in steranes suggests that the algal source material for Winnipeg reservoired oils was different than that of Red River oils. Hopane biomarkers also effectively differentiate between Winnipeg and Red River Formation oils. Winnipeg oils have relatively high concentrations of C23 and C24 tricyclic terpanes compared to Red River oils, which according to Hunt (1996), are common in oils derived from marine and lacustrine environments. Red River oils typically have Ts/Tm values of less than 1 (Obermajer et al., 1998), whereas Winnipeg oils tend to have Ts/Tm values greater then 1 suggesting a more clastic source for Winnipeg oil (Peters and Moldowan, 1993). Although Ts/Tm values are controlled by both source and maturity, values for Winnipeg oils are believed to be source related, consistent with high concentrations of methylhexanes which also suggest high clastic input (Jarvie, 2001; Jarvie et al., 2001). The smooth C31–C35 homohopane profile of the Winnipeg oils is also typical for oils originating from clastic sources. High concentrations of rearranged hopanes found in Winnipeg oils including 17a (H)-C30 diahopanes (C*30), UC30 hopanes and 18a(H)-30-norneohopane (C29Ts) are absent in Red River oils (peaks 8, 4 and 7 in Fig. 6). High concentrations of diahopanes are to some extent related to variations in maturity since diahopanes typically have a greater degree of thermal stability than regular hopanes, therefore values can increase with increasing maturity (Moldowan et al., 1991; Obermajer et al., 2002). However, numerous studies have shown that the presence of diahopanes is influenced by the environment of deposition (Telnaes et al., 1992; Peters and Moldowan, 1993). Diahopanes have typically been associated with clay-rich source rocks deposited in suboxic to oxic conditions (Peters and Moldowan, 1993). Moldowan et al. (1991) suggested that C*30 diahopanes recognized in numerous oils along with C29Ts compounds, are derived from a common bacterial hopane precursor with variations resulting from effects of diagenesis. However, it should be noted that according to Telnaes et al. (1992), diahopane abundances co-vary with the salinity of the depositional environment and type of bacterial organisms living there, not with the presence or absence of active catalytic sites on clay minerals as previously suggested. Telnaes et al. (1992) also suggested that diahopanes are common in oils sourced in lacustrine environments. However, despite hydrogen isotope evidence of lacustrine input in Cambrian/Ordovician times within the Williston Basin (Li et al., 1999), the oils from this study do not correspond with a lacustrine source environment. Moreover, geochemical evidence (this study) and an abundance of geological evidence (Kessler, 1991; Nimegeers, 2000;
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Fig. 11. Ternary plot of the normalized distribution of C27:C28:C29 regular steranes in Winnipeg Formation and Red River Formation oils.
Seibel and Bend, 2001; Siebel, 2002) suggest that Winnipeg oils originate from a marine shale source rather than a lacustrine source. Finally, Armanios et al. (1992) believed that large abundances of diahopanes were characteristic of highly biodegraded oils, although this does not explain the existence of diahopanes in the unbiodegraded oils of the Winnipeg Formation. It is evident that tthe precise reason for high abundances of rearranged hopanes remains unresolved. However, they can be used to differentiate between compositionally different oils clearly separating Winnipeg reservoired oils from all previously defined oils in the basin. Moreover, it appears that oils reservoired in the Winnipeg formation may be related to a marine shale source.
7. Conclusion Despite their close stratigraphic proximity, it is evident that oils found in Winnipeg and Red River Formations are distinct and originate from two separate sources. The diagnostic geochemical signature of Winnipeg Formation oils is observed in the gasoline range, saturate fraction and biomarker fingerprints. The gasoline fraction of Winnipeg oils is characterized by high paraffin indices and variations in C7 parameters resulting from a high abundance of methylhexanes. The
C15+ saturate fraction of Winnipeg oils is characterized by an abundance of C20+ n-alkanes in addition to low CPI values, low amounts of pristane and phytane, and low ratios of Pr/Ph. Regular sterane biomarkers show Winnipeg oils to have a predominance of C27 >C28C29 in contrast to Red River oils which are characterized by a C29 regular sterane predominance. Winnipeg reservoired oils are also distinguishable through a combination of terpane biomarkers including high concentrations of unknown C30 compounds (UC30), 17a(H)-diahopanes (C*30) and 18a(H)-30-norneohopanes (C29Ts). In addition, Winnipeg oils have a higher abundance of C23 and C24 tricyclic terpanes and relatively higher Ts/Tm ratios than Red River oils. This preliminary work suggests that the Winnipeg oils are mature, aliphatic oils that are potentially from a clastic marine source. Although it is evident that the Winnipeg reservoired oils of the Williston Basin belong to a unique oil family, the source of these oils is yet to be determined and will be the focus of future studies.
Acknowledgements We would like to thank Sneh Achal, Rachel Robinson and Marina Milovic for their fantastic lab assistance as well as Martin Fowler, Kim Manzano-Kareah and
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Mark Obermajer for their help. Anadarko Canada is greatly appreciated for their financial support and the Geological Survey of Canada for their analytical support. We would also like to extend our appreciation to Dr. Dan Jarvie and Dr. Barry Bennett for their constructive reviews of the work.
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Group (Middle Ordovician) Manitoba, Saskatchewan, North Dakota. In: Christopher, J.E., Haidl, F.M. (Eds.), Eighth International Williston Basin Symposium, Saskatchewan Geological Society Special Publication No.11. pp. 1–3. Kreis, L.K., Kent, D.M., 2000. Basement Controls on Red River Sedimentation and Hydrocarbon Production in Southeast Saskatchewan. Summary of Investigations 2000, Saskatchewan Geological Survey, Sask. Energy Mines, Misc. Rep. 2000-4.1. pp. 21–42. Leenheer, M.J., Zumberge, J.E., 1987. Correlation and thermal maturity of Williston Basin crude oils and Bakken source rocks using terpane biomarkers. In: Longman, M.W. (Ed.), Williston Basin: Anatomy of a Cratonic Oil Province. Rocky Mountain Association of Geologists, Denver, pp. 287–298. LeFever, R.D., 1996. Sedimentology and stratigraphy of the Deadwood-Winnipeg Interval (Cambro-Ordovician), Williston Basin. In: Longman, M.W., Sonnenfeld, M.D. (Eds.), Paleozoic Systems of the Rocky Mountain Region. Rocky Mountain Section, Society for Sedimentary Geology. pp. 11–28. Li, M., Lin, R., Liao, Y., Snowdon, L.R., Wang, P., Li, P., 1999. Organic geochemistry of oils and condensates in the Kekeya Field, Southwest Depression of the Tarim Basin (China). Organic Geochemistry 30, 15–37. Longman, M.W., Palmer, S.E., 1987. Organic geochemistry of mid-continent Middle and Late Ordovician Oils. American Association of Petroleum Geologists Bulletin 71, 938–950. Mango, F.D., 1987. An invariance in the isoheptanes of petroleum. Science 237, 514–517. Mango, F.D., 1990. The origin of light cycloalkanes in petroleum. Geochimica et Cosmochimica Acta 54, 23–27. Moldowan, J.M., Fago, F.J., Carlson, R.M., Young, D.C., Duyne, G.V., Clardy, J., Schoell, M., Pillinger, C.T., Watt, D.S., 1991. Rearranged hopanes in sediments and petroleum. Geochimica et Cosmochimica Acta 55, 3333–3353. Nimegeers, A., 2000. An Allostratigraphic Analysis of the Middle Ordovician Winnipeg Group in Southern Saskatchewan, unpublished B.Sc. Honours Thesis. University of Regina, Regina. Obermajer, M., Osadetz, K. G. Snowdon, L. R., 1998. Familial association and sources of oil quality variation in the Williston Basin from gasoline range and saturated hydrocarbon parameters In: Christopher, J.E., Gilboy, C.F., Paterson, D.F., Bend, S.L. (Eds.), Eighth International Williston Basin Symposium, Saskatchewan Geological Society Special Publication No. 13, pp. 209–225. Obermajer, M., Osadetz, K.G., Fowler, M.G., Snowdon, L.R., 2000. Light hydrocarbon (gasoline range) parameter refinement of biomarker-based oil-oil correlation studies: an example from the Williston Basin. Organic Geochemistry 31, 959–976. Obermajer, M., Osadetz, K.G., Fowler, M.G., Silliman, J., Hansen, W.B., Clark, M., 2002. Delineating compositional variabilities among crude oils from central Montana, USA, using light hydrocarbon and biomarker characteristics. Organic Geochemistry 33, 1343–1359. Oil & Gas Journal, 1996. Eagle Operating IPF’s re-entry for 1025 BOPD out of Cambrian-Renville County, North Dakota. Oil & Gas Journal 76 (29), 1. Osadetz, K.G., Brooks, P.W., Snowdon, L.R., 1992. Oil families and their sources in Canadian Williston Basin,
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southeastern Saskatchewan and southwestern Manitoba. Bulletin of Canadian Petroleum Geology 40, 254–273. Peters, K.E., Moldowan, J.M., 1993. The Biomarker Guide. Prentice Hall, New Jersey. Philp, R.P., Oung, J.N., 1992. Biomarker distributions in crude oils as determined by tandem mass spectrometry. In: Moldowan, J.M., Albrecht, P., Philp, R.P. (Eds.), Biological Markers in Sediments and Petroleum. Prentice Hall, Englewood Cliff, NJ, pp. 106–123. Podruski, J.A., Barclay, J.E., Hamblin, A.P., Lee, P.J., Osadetz, K.G., Procter, R.M., Taylor, G.C., 1988. Conventional Oil Resources of Western Canada. Geological Survey of Canada, paper 87–26, 17–19. Radke, M., Welte, D.H., 1983. The Methylphenanthrene Index (MPI): a maturity parameter based on aromatic hydrocarbons. In: Bjoroy, M. et al. (Eds.), Advances in Organic Geochemistry 1981. J. Wiley and Sons, New York, pp. 504–512. Seibel, C., 2002. An Examination of the Source Rock Potential of the Deadwood and Winnipeg Formations of Southern Saskatchewan. Unpublished M.Sc. Thesis, University of Regina. Regina, pp. 1–140. Seibel, C., Bend, S., 2001. Organofacies and Source Potential of the Middle Ordovician Winnipeg Formation within Southern Saskatchewan. In: Rock the Foundation Convention, Canadian Society of Petroleum Geologists, Conference proceedings CD, pp. 082-1. Sloss, L.L., 1963. Sequences in the cratonic interior of North America. Geological Society of America Bulletin 74, 93–110.
Stasiuk, L.D., 1999. Microscopic studies of sedimentary organic matter: key to understanding organic-rich strata, with Paleozoic examples from Western Canada Basin. Geoscience Canada 26, 149–172. Stasiuk, L.D., Osadetz, K.G., 1993. Thermal maturity, alginitebitumen transformation and hydrocarbon generation in Upper Ordovician source rocks, Saskatchewan. Energy Source 15, 205–237. Telnaes, N., Isaksen, G.H., Farrimond, P., 1992. Unusual triterpane distributions in lacustrine oils. Organic Geochemistry 18, 785–789. ten Haven, H.L., 1996. Applications and limitations of Mango’s light hydrocarbon parameters in petroleum correlation studies. Organic Geochemistry 24, 957–976. Thompson, K.F.M., 1983. Classification and thermal history of petroleum based on light hydrocarbons. Geochimica et Cosmochimica Acta 47, 303–316. Vigrass, L.W., 1971. Depositional framework of the Winnipeg Formation in Manitoba and eastern Saskatchewan. Geological Association of Canada Special Paper No 9, 225– 234. Williams, J.A., 1974. Characterization of Oil Types in Williston Basin. American Association of Petroleum Geologists Bulletin 58, 1243–1252. Zumberge, J.E., 1983. Tricyclic diterpane distribution in the correlation of Palaeozoic crude oils from the Williston Basin. In: Bjoroy, M. (Ed.), Advances in Organic Geochemistry 1981. John Wiley & Sons Ltd, New York, pp. 738–745.
Geochemical analysis and familial association of Red River and Winnipeg reservoired oils of the Williston Basin, Canada Mauri Smith*, Stephen Bend Department of Geology, University of Regina, Regina Saskatchewan, Canada, S4S 0A2
Abstract Light oils reservoired in the Lower Ordovician Winnipeg Formation, Williston Basin, have a unique geochemical signature separating them from previously recognized oil families, most importantly they are geochemically distinct from the stratigraphically adjacent Upper Ordovician Red River Formation oils. Winnipeg oils are characterized in the gasoline fraction by very high paraffin indices (4–16) and variations in C7 parameters. The saturate fraction is distinguished by a high abundance of C20+ n-alkanes, low carbon preference index and low amounts of pristane and phytane. Sterane biomarkers show a predominance of C27 > C28C29 suggesting an algal source different from that contributing to Red River oils. In addition, the terpane biomarkers of Winnipeg oils show a high abundance of rearranged hopanes including an unknown C30 compound labelled UC30 and 17 (H) C30-diahopanes (C*30), Moreover, these oils have unambiguous amounts of 18 (H)-30-norneohopanes (C29Ts) which are in low abundance in Red River Formation oils. Geochemical analysis of Lower Ordovician Winnipeg Formation reservoired oils from the Williston Basin suggests that an additional hydrocarbon source, not yet defined, may exist. # 2004 Elsevier Ltd. All rights reserved.
1. Introduction The area commonly referred to as the Williston Basin represents a significant petroleum province. The basin contains pooled hydrocarbons that exhibit a range of characteristics, through which their familial relationships have been defined and subsequently refined (e.g., Williams, 1974; Zumberge, 1983; Osadetz et al., 1992). The Upper Ordovician Red River Formation has been identified as the main source of Ordovician oils in the Williston Basin (Osadetz et al., 1992; Obermajer et al., 1998). However, little is known about the Ordovician oils reservoired in the Winnipeg Formation, specifically their geochemical characteristics, the location of their source (or sources), and the petroleum system to which they may belong. This is because few exploration wells have met with economic success, or have failed to detect the presence of hydrocarbons (i.e., light oils) within the
* Corresponding author. Tel.: +1-306-585-4147; fax: +1306-585-5433.
Winnipeg Formation hence, few samples and little impetus to study the oils. Recently, the Berkley et al. Midale 16a-20-6-11W2 well in southeast Saskatchewan initially produced 1719 m3 of clean 55 API gravity oil at 1150 psi tubing pressure from the Ordovician Winnipeg sand (Oil & Gas Journal, February 8, 1999). Current production from the Winnipeg sand (Lower Black Island Member) includes the Berkley et al. Midale 8-16-6-11W2 (15,699+ m3 cum. prod.), Berkley et al. Midale 15A-206-11W2 (1,700+ m3 cum. prod.) and Berkley et al. Harthaven 7-2-10-9W2 (28,000+ m3 cum. prod.). Moreover, recent studies indicate that there is source rock potential in the Winnipeg and Deadwood formations, that had been previously overlooked, providing more reason to revisit the petroleum potential of these formations (Jarvie, 2001; Seibel, 2002). Together, this has promoted renewed interest concerning the origin of these oils and their familial association. The objective of this study is to define the geochemical signature of the Lower Ordovician Winnipeg reservoired oils through gasoline range, saturate fraction and
0146-6380/$ - see front matter # 2004 Elsevier Ltd. All rights reserved. doi:10.1016/j.orggeochem.2004.01.008
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Fig. 1. Regional setting of the Williston Basin and a location map of the study area with the location of the analysed wells. Red River Formation oil—open circles, Winnipeg Formation oil—filled circles.
biomarker analysis. In addition, identification of key biomarkers, allows to determine if Winnipeg oils are compositionally distinct from previously defined oils in the Williston Basin.
2. Geological setting The study area is located within the Williston Basin and extends from Southeast Saskatchewan into the Western edge of Manitoba and south into North Dakota (Fig. 1). Oils used for analysis consisted of Lower Ordovician Winnipeg reservoired oils and stratigraphically younger Upper Ordovician Red River Formation oils (Fig. 2). The Winnipeg Formation was deposited during the initial progradation of the Tippecanoe transgression in response to early subsidence within the basin (Sloss,
Fig. 2. Stratigraphic section of the Williston Basin.
1963). It lies unconformably above the Cambrian to Lower Ordovician Deadwood Formation, except in the extreme eastern part of the basin where it unconformably lies on Precambrian basement (LeFever, 1996; Greggs and Hein, 2000). The Winnipeg Formation is separated into three members, in ascending order; the Black Island, Icebox and Roughlock members. The Black Island member consists primarily of well-topoorly sorted quartzose sandstone (Vigrass, 1971; LeFever, 1996; Nimegeers, 2000) and represents the principal hydrocarbon reservoir in the Winnipeg Formation (Podruski et al., 1988). The Black Island member is conformably overlain by shales of the Icebox member interpreted as an extensive flooding surface that becomes increasingly silty towards the North (Kessler, 1991; Seibel, 2002). The Roughlock member was deposited in a marine environment and conformably overlies the Icebox member in North Dakota but is absent throughout most of Saskatchewan. When present, it is considered to be a transitional facies between the Icebox member shales and overlying Red River Formation carbonates, becoming less argillaceous and increasingly calcareous upwards (LeFever, 1996). The Roughlock member of the Winnipeg Formation is considered transitional between the Red River and Winnipeg Formation, however, where the Roughlock is absent the contact is sharp and unconformable (Nimegeers, 2000). The overlying Red River Formation is primarily composed of a carbonate sequence that was deposited during an inundation of the eastern North American epeiric seaway (Vigrass, 1971; Kreis and Kent, 2000) and is subdivided in Canada into the Yeoman and Herald members. The Yeoman member is the lowermost member of the Red River Formation and is composed of dolomitized to undolomitized, burrowmottled to unmottled lime mudstones and wackestones (Kent, 1999). The presence of thin kukersite layers
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within the Yeoman member have been identified as the major source for oils reservoired within the Yeoman and Herald members in the Williston Basin (Fowler, 1992; Osadetz et al., 1992; Kent, 1999). The overlying Herald member is composed of laminated dolomite and anhydrite and is not associated with the production of hydrocarbons in Saskatchewan and is not directly referred to in the study.
3. Previous studies The possible existence of multiple petroleum systems in Cambrian-Ordovician strata in the Williston Basin has been a subject of discussion for numerous years (e.g., Williams, 1974; Zumberge, 1983; Brooks et al., 1987; Osadetz et al., 1992). Early oil-to-oil and oil-tosource correlation studies utilized gas chromatography, carbon-isotope ratios and optical-rotation data (e.g., Williams, 1974). C15+ saturate fraction gas chromatography (SFGC) of Winnipeg shale extracts were considered to match the odd-even predominance of C15–C19 n-alkanes associated with Ordovician Red River Formation oils (Williams, 1974). In addition, Rock-Eval, TOC data was used to assess the source potential of Winnipeg shales, and although low, Williams (1974) concluded that the Lower Ordovician Winnipeg Formation shale was the sole source of Ordovician oil. Later studies (Zumberge, 1983; Leenheer and Zumberge, 1987) using carbon-isotope ratios and biomarker analysis, focusing on tricyclic diterpane distributions, also suggested that the Winnipeg Formation was the source of Ordovician reservoired oils. Zumberge (1983) noted the predominance of C19 and C20 diterpanes and a low abundance of C29 steranes in the Red River Formation oils. Leenheer and Zumberge (1987) subsequently noted the distinct C15+ SFGC signature of the Red River oils and, like Williams (1974), attributed the origin of the Red River oils to a Winnipeg shale source. Brooks et al. (1987), using gross geochemical characteristics in conjunction with SFGC of the C15+ fraction and biomarker analyses, concluded that the unique geochemical signature shown in Ordovician Red River oils could not be correlated with a Winnipeg Formation source. Several researchers noted that the geochemical signature associated with the Red River Formation oils is typical of oils sourced by organic matter containing abundant Gloeocapsomorpha Prisca (Longman and Palmer, 1987; Fowler, 1992), geochemically and petrographically defined as a kukersite (Fowler, 1992; Stasiuk and Osadetz, 1993; Stasiuk, 1999). Red River Formation kukersites were proven to be the main source of Ordovician oils (Longman and Palmer, 1987; Fowler, 1992; Osadetz et al., 1992). Osadetz et al. (1992) empirically separated the known oils of the Williston Basin into five oil families based on whole oil characteristics
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and biomarkers. This is the most commonly used oil classification scheme for oils of the Williston Basin. However, recently discovered Cambrian and Ordovician oils appear to be geochemically distinct and do not conform to any of the oil families previously defined by Osadetz et al. (1992). For example, the Cambrian oils from Newporte, North Dakota have a higher abundance of C20+ n-alkanes, low pristane/phytane ratios and a higher abundance of acyclic isoprenoids relative to n-alkanes (Fowler et al., 1998; Jarvie, 2001). Moreover, no studies to date have successfully shown that the geochemical signature of Winnipeg oils is significantly different from Red River oils proving that they are from two different sources (e.g., Jarvie, 2001). In high gravity oils with relatively low concentrations of high molecular weight biomarkers, the application of light hydrocarbon correlation parameters for oil-to-oil and oil-to-source correlations have been found to be extremely useful (Thompson, 1983; Obermajer et al., 2000; Jarvie, 2001). Therefore, in this study, gasoline range hydrocarbons in conjunction with biomarker analyses are used to distinguish between oils of different famial association to determine if Winnipeg reservoired oils represent a separate oil from a unique source.
4. Analytical methods Gasoline range hydrocarbons (i-C5–i-C8) were analyzed using a HP5890 gas chromatograph (GC) with a 60m DB-1 fused silica column connected to an OI Analytical 4560 Purge and Trap sample concentrator. The initial oven temperature was held at 30 C for 10 min then increased at 1 C/min to 40 C and held for 25 min with a total run time of 45 min. Eluting hydrocarbons were detected using a flame ionization detector (FID). Saturated hydrocarbons were analyzed using GC-MS. Saturate fraction gas chromatograms were obtained using a Varian 3700 FID GC with a 30 m DB-1 column and helium as the carrier gas. The initial oven temperature (60 C) was increased at 6 C/min to 300 C and held for 30 min with a total run time of 70 min. Saturate fraction biomarker data was collected using an Agilent 6890 GC directly coupled to a Micromass Autospec double focusing mass spectrometer with a 30 m DB-5MS fused silica column. Helium was used as the carrier gas. The oven was programmed at 100 C for 2 min, ramped at 40 C/min to 180 C, and then ramped at 4 C/min to 320 C and held for 7 min. The mass spectrometer was operated in electron impact mode with an ionization voltage of 40eV and a source temperature of 300 C and data was recorded by selected ion monitoring mode of eight ions. Terpane and sterane ratios were calculated from the resulting m/z 191, m/z 217, and m/z 218 mass fragmentograms. The aromatic fraction was analyzed using an HP 6890 GC coupled to an HP 5973MSD with
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a 30m DB-5MS fused silica column. The oven was programmed from 100 C at 3 C/min to 300 C and held for 10 min. The instrument was operated in selected ion monitoring mode.
sample locations are given in Table 1. Representative gasoline range chromatograms, saturate fraction chromatograms, and mass fragmentograms are displayed in Figs. 3–6. There are no apparent signs or suggestion of biodegradation or water washing for any of the oils studied.
5. Results Oils used for the study consisted of eight early Ordovician Winnipeg reservoired oils and six stratigraphically younger Ordovician Red River Formation oils. The
Table 1 Sample locations for Red River and Winnipeg Formation reservoired oils used in the study
RED RIVER
WINNIPEG
GSC Sample
Sample location
L00549 L00550 L01018 L01720 L02270 L02468 L02610 L02807 L02808 L02893 L02899 L03180 L03182
4-22-315W2 7-23-1-17W2 SW33-163N-101W2 T157N-R100W 16-03-07-11W2 07-16-06-11W2 11-16-07-07W2 16-20-06-11W2 08-16-06-11W2 08-16-06-11W2 16-20-06-22W2 11-14-07-10W2 11-14-07-10W2
Fig. 3. Representative gasoline range chromatograms of Ordovician Winnipeg and Red River Formation oils of the Williston Basin area.
Fig. 4. Representative saturate fraction gas chromatograms showing distributions of n-alkanes and isoprenoids for Winnipeg Formation and Red River Formation reservoired oils.
Fig. 5. Representative m/z 218 fragmentograms of C27, C28 and C29 steranes for Winnipeg and Red River reservoired oils in the Williston Basin area.
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5.1. Geochemistry of Winnipeg Formation oils Winnipeg Formation oils are typically high API oils (40–54 ), with a high saturate/aromatic hydrocarbon ratio (average 6.7) with the saturate+aromatic fraction combining to account for over 92% of the total oil composition. The gasoline range signature of Winnipeg oils indicates high amounts of methylhexanes exemplified by extremely high Paraffin Index 1 (PI 1) values ranging from 3.95 up to 16.64 with an average of 11.24 (Fig. 3). The saturate fraction of the Lower Ordovician Winnipeg Formation oils is characterized by a high abundance of long chain n-alkanes (C20+) and low carbon preference index (CPI) of 1.0–1.5 (Fig. 4). The n-alkane profile displays a slight odd/even predominance of nalkanes between C15–C19 with a smooth envelope from C20+ onward. In addition, these oils are associated with low concentrations of pristane and phytane and a low pristane/phytane ratio (average 1.3). The GC trace has a smooth baseline and abundance of low molecular weight n-alkanes, commonly used to indicate that the effects of biodegradation and/or water washing, were negligible (Peters and Moldowan, 1993). Sterane and terpane biomarkers appear to be quite distinct and are comparable throughout the sample set for all Winnipeg reservoired oils. Sterane biomarkers have a normalized distribution of C27 > C28C29 (45:28:27) regular steranes, based on abb isomers, as derived from the m/z 218 mass fragmentogram (Fig. 5). Terpane biomarkers have a high relative abundance of C23 and C24 triterpanes and a smooth extended hopane profile from C31–C35. Winnipeg oils typically have Ts/ Tm values greater then 1, with an average of 1.28. In addition, terpane biomarkers of Winnipeg oils show a high abundance of rearranged hopanes including an unknown C30 compound labelled UC30 (Philp and Oung, 1992; Li et al., 1999) and 17 (H) C30-diahopanes (peaks 4 and 8 in Fig. 6). Moreover, these oils have unambiguous amounts of 18 (H)-30-norneohopanes (C29Ts) (peak 7 in Fig. 6) not present in other oils found in the basin.
of C20+ n-alkanes, a high carbon preference index (CPI) (1.5–2.0), a low pristane/phytane ratio and low concentrations of acyclic isoprenoids (i.e. pristane and phytane) (Fig. 4). In addition, the GC traces show an abundance of low molecular weight n-alkanes and a smooth baseline. Sterane and hopane distributions indicate that Red River oils have a relatively high abundance of steranes and show a predominance of C29 >C27 >C28 (49:34:17) on the m/z 218 mass fragmentogram. The hopane signature for the oils shows no predominance of C23 or C24 triterpanes and Ts/Tm values are typically < 1. More importantly rearranged hopanes are not present in these oils as they are in the other Lower Palaeozoic oils.
5.2. Geochemistry of Red River Formation oils
5.3. Maturity
Oils reservoired in the Red River Formation have relatively high saturate/aromatic hydrocarbon ratios (average 2.36) with the saturate+aromatic fraction combining to account for over 78% of the total oil composition. Gasoline range parameters of Red River Formation oils exhibit very low abundance of methylhexanes, specifically 2-methylhexane and 3-methylhexane (Fig. 3). The saturate fraction of Red River Formation oils is consistent with previous studies (Longman and Palmer, 1987; Fowler, 1992). The SFGC exhibits a predominance of n-alkanes up to C19, a low concentration
Aromatic hydrocarbons were examined to determine the maturity of Winnipeg and Red River Formation oils. The Methylphenanthrene Index (MPI 1), in combination with calculated vitrinite reflectance equivalent indices (%Rc) (Radke and Welte, 1983), suggests that the Red River oils are of low maturity, equivalent to a vitrinite reflectance of 0.62%, whereas Winnipeg oils are slightly more mature with an average vitrinite reflectance equivalent of 0.82%. This is consistent with Winnipeg and Red River triaromatic sterane cracking ratios of 0.74 and 0.45, respectively, also suggesting that Winnipeg oils are more mature.
Fig. 6. Representative m/z 191 fragmentograms of Red River Formation and Winnipeg Formation oils.
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Fig. 7. Cross-plot of the normalized percentage peak area of 3-methylhexane+2, 4-dimethylpentane vs. 2-methylhexane+2, 3-dimethylpentane showing invariance of Mango K1 parameters and separation of Winnipeg and Red River oils.
6. Discussion Light hydrocarbon ratios effectively differentiate between Winnipeg and Red River Formation oils particularly using C7 ‘‘Mango’’ Parameters (Mango, 1987, 1990) and Paraffin Indices (Thompson, 1983). According to ten Haven (1996) the K1 parameter (2-methylhexane+2, 3-dimethylpentane)/(3-methylhexane+2, 4dimethylpentane), remains consistent within co-genetic oil families. Winnipeg and Red River Formation oils separate into two groups suggesting they stem from two distinct sources (Fig. 7). Despite an apparent similarity in the slope of K1, the concentration of methylhexanes is much higher in Winnipeg oils than in Red River oils (peaks 9 and 11 in Fig. 3). Moreover, high concentrations of methylhexanes provide strong evidence for the source environment, suggesting a high abundance of clastic input (Jarvie et al., 2001; Jarvie, 2001). In addition, geochemical plots of P3 versus P2+N2 (Fig. 8a) and P2 versus N2/P3 (Fig. 8b) commonly used to
determine homologous sets of oils, clearly differentiate between Winnipeg and Red River Formation oils. The application of Paraffin Indices provides a preliminary means of separating the oils into families (Fig. 9). Variations in Paraffin Indices are not totally dependent on maturity as first suggested by Thompson (1983), but are also dependent on source material and kerogen type, typically increasing in more aliphatic Type I kerogens (Obermajer et al., 1998, 2000). High PI 1 values of Winnipeg oils separate them from all the other oil families defined by Obermajer et al. (2000) for the Williston basin suggesting a unique source. According to Thompson (1983), high Paraffin Indices indicate supermature oils originating in deep basin-center locations where oils are trapped in the source, or a reservoir in close proximity, for an extended period of time and are therefore subjected to extreme thermal conditions increasing the degree of paraffinicity. This may indicate that Winnipeg oils come from an older, deeper source then Red River oils. The C15+ saturate fraction of Upper Ordovician Red River Formation oils is associated with a geochemical signature typical of kukersite source rocks containing organic matter dominated by Gloeocapsomorpha Prisca (Longman and Palmer, 1987; Fowler, 1992). The oils exhibit a predominance of n-alkanes up to C19, a low concentration of C20+ n-alkanes, a high carbon preference index (CPI) (1.5–2.0), a low pristane/phytane ratio and low concentrations of acyclic isoprenoids (i.e. pristane and phytane) (Longman and Palmer, 1987; Fowler, 1992) (Fig. 4). In contrast, Winnipeg oils appear to be ‘‘waxier’’ than Red River oils, containing a higher abundance of C20+ n-alkanes indicated by the low ratio of medium-chain to long-chain n-alkanes (Fig. 10). Jacobson et al. (1988) showed two distinct organic matter assemblages within the Red River Formation, stating that one of the assemblages had extended paraffin contents in the nC20+ range. However, it appears that neither assemblage contained the high paraffin content
Fig. 8. Cross-plot of normalized % peak areas of ‘‘Mango’’ parameters of a) P2+N2 versus P3 and b) N2/P3 versus P2 showing good separation between oil families. P2=2-methylhexane+3-methylhexane, P3=2,2-dimethylpentane+2,4-dimethylpentane+3,3 dimethylentane+2,3-dimethylpentane, N2=1,1-dimethylpentane+1c3-dimethylcyclopentane+1t3-dimethylcyclopentane.
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Fig. 9. Cross-plot of Paraffin Index 1 versus Paraffin Index 2. PI 1- (Isoheptane value)=(2-methylhexane+3-methylhexane)/ sum of 1c3-, 1t3-, 1t2- dimethylcyclopentanes; PII 2- (Heptane value)=(n-heptane100)/sum of compounds eluting between cyclohexane and methylcyclohexane.
Fig. 10. Cross-plot of Carbon Preference Index (CPI) versus the ratio of Medium-Chain (C15-C19)/Long-Chain (C20-C25) n-alkanes for Winnipeg and Red River Formation oils.
shown by Winnipeg Formation oils. High abundance of long-chain n-alkanes is typically associated with terrestrial input however because of the possible age of Winnipeg oils it is likely related to algal contributions. In addition, Winnipeg oils can be distinguished from Red River oils by lower CPI values and from other, younger oils in the basin (Osadetz et al., 1992) by low abundance of pristane and phytane and low pristane/phytane ratios. The geochemical difference between Winnipeg and Red River Formation oils is not only evident in the gasoline range and saturate fraction but extends into the biomarker fingerprints as well. Winnipeg oils exhibit a predominance of C27 over C28 and C29 steranes (Fig. 11). Bend and Seibel (2000) also noted a predominance of C27 steranes for Winnipeg oils in Saskatchewan.
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Consistent with previous observations, Red River oils show a predominance of C29 over C27 and C28 steranes representing the algal input of G. prisca (Fig. 11)(Fowler, 1992). Variation in steranes suggests that the algal source material for Winnipeg reservoired oils was different than that of Red River oils. Hopane biomarkers also effectively differentiate between Winnipeg and Red River Formation oils. Winnipeg oils have relatively high concentrations of C23 and C24 tricyclic terpanes compared to Red River oils, which according to Hunt (1996), are common in oils derived from marine and lacustrine environments. Red River oils typically have Ts/Tm values of less than 1 (Obermajer et al., 1998), whereas Winnipeg oils tend to have Ts/Tm values greater then 1 suggesting a more clastic source for Winnipeg oil (Peters and Moldowan, 1993). Although Ts/Tm values are controlled by both source and maturity, values for Winnipeg oils are believed to be source related, consistent with high concentrations of methylhexanes which also suggest high clastic input (Jarvie, 2001; Jarvie et al., 2001). The smooth C31–C35 homohopane profile of the Winnipeg oils is also typical for oils originating from clastic sources. High concentrations of rearranged hopanes found in Winnipeg oils including 17a (H)-C30 diahopanes (C*30), UC30 hopanes and 18a(H)-30-norneohopane (C29Ts) are absent in Red River oils (peaks 8, 4 and 7 in Fig. 6). High concentrations of diahopanes are to some extent related to variations in maturity since diahopanes typically have a greater degree of thermal stability than regular hopanes, therefore values can increase with increasing maturity (Moldowan et al., 1991; Obermajer et al., 2002). However, numerous studies have shown that the presence of diahopanes is influenced by the environment of deposition (Telnaes et al., 1992; Peters and Moldowan, 1993). Diahopanes have typically been associated with clay-rich source rocks deposited in suboxic to oxic conditions (Peters and Moldowan, 1993). Moldowan et al. (1991) suggested that C*30 diahopanes recognized in numerous oils along with C29Ts compounds, are derived from a common bacterial hopane precursor with variations resulting from effects of diagenesis. However, it should be noted that according to Telnaes et al. (1992), diahopane abundances co-vary with the salinity of the depositional environment and type of bacterial organisms living there, not with the presence or absence of active catalytic sites on clay minerals as previously suggested. Telnaes et al. (1992) also suggested that diahopanes are common in oils sourced in lacustrine environments. However, despite hydrogen isotope evidence of lacustrine input in Cambrian/Ordovician times within the Williston Basin (Li et al., 1999), the oils from this study do not correspond with a lacustrine source environment. Moreover, geochemical evidence (this study) and an abundance of geological evidence (Kessler, 1991; Nimegeers, 2000;
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Fig. 11. Ternary plot of the normalized distribution of C27:C28:C29 regular steranes in Winnipeg Formation and Red River Formation oils.
Seibel and Bend, 2001; Siebel, 2002) suggest that Winnipeg oils originate from a marine shale source rather than a lacustrine source. Finally, Armanios et al. (1992) believed that large abundances of diahopanes were characteristic of highly biodegraded oils, although this does not explain the existence of diahopanes in the unbiodegraded oils of the Winnipeg Formation. It is evident that tthe precise reason for high abundances of rearranged hopanes remains unresolved. However, they can be used to differentiate between compositionally different oils clearly separating Winnipeg reservoired oils from all previously defined oils in the basin. Moreover, it appears that oils reservoired in the Winnipeg formation may be related to a marine shale source.
7. Conclusion Despite their close stratigraphic proximity, it is evident that oils found in Winnipeg and Red River Formations are distinct and originate from two separate sources. The diagnostic geochemical signature of Winnipeg Formation oils is observed in the gasoline range, saturate fraction and biomarker fingerprints. The gasoline fraction of Winnipeg oils is characterized by high paraffin indices and variations in C7 parameters resulting from a high abundance of methylhexanes. The
C15+ saturate fraction of Winnipeg oils is characterized by an abundance of C20+ n-alkanes in addition to low CPI values, low amounts of pristane and phytane, and low ratios of Pr/Ph. Regular sterane biomarkers show Winnipeg oils to have a predominance of C27 >C28C29 in contrast to Red River oils which are characterized by a C29 regular sterane predominance. Winnipeg reservoired oils are also distinguishable through a combination of terpane biomarkers including high concentrations of unknown C30 compounds (UC30), 17a(H)-diahopanes (C*30) and 18a(H)-30-norneohopanes (C29Ts). In addition, Winnipeg oils have a higher abundance of C23 and C24 tricyclic terpanes and relatively higher Ts/Tm ratios than Red River oils. This preliminary work suggests that the Winnipeg oils are mature, aliphatic oils that are potentially from a clastic marine source. Although it is evident that the Winnipeg reservoired oils of the Williston Basin belong to a unique oil family, the source of these oils is yet to be determined and will be the focus of future studies.
Acknowledgements We would like to thank Sneh Achal, Rachel Robinson and Marina Milovic for their fantastic lab assistance as well as Martin Fowler, Kim Manzano-Kareah and
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Mark Obermajer for their help. Anadarko Canada is greatly appreciated for their financial support and the Geological Survey of Canada for their analytical support. We would also like to extend our appreciation to Dr. Dan Jarvie and Dr. Barry Bennett for their constructive reviews of the work.
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