Directory UMM :Data Elmu:jurnal:O:Organic Geochemistry:Vol31.Issue10.Oct2000:

Organic Geochemistry 31 (2000) 959±976
www.elsevier.nl/locate/orggeochem

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 di€erent 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, di€erences 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: mobermaj@nrcan.gc.ca (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 (paran indices). The application of these light
hydrocarbon analyses is advantageous, not only because

0146-6380/00/$ - see front matter # 2000 Elsevier Science Ltd. All rights reserved.
PII: S0146-6380(00)00114-5

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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 di€erences in source kerogen, depositional
paeloenvironment, genetic anities 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 di€erences 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

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

961

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)
Family C
(Miss. & Jurassic oils)
Family D
(Winnipegosis oils)

Lodgepole Fm. (L. Miss.)

Family A
(Red River oils)
Not studied

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

Not studied

Type 1
(Ordovician-Silurian oils)

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

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

Winnipegosis Fm. (M.Dev.)

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

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; Ho€mann 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

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

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

963

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

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.

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 (