Mark Obermajer

Hydrogen isotopic compositions of individual alkanes as a new approach to petroleum correlation: case studies from the Western Canada Sedimentary Basin

Isotopic compositions of carbon-bound hydrogen in individual n-alkanes and acyclic isoprenoid alkanes, from a number of crude oil samples, were measured using gas chromatography-thermal conversion-isotope ratio mass spectrometry. The precision of this technique is better than 3‰ for most alkanes, compared to the large range of δD variation among the samples (up to 160‰). The oils were selected from major genetic oil families in the Western Canada Sedimentary Basin, with source rocks ranging in age from Ordovician (and possibly Cambrian) to Cretaceous. The hydrogen isotopic composition of alkanes in crude oils is controlled by three factors: isotopic compositions of biosynthetic precursors, source water δD values, and postdepositional processes. The inherited difference in the lipids biosynthetic origins and/or pathways is reflected by a small hydrogen isotopic variability within n-alkanes, but much larger differences in the δD values between n-alkanes and pristane/phytane. The shift toward lighter hydrogen isotopic compositions from Paleozoic to Upper Cretaceous oils in the WCSB reflects a special depositional setting and/or a minor contribution of terrestrial organic matter. The strong influence of source water δD values is demonstrated by the distinctively lower δD values of lacustrine oils than marine oils, and also by the high values for oils with source rocks deposited in evaporative environments. Thermal maturation may alter the δD values of the alkanes in the oil to some extent, but secondary oil migration does not appear to have had any significant impact. The fact that oils derived from source rocks that could be of Cambrian age still retain a strong signature of the hydrogen isotopic compositions of source organic matter, and source water, indicates that δD values are very useful for oil-source correlation and for paleoenvironmental reconstructions.

Depositional Environment and Oil Generation in Ordovician Source Rocks from Southwestern Ontario, Canada: Organic Geochemical and Petrological Approach

The Ordovician Trenton Group (Sherman Fall and Cobourg formations) and the Lindsay (Collingwood Member) and Blue Mountain formations of southwestern Ontario were examined using Rock-Eval pyrolysis, gas chromatography, gas chromatography-mass spectrometry, and incident-light microscopy to evaluate their paleodepositional environments, thermal maturities, and source rock potential. All units contain sufficient amount of oil-prone (type II), predominantly marine organic matter to be considered as petroleum source rocks. Unstructured bituminite with varying proportions of unicellular alginite are the dominant dispersed organic matter macerals. The bituminite typically occurs in massive to laminated, granular or patchy populations that commonly show microtextural relationships. Persistent inclusions of Leiosphaeridia telalganite demonstrate that planktonic algal debris was a primary organic substrate for blooming microbes. Disseminated coccoidal Gloeocapsomorpha prisca is found in minor amounts, usually in association with common to abundant acritarchs. Zooclasts (chitinozoa, graptolites, scolecodonts) and solid bitumen also are present as maceral inclusions within the bituminite network. The biomarker distributions for all of the studied units are those expected for marine organic matter deposited in a clastic-dominated environment. The extracts are characterized by a smooth n-alkane profile, with low abundance of C20+ members, typical for marine derived organic matter. Pristane/phytane ratios range from 0.97 to 1.72, indicating dysoxic conditions during deposition. Smooth C31-C35 homohopane profiles, Ts/Tm ratios (typically above 1.0), and a higher concentration of diasteranes relative to regular steranes all appear to indicate the clay-bearing character of these rocks. The predominance of C30 hopane over C29 regular sterane is interpreted to reflect a primary microbial input and extensive reworking of the organic matter. Optical (reflectance, fluorescence) and geochemical (Tmax, biomarker data) thermal maturity parameters indicate that the Trenton and Blue Mountain strata are within the zone of prolific oil generation throughout the whole area of study. The Collingwood shales are mature with respect to petroleum generation in the eastern part (Toronto area) and only marginally mature in the northern part (Georgian Bay area) of the study area. In general, the biomarker composition of the extracts from all examined units is compatible with that of the oils found in the Trenton reservoirs of southwestern Ontario; however, geochemical and geological evidence suggests that the organic-rich shaly laminae within the Trenton Group are the principal source of these oils. Accumulation of organic carbon in the Ordovician sediments of southern Ontario is suggested to derive from low-energy, normal-marine environments grading from shallow-shelf into deep-shelf and open-basinal settings. The nutrient availability and, consequently, higher bioproductivity, more intense consumption of oxygen, and progressing anoxia, controlled by a low-latitude location, diminished water circulation, stratification of the water column, and a depressed pycnocline resulted in high preservation rates. The amorphous nature of kerogen reflects significant microbial interaction at the water/ sediment interface and within the sediments where reducing conditions must have periodically predominated.

Bakken/Madison petroleum systems in the Canadian Williston Basin. Part 2: molecular markers diagnostic of Bakken and Lodgepole source rocks

Abstract The uppermost Devonian-Mississippian Bakken Formation black shale and the Mississippian Lodgepole Formation carbonate represent two of the most important source rocks in the Canadian Williston Basin. Quantitative analyses of both saturated and aromatic hydrocarbon fractions reveal significant differences in the relative distributions and absolute concentrations for a wide range of molecular markers between the extracts of the two source units. Among others, the Bakken shales are characterized by their high relative abundance of trimethyl aryl and diaryl isoprenoids likely derived from green sulfur bacteria Chlorobiaceae. In contrast, the Lodgepole carbonates at similar maturity levels display a C35 homohopane prominence and abundant benzohopanes, ring-D monoaromatic 8,14-secohopanes and a tetracyclic monoaromatic hydrocarbon. The distinctive nature of molecular marker “fingerprints” diagnostic of the two source rocks is clearly related to their different organic inputs and depositional environments. Additionally, the large difference in the absolute concentrations of these compounds observed in both source units may potentially lead to biased geochemical interpretations if strictly conventional, saturate-based biomarker approaches were used for oil-oil and oil-source correlation.

Geochemical characterisation of Middle Devonian oils in NW Alberta, Canada: possible source and maturity effect on pyrrolic nitrogen compounds

Abstract Molecular geochemical compositions of a suite of Middle Devonian sourced and reservoired oils from the Rainbow–Zama–Shekilie sub-basins in N.W. Alberta, Canada, reveal the presence of at least two oil families in the study area. The distribution of each oil family is geographically restricted to a single sub-basin, consistent with the oils being sourced locally within a series of closed generation/migration/trapping systems. The diversity in the biomarker distributions of the oils indicates the wide range of depositional environments and source materials existing in each sub-basin, rather than mixing of end member oils across different sub-basins. Clear maturity differences are observed between the oils from the Rainbow and Zama subbasins. Pre-Cretaceous thermal anomalies along the reactivated regional Precambrian basement faults are proposed as one of the major causes for the relatively high maturity levels for the Middle Devonian source rocks in the study area. We infer that depositional environment and thermal maturity have had a strong impact on the geochemical characteristics of the saturated and aromatic hydrocarbons in the Rainbow–Shekilie–Zama oils, but may not influence the pyrrolic nitrogen compounds to a significant extent. However, recognition of possible source and maturity effects on pyrrolic nitrogen compounds in other studies suggests that these factors should be considered before the pyrrolic nitrogen compounds are used to characterize petroleum migration.

Delineating compositional variabilities among crude oils from Central Montana, USA, using light hydrocarbon and biomarker characteristics

Abstract Three compositionally distinctive groups of oils identified in central Montana by biomarker analyses are also recognized by the unique compositions of their light hydrocarbon (gasoline range) fraction. The majority of oils produced from Paleozoic pools (Pennsylvanian Tyler–Amsden interval) group into one broad category based on the distribution of C 20 –C 40 biomarkers. These oils not only have the lowest Paraffin Indices and relative concentrations of normal heptane, but are readily distinguishable from the other compositional groups by using selected “Mango” parameters. However, the biomarker-based subdivision of this group into at least two sub-families is not reflected in the gasoline range fraction, suggesting little effect of source rock host lithology on the distribution of C 5 –C 8 hydrocarbons. Oils occurring predominantly in Jurassic–Cretaceous reservoirs display different biomarker and gasoline range characteristics, including Paraffin Indices, K1 parameter and relative concentrations of C 7 compounds, and are classified in two separate compositional categories. In contrast to oils from the Tyler–Amsden interval, the oils produced from the Mesozoic strata are amongst the most mature oils in the study area. The unique biomarker/light hydrocarbon signatures are likely due to different source organic matter. Secondary alteration of oil due to biodegradation and migration, although recognized, appears less significant. The results indicate the overall usefulness of gasoline range compositions in delineating compositional affinities of crude oils in central Montana, clearly suggesting that the oils found in Paleozoic and Mesozoic reservoirs belong to different petroleum systems.

Application of acritarch fluorescence in thermal maturity studies

The relative fluorescence of acritarchs (400-700 nm range) was investigated as an alternative technique of determining the level of thermal maturity of marine Paleozoic source rocks in Canada. The sedimentary strata examined include the Blue Mountain, Lindsay (Collingwood Mbr), Guelph (Eramosa Mbr) and Marcellus formations from southern Ontario, Yeoman and Winnipegosis formations from Saskatchewan, as well as the Manitoba and Elk Point groups from Saskatchewan and Alberta, respectively. The examined strata contain oil-prone, predominantly marine organic matter (Type II and I kerogen) with varying proportions of bituminite and alginite as the dominant maceral components. Acritarchs, which occur as persistent maceral inclusions within such organic facies, show excellent potential in thermal maturity estimations. The fluorescence of acritarchs shows a progressive red shift throughout the initial and main stages of oil generation with a trend parallel to that of alginite. However, as a result of their lower sensitivity to increasing burial temperature, the Amax and Q values of acritarchs are lower than the corresponding Amax and Q of Gloeocapsomorpha prisca and Leiosphaeridia alginite, with the difference becoming more pronounced with increasing thermal maturity. Correlations with optical and geochemical maturity indicators, such as reflectance of chitinozoa (%ChR o ), bitumen (%BR o ) and vitrinite (%VR o ), Rock-Eval Tmax and the isomerization ratio of regular steranes (S/[S + R], ββ/[αα + ββ]), indicate that in kerogen Type II organic matrix both Amax and Q values of acritarchs vary little until the onset of oil generation. At this maturity level, corresponding to VR o < 0.5% and Tmax < 435°C, Amax values are commonly 450 nm or less whereas Q is below 0.5. Within the zone of the initial phase of oil generation the Amax shows a steady increase to 480 nm, and then a more rapid raise throughout the oil window (520-550 nm). These changes in Amax are not accompanied by a meaningful increase in Q values which, in general, remain around 0.5. In kerogen Type I organic matrix no significant variations in Amax and Q have been observed up to a maturity level corresponding to VR o ≤ 1% and Tmax up to 460°C.

Chapter 38 Thermal maturity of the Sverdrup Basin, Arctic Canada and its bearing on hydrocarbon potential

Abstract Analysis of a large thermal maturity dataset indicates that the Carboniferous to Eocene Sverdrup Basin in the Canadian Arctic had a uniform response to thermal stress with depth for Mesozoic strata. Thermal maturity was established at the level of the widespread Upper Triassic Gore Point Member; a good seismic reflector, occurring in close vertical proximity to the two main oil-prone source rocks in the basin. The Gore Point Member is in the gas window (Ro>1.35%) in the northeastern part of the Sverdrup Basin, whereas in the western Sverdrup Basin its maturity does not exceed 1.2% Ro. This would support the hypothesis that large quantities of gas found at the Drake, Hecla and Whitefish fields have derived from a deeper source, probably in Permian or lower Palaeozoic strata. A normal burial curve is established using boreholes drilled in areas with no structural complexity at time of maximum burial. Low-amplitude structures, including the Drake, Hecla and Whitefish fields, show little or no uplift following maximum burial in the Paleocene, indicating that these structures formed prior to the Eocene folding related to the Eurekan Orogeny. Because they were present at the time of maximum burial, they were available to be charged during hydrocarbon migration. In contrast, high-amplitude structures show evidence of large uplifts following maximum burial. They formed in the Eocene and hence post-date most hydrocarbon migration.

Rhenium–osmium geochronology and oil–source correlation of the Duvernay petroleum system, Western Canada sedimentary basin: Implications for the application of the rhenium–osmium geochronometer to petroleum systems

The Re–Os geochronometer has been applied to many petroleum systems worldwide. However, it is debated if the Re–Os systematics in petroleum actually record the timing of oil generation. Here, we investigate the Re–Os isotope systematics of the Duvernay petroleum system in the Western Canada sedimentary basin, which has been shown to be a relatively simple petroleum system that is associated with oil generated during the Late Cretaceous–early Eocene Laramide orogeny from a single source. The organic geochemistry of the Duvernay oils (pristane/phytane ratios of ∼1.5, smooth homohopane profile, C29 > C27 > C28 regular sterane distribution, and predominance of diasteranes over regular steranes) strongly suggests the oil source to be that of type I–II marine organic matter of the Upper Devonian Duvernay Formation. The asphaltene fraction Re–Os isotope data of the Duvernay oil yield an age of 66 ± 31 Ma, which is in excellent agreement with the timing of the main-stage hydrocarbon generation of the Duvernay Formation based on basin models. Further, the similarity between the 187Os/188Os compositions of the Duvernay Formation source rock (0.46–1.48) and the oil (0.55–1.06) at the time of oil generation supports the hypothesis that the 187Os/188Os composition of an oil is inherited from the source unit at the time of oil generation and therefore shows no, or limited, influence from interaction with basin fluids. This study supports that the Re–Os isotope systematics of an oil can yield the timing of oil generation and be used to trace its source.