Light hydrocarbon - Semantic Scholar

Organic Geochemistry 31 (2000) 959±976

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Light hydrocarbon (gasoline range) parameter re®nement of biomarker-based oil±oil correlation studies: an example from Williston Basin Mark Obermajer *, Kirk G. Osadetz, Martin G. Fowler, Lloyd R. Snowdon Geological Survey of Canada, 3303-33rd Street NW, Calgary, AB T2L 2A7, Canada Received 28 January 2000; accepted 26 July 2000 (returned to author for revision 27 April 2000)

Abstract We evaluated geochemical compositions of 189 crude oils produced from Paleozoic reservoirs across the Williston Basin. Emphasis is placed on compositional variations in the gasoline range (i-C5H12-n-C8H18) to verify the biomarkerbased classi®cation of oil families. The oils belong to four distinct compositional oil families Ð A, B, C and DÐ broadly con®ned to speci®c stratigraphic intervals. The unique character of each oil family, evident from their n-alkane and biomarker signatures, is supported by distinctive gasoline range characteristics in general, and C7 (``Mango'') parameters in particular. An invariance in the K1 parameter among oils from a single compositional group is observed for most of the oils. The K1 ratio, although relatively constant within each suite of oils, is dierent for each oil family, clearly indicating their compositional distinction. Other Mango parameters (N2, P2, P3) show a similar re¯ection of the oil families. However, while C7 parameters provide excellent evidence for distinct familial association of oils from families A, B and D, family C often overlaps with the latter two families, perhaps indicating greater genetic and source heterogeneity in the family C oils. Nevertheless, dierences in the gasoline range composition suggest that the existing biomarker-based classi®cation of oil families can be more universally applied throughout the entire Williston Basin. Moreover, because the light hydrocarbon parameters prove very useful in re®ning oil±oil correlations, routine gasoline range analysis shows good potential as a supplementary component in geochemical correlation of crude oils, especially when high levels of thermal maturity decrease the usefulness of biomarker compounds. # 2000 Elsevier Science Ltd. All rights reserved. Keywords: Light hydrocarbons; Isoheptanes; ``Mango'' parameters; Oil±oil correlation; Williston Basin

1. Introduction Although higher molecular weight biomarkers (C20± C40) are considered the best tools for oil±oil correlation studies because they provide much information regarding an oil and its source rock (Peters and Moldowan, 1993), these compounds are unstable under thermal stress and are often absent in high maturity oils/condensates (van Graas, 1990; ten Haven, 1996). In contrast, many lower molecular weight hydrocarbon compounds,

* Corresponding author. E-mail address: [email protected] (M. Obermajer).

though more susceptible to biodegradation, typically comprise a persistent fraction of oils at high maturities. Benchmark studies (Thompson, 1983; Mango, 1990; BeMent et al., 1995; Halpern, 1995; ten Haven, 1996) have suggested that gasoline range hydrocarbons also carry useful information regarding genetic associations and alteration of oils. It has been documented that the light hydrocarbon ratios have applications for oil-oil correlation studies (Mango parameters, C7-based star diagrams), provide an indication of the temperature of oil expulsion from its source (2,3-/2,4-dimethylpentane ratio), and re¯ect the stage of thermal decomposition of oil (paran indices). The application of these light hydrocarbon analyses is advantageous, not only because

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M. Obermajer et al. / Organic Geochemistry 31 (2000) 959±976

they may constitute the only compositional fraction available for analysis in oils/condensates generated late during catagenesis when sterane and terpane biomarkers are below detection limit, but also because such techniques are relatively rapid and inexpensive. Therefore, they show excellent potential and can be extremely practical for geochemical correlations of low-density crude oil/condensate fractions providing valuable information about dierences in source kerogen, depositional paeloenvironment, genetic anities and petroleum alteration, data typically obtained through more advanced analyses of biomarkers. Moreover, it has been indicated that analyses of light hydrocarbons have application in oil-source correlation studies because the lighter (C5±C8) fraction of source rock kerogen can be evaluated through thermal extraction (Jarvie and Walker, 1997; Odden et al., 1998). The main objective of the present study was to examine a suite of 189 oils produced from the Red River, Winnipegosis, Bakken and Madison reservoirs (Middle Ordovician Ð Lower Mississippian), from both the American and Canadian portions of the Williston Basin, with emphasis placed on the composition of the gasoline range hydrocarbons (C5±C8 range). These light hydrocarbon parameters, C7 in particular, are used to constrain the biomarker-based classi®cation of oil families in the Williston Basin. Mango (1987, 1990) observed a unique invariance in the relative concentration of methylhexanes and dimethylpentanes in oil, indicating that the ratio of [2-methylhexane+2,3-dimethylpentane]/[3-methylhexane+2,4-dimethylpentane], the so called K1 parameter, is relatively constant and remains around unity (i.e. 1.0). A high consistency of this ratio within a large set of oils (2000) was interpreted by Mango (1987) as an argument against a speci®c biological precursor for isoheptanes. Instead, a chemical steady-state kinetic process, with constant rates of product formation, was proposed as a mechanism for the generation of isoheptanes. However, when discussing some other parameters derived from his C7 parentdaughter transformation scheme, Mango (1990) also indicated that distinctions between some of these parameters likely re¯ect dierences in kerogen type and kerogen structure. Therefore, oils generated from the same source kerogen (homologous oils) should have similar ratios of isoheptanes and dimethylcyclopentanes. This concept was further tested by ten Haven (1996) who, based on a smaller (500) but global set of oils, concluded that K1 ratios should be consistent within cogenetic suites of oils. Although con®rming the remarkable invariance of isoheptanes, ten Haven (1996) documented that the K1 ratio is not always around 1.0, and can vary signi®cantly between homologous series of oils. Interestingly, this variance makes the K1 ratio very useful for correlating oils because ``. . .if K1 would have been constant for oils world-wide, then there would

have been no application in correlation studies. . .'' (ten Haven, 1996, p. 962). It was stressed, however, that the light hydrocarbon parameters should be used in conjunction with other, more conventional geochemical data. More recently, Wilhelms et al. (1999) indicated that kinetic fractionation model proposed by Mango (1990) was inconsistent with compound speci®c isotopic composition of C7 hydrocarbons. These authors, however, also pointed to a common precursor for most of the C7 compounds. Following these studies, C7 parameters have been applied successfully in the Williston Basin for grouping oils (Jarvie and Walker, 1997; Obermajer et al., 1998). In the present paper, a number of standard gasoline range hydrocarbon parameters are used not only to examine if they are universally applicable but also to validate and re®ne the existing biomarker-based classi®cation of oil families in the Williston Basin (Osadetz et al., 1992), and to investigate if this classi®cation is applicable throughout the entire Williston Basin. Reexamination of this classi®cation based on our new analyses will allow a much better understanding of the petroleum systems in the Williston Basin, providing a framework for appraising the future hydrocarbon potential of this basin. 2. Paleozoic oils in Williston basin Ð an overview The Williston Basin, situated on the western Canadian Shield within the interior platform structural province (Fig. 1), is a sub-circular epicratonic, preservational basin ®lled with sedimentary rocks of predominantly marine origin. These sedimentary sequences range in age from Cambrian to Tertiary reaching a maximum thickness of 5 km near the center of the basin (Williston, North Dakota). The basin is a proli®c petroleum province with numerous occurrences of oil documented throughout the Phanerozoic succession. Petroleum occurs in structural, stratigraphic and combined structural±stratigraphic traps that are often controlled by important epeirogenic basement structures such as Cedar Creek and Nesson anticlines (Clement, 1987; Gerhard et al., 1987 LeFever et al., 1987). A ®rst attempt to classify oils from the Williston Basin was made by Williams (1974) who recognized three main oil types (Table 1). Oils occurring predominantly in Ordovician and Silurian reservoirs were identi®ed as type I and attributed to sources in Middle Ordovician Winnipeg shales. type II oils, broadly corresponding to Upper Devonian, Mississippian and Mesozoic reservoirs were inferred to have a Bakken Formation source. A third group consisted of oils restricted to Pennsylvanian reservoirs and categorized as type III, with sources attributed to the Tyler Formation. Subsequent studies documented that carbon and sulphur


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Fig. 1. Map showing the location and main structural elements of the Williston Basin.

Table 1 Generalized Williston Basin oil family classi®cation schemes (modi®ed from Osadetz et al., 1994) Williams, 1974

Zumberge, 1983; Leeheer and Zumberge, 1987

Osadetz et al., 1992, 1994

Source rocks

Type III (Pennsylvanian oils) not studied

Not studied

Not studied

Tyler Fm. (Pennsyl.) Exshaw/Bakken Fm. (U. Dev.-Miss.)

Type II (Devonian, Mississippian & Mesozoic oils)

Group 2 (Mission Canyon oils)

Family E (Bakken oils) Family B (Bakken oils)

Lodgepole Fm. (L. Miss.)

Not studied

Group 4 (Nisku oils) Group 3 (Duperow oils) Group 1 (Red River oils) Group 5 (Cambrian oil)

Family C (Miss. & Jurassic oils) Family D (Winnipegosis oils) Family A (Red River oils) Not studied

Winnipeg Gr. (M. Ord.) and Bighorn Gr. (U.Ord.) unknown (?U.Cam.-Ord)

Type 1 (Ordovician-Silurian oils)

Bakken Fm. (U.Dev.-Miss.)

Winnipegosis Fm. (M.Dev.)

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isotope compositions conformed to these families and, together with other data, showed that many pools were water washed or biodegraded (Bailey et al., 1973a,b; Thode, 1981; Thompson, 1983). Based on a smaller sample set, Zumberge (1983) and Leenheer and Zumberge (1987) classi®ed crude oils from the American Williston Basin into ®ve oil groups/families (Table 1). Group 1, identical to Type 1, was recognized as unique to Ordovician petroleum systems in the American mid-continent (Longman and Palmer, 1987; Jacobson et al., 1988; Foster et al., 1989) and elsewhere (Fowler and Douglas, 1984; Foster et al., 1986; Homann et al., 1987). Group 2 oils had characteristics similar to type II, Bakken-sourced oils. No equivalent to type III was identi®ed. Instead, three other groups included high and low maturity oils from Devonian pools (groups 3 and 4, respectively) and a low maturity oil from Middle Cambrian ± Lower Ordovician Deadwood Formation (group 5). A commonly accepted model of eastern Williston Basin petroleum systems, outlined initially by Brooks et al. (1987) and then revised and more comprehensively documented by Osadetz et al. (1992, 1994) in Canada, was followed by comparable petroleum systems described from the US portion of the Williston Basin (Price and LeFever, 1994; Osadetz et al., 1995). Using combinations of terpane, steroidal and normal alkane characteristics Osadetz et al. (1992) categorized oils from the Canadian Williston Basin into four families. Family A, commonly restricted to Upper Ordovician reservoirs, had distinctive n-alkane distributions low acyclic isoprenoid/n-alkane ratios and corresponded to type I± group 1 (Table 1) with sources in Upper Ordovician Bighorn Group kukersites (Osadetz et al., 1992; Osadetz and Snowdon, 1995), and not Winnipeg shales as previously postulated (Williams, 1974; Dow, 1974). Oils with low tricyclic/pentacyclic terpane ratios but lacking gasoline range and n-alkane characteristics of the family A, typically occurring below the Three Forks Group, were classi®ed as family D. This family was further subdivided into two sub-families recognized by their distinctive stratigraphic occurrence and n-alkane/ acyclic isoprenoid composition (Osadetz et al., 1992). Oils from Winnipegosis pinnacle reefs, family D2, are distinguished from other oils occurring predominantly in Saskatchewan and Manitoba groups reservoirs, family D1. Family D2 oils were speci®cally inferred to have source rocks in the Brightholme Member of the Winnipegosis Formation, while D1 oils were inferred to have sources in Devonian strata like, but not exclusive to, those found at the contact between the Upper and Lower members of the Winnipegosis Formation (Osadetz et al., 1992; Osadetz and Snowdon, 1995). Family D was not represented in the original study (Williams, 1974), but would likely correlate with group 3, 4 and possibly group 5 oils of Leenheer and Zumberge (1987) (Table 1).

Two other families, B and C, distinguished from families A and D mainly based on terpane ratios (Osadetz et al., 1992), are found in Bakken Formation to Mannville Group reservoirs. Family B oils occur primarily in the Bakken Formation, while Family C oils are found primarily in the Mississippian Madison Group and Mesozoic strata. Both families are subdivisions of type II of Williams (1974) and group 2 of Leenheer and Zumberge (1987). Although a Bakken source was initially inferred for all these oils, it has been proposed that only family B oils are derived from Bakken Formation shales and family C oils are derived from Lodgepole Formation carbonates (Osadetz et al., 1992, 1994; Price and LeFever, 1994; Osadetz and Snowdon, 1995). Families B and C were then identi®ed in American Williston Basin by Price and LeFever (1994) who con®rmed the predominance of family C oils in the Mississippian subcrop play and the common restriction of family B oils to the Bakken Formation. More recent studies of Williston Basin petroleum systems indicated a possible existence of several petroleum sub-systems and numerous source rock intervals within Madison Group strata (Jarvie and Inden, 1997; Jarvie and Walker, 1997). Moreover, an up-to-date assessment of the Williston Basin petroleum systems provided by Jarvie (in press) documents a dominant Madison Group system with four proven and two hypothetic sub-systems, as well as functional secondary systems, such as Bakken-Lodgepole, Bakken, Duperow and Red River petroleum systems. There are oils from a few pools, distinguished by their stratigraphic occurrence and isotopic composition, that do not comply with the general classi®cation of the Williston Basin oils. These include a Cambrian Deadwood Formation oil at Newporte Field (Leenheer and Zumberge, 1987; Fowler et al., 1998) and a Beaverlodge Silurian pool on the Nesson Anticline (Downey, 1996). Therefore, there is a possibility that a major, currently unrecognized petroleum system (or systems) operates in the lower Paleozoic strata across the Williston Basin. More recently, Obermajer et al. (1999) indicated that oils occurring in the Upper Devonian Birdbear Formation reservoirs in Saskatchewan have a distinctive geochemical composition and should be separated from family D Winnipegosis oils, with which they were formerly grouped (Osadetz et al., 1992). 3. Analytical techniques The gasoline range hydrocarbons (i-C5H12±n-C8H18) were analysed on a HP5890 gas chromatograph connected to an OI Analytical 4460 Sample Concentrator. A small amount of the whole crude oil was mixed with deactivated alumina and transferred to the sample concentrator. The gasoline fractions were then passed onto


the gas chromatograph equipped with a 60m DB-1 fused silica column. The initial temperature was held at 30 C for 10 min and then programmed to 45 C at a rate of 1oC/min. The ®nal temperature was held for 25 min. The eluting hydrocarbons were detected using a ¯ame ionization detector. An aliquot of the fraction boiling above 210 C was deasphalted by adding an excess of pentane (40 volumes) and then fractionated using open column liquid chromatography. Saturated hydrocarbons were

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analysed using gas chromatography (GC) and gas chromatography±mass spectrometry (GC±MS). A Varian 3700 FID gas chromatograph was used with a 30 m DB-1 column coated with OV-1 and helium as the mobile phase. The temperature was programmed from 50 to 280 C at a rate of 4 C/min and then held for 30 min at the ®nal temperature. The eluting compounds were detected and quantitatively determined using a hydrogen ¯ame ionization detector. The resulting gasoline range (GRGC) and saturate fraction chromatograms (SFGC)

Fig. 2. Generalized Paleozoic stratigraphy in the Williston Basin.

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were integrated using Turbochrom software. ``Mango'' parameters were calculated using the normalized percentage peak area from GRGC's instead of the weight percentage abundance in the whole oil as originally applied by Mango (1987). Single ion monitoring GC±MS experiments were performed on a VG 70SQ mass spectrometer with a HP gas chromatograph attached directly to the ion source (30 m DB-5 fused silica column used for GC separation). The temperature, initially held at 100 C for 2 min, was programmed at 40 C/min to 18 C and at 4 C/min to 320 C, then held for 15 min at 320 C. The mass spectrometer was operated with a 70 eV ionization voltage, 300 mA ®lament emission current and interface temperature of 280oC. The instrument was controlled by an Alpha Workstation using Opus software. Terpane and sterane ratios were calculated using m/z 191 and m/z 217 mass fragmentograms. 4. Results and discussion Most of the analyzed oils are paranic in nature as they contain a high proportion of hydrocarbons in fraction boiling above 210 C. In general, the combined amounts of hydrocarbon fractions are higher in samples collected from the pools located in the southern (US) portion of the Williston Basin, often reaching values of more than

95%. The proportion of hydrocarbons is typically lower in oils from the northern (Canadian) part of the Williston Basin, although in most of the family D and some of the family B oils this parameter is often greater than 90%. Lower values (