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The main controls on petroleum accumulations in sedimentary basins include source rock distribution, thermal maturity, migration pathways, as well as structural and stratigraphic traps. While shale plays and conventional reservoirs are endmembers governed by contrasted geological processes, unconventional hybrid systems represent a continuum between them and share common characteristics with both. The Montney Formation provides a well-documented example of such a play, where petroleum distribution is controlled by a combination of downdip increase of thermal maturity, fluid migration influenced by lateral and vertical permeability variations, and pressure compartmentalization. In this paper, we integrate publicly available data from thousands of wells within a well-defined stratigraphic framework, to illustrate these regional and local controls on petroleum distribution in the Montney hybrid play. We demonstrate that produced gas compositional mapping is a powerful tool that complements comparatively sparse data from core or cuttings-based organic geochemistry and petrography methods, to provide an unparalleled level of detail of petroleum distribution at various scales. Coupling this compositional mapping with reservoir pressure data and published faults reveals a strong control of the structural framework on petroleum migration routes. The main targets of horizontal drilling in the Montney play are carrier beds that were charged by up-dip migrating petroleum and experienced further thermal maturation during the burial history. The relative contribution of different source rocks to this petroleum system remains speculative and further investigation is needed to solve this conundrum.

Significant reserves of oil and gas have been predicted for Hecate Strait, a pristine, semi-enclosed sea on the continental shelf adjacent to British Columbia, on the west coast of Canada. To establish a baseline for the natural background of hydrocarbons in sediment prior to any further offshore oil and gas development or increase in oil tanker traffic in the Hecate Strait region, three sediment box cores were collected along a west to east transect across southern Hecate Strait in September 2003. 210 Pb measurements established that the bottom sections date to ∼1920, pre-1800 and ∼1870, respectively, which predate any significant industrial development on the coast. Alkane and polycyclic aromatic hydrocarbon (PAH) concentrations are low in most sediment samples and both the concentrations and fluxes differ little between surface and bottom core sections. PAH profiles exhibit a dominance of alkyl PAHs for each alkyl PAH homologous series with varying amounts of parent (unsubstituted) PAHs, while alkane chromatograms show no unresolved complex mixture (UCM), and there is little change in composition between present day and pre-1800 sediments for most parameters. Principal components analysis (PCA) models, and PAH and biomarker ratios indicate that composition patterns are consistent with low and varying natural petrogenic and pyrogenic inputs, with little or no anthropogenic input. The most likely primary source of petrogenic PAHs to the sediments is Cenozoic lignites from the Skonun Formation, which outcrops on Haida Gwai and underlies most of Hecate Strait. Two subsurface sections (deposited in ∼1990 and ∼1930) in the core from Milbanke Sound, on the east side of the transect, have elevated concentrations for the alkyl phenanthrene/anthracenes and dibenzothiophenes with no UCM, and most likely also have a source in immature coal. This study suggests that the Hecate Strait environment has low hydrocarbon concentrations, with an apparent minor role for oil seeps and a likelihood that most of the petrogenic PAH sources are shales or immature coals with limited PAH bioavailability. If these characteristics are representative of Hecate Strait sediments overlying the Queen Charlotte Basin, it may mean that biota are likely unadapted to the presence of oil and thus would be more sensitive to exposure to oil from an oil spill than those in a more impacted environment.

Geochemical analysis shows that oil from Devonian reservoirs at Bent Horn field in the Canadian Arctic Archipelago is non-biodegraded and has a maturity corresponding to the mid-late part of the oil window. It is characterized by a smooth n-alkane profile, low concentration of acyclic isoprenoids and saturated hydrocarbon biomarkers, with some variability in sterane composition. Compared with oil from Mesozoic strata of the Canadian Arctic Islands, the Bent Horn oil shows higher paraffin indices and aromatic hydrocarbon maturity indicators (MPI, MDR), dominant tricyclic terpanes and different distribution of regular steranes. Geological evidence suggests a Paleozoic source rock for the oil. Rock–Eval pyrolysis and total organic carbon (TOC) data indicate good source rock potential for the Silurian basinal facies and Upper Silurian–Lower Devonian clastics of the Boothia Uplift. These intervals are enriched in Type II oil-prone organic matter (commonly 2.0–5.0% TOC, maximum 13.6%) and are mature with respect to petroleum generation. Based on preliminary biomarker analysis, maturity, and stratigraphic and geographic proximity to the Bent Horn oil field, the Cape Phillips Formation appears to be the most likely source rock for the hydrocarbon accumulation at Bent Horn.

Whitehorse trough is a frontier basin in south-central Yukon that is thought to contain gas and possibly oil. It consists of up to 7000 m of sedimentary and volcanic rocks referred to as the Lewes River Group (Triassic), Laberge Group (Jurassic), and Tantalus Formation (Jura-Cretaceous). The Lewes River Group is informally subdivided into the Povoas and Aksala formations, and the Laberge Group is informally subdivided into the Richthofen, Nordenskiold and Tanglefoot formations. To evaluate the petroleum source-rock potential of this basin, over 600 samples from the Aksala, Richthofen, Tanglefoot and Tantalus formations from throughout the trough have been analyzed by Rock-Eval programmed pyrolysis and combustion and by study of thermal alteration indicies (TAI) of palynomorphs, conodont alteration indicies (CAI), and vitrinite reflectance. The Povoas and Nordenskiold formations were not sampled because they consist of volcanic and volcaniclastic rocks, respectively, and have no source rock potential. The analyses indicate that the Aksala formation is a poor source rock that is postmature with no hydrocarbon potential. The Richthofen formation is a poor source rock that is postmature with minor gas potential. The Tanglefoot formation is a good source rock that is immature to early mature and gas-prone. The Tantalus Formation is also a good source rock that is immature to early mature and gas-prone. The Tanglefoot and Tantalus formations contain petroleum fluid inclusions that were probably generated from within these units. The inclusions reveal homogenization temperatures of mostly between 75–115°C and reveal several distinct, but minor pulses of liquid petroleum (mainly 19–21°API, 23°–35°API and 40–46° API). Potential petroleum (gas) generative intervals occur at surface and in the shallow subsurface in deltaic mudstones (Tanglefoot formation) and fluvial mudstones (Tantalus Formation). The lateral extent of these intervals is unknown due to poor outcrop exposure and limited shallow drilling. Both the Tanglefoot and Tantalus formations are interpreted as potential source rocks and possibly effective source rocks. The most prospective areas for petroleum exploration are Five Finger Rapids, Division Mountain and Tantalus Butte and in the northern portion of Whitehorse trough.

Examining a well-documented case history in Western Canada sedimentary basin using two-dimensional gas chromatography (GC × GC) has produced a useful tool for fingerprinting thermochemical sulfate reduction (TSR)-affected petroleum fluids. Application of the approach and data interpretation strategies to the northeastern Jinxian Sag of Bohai Bay Basin has provided molecular evidence for TSR as a plausible source for the H2S in the gases associated with the studied oils.

Analysis of 12 worldwide oil samples show that Re and Os abundances are positively correlated with the asphaltene content of oil. Light oils with 83%), with

The principal controls on the fluid properties of biodegraded oil systems have been determined by a combination of petroleum geochemistry, numerical modeling of oil biodegradation in reservoirs, and analysis of oil property data sets from a variety of geological settings. Petroleum biodegradation proceeds under anaerobic conditions in any reservoir that has a water leg and has not been heated to temperatures more than 80C. In most reservoirs with low concentrations of aqueous sulfate, methanogenic degradation is a primary mechanism of petroleum degradation, whereas in waters containing abundant sulfate, sulfate reduction and sulfide production may dominate. Net degradation of petroleum fractions in reservoirs is primarily controlled by the reservoir temperature, the chemical compounds being degraded, and relationships between the oil-water contact (OWC) area and oil volume. The relative volumes of water leg to oil leg, prior level of oil biodegradation, and reservoir water salinity act as second-order controls on the process. Typically, degradation fluxes (kilograms of petroleum destroyed per square meter of oil-water contact area per year or kg petroleum m2 OWC yr1) for fresh petroleum in clastic reservoirs are in the range of 103–104 kg petroleum m2 OWC yr1 and increase with decreasing reservoir temperature, from zero near 80C, to a maximum flux at the OWC of less than 103 kg petroleum m2 OWC yr1 at a temperature less than 40C. At very low reservoir temperatures and with severely degraded oils, such as are seen in the near-surface Canadian tar sands at the present day, the net degradation fluxes are much less than maximum values. Nutrient supply from the aquifer and adjacent shales, mostly buffered by mineral dissolution, probably provides the ultimate control on the range of degradation flux values. Oil compositional gradients and resulting oil viscosity variations are common on both reservoir thickness and field scales in biodegraded oil reservoirs and are a defining characteristic of heavy oil fields produced by crude-oil biodegradation. Continuous vertical gradients in the oil columns document episodic degradation for many millions of years, suggesting that the time scales of oil-field degradation and petroleum charging are similar. The flux-temperature relationship we have derived, coupled with typical reservoir charge histories, defines the range of variation of fluid properties seen in many biodegraded oil provinces and identifies oil charge, mixing of biodegraded and fresh oils, and reservoir-temperature history as the primary controls on fluid properties. These flux-temperature relationships are easily integrated into prospect charge modeling procedures; sensitivity analyses show that the limiting factor in fluid property predictions, using even this first-level approach, are ultimately constrained by the accuracy of current oil-charge modeling estimates. The absence today of any functional geochemical proxies for assessing oil-residence time in oil fields and the substantial uncertainty in petroleum-charging times estimated by forward basin modeling is a major obstacle to more accurate fluid-property predictions that needs to be addressed.

Bitumens of the Alberta tar sands share a similar primary source rock, but exhibit varying levels of degradation. In the Peace River tar sands area, the wide range of API gravity and sulphur content in Lower Cretaceous reservoirs is investigated in terms of biodegradation processes, using detailed geochemical analyses, burial history modelling and charge/degrade modelling. Decreasing tar sand degradation to the west can be attributed to increasing reservoir temperatures which retard biodegradation. Gething oils west of the Peace River tar sands are derived from the same source, but are minimally degraded due to reservoir pasteurization at 80 °C shortly after charging. Long charge times, reservoir filling and possibly compositional or very low temperature degradation retardation have limited biodegradation of the Alberta tar sands despite long oil residence times and low reservoir temperatures.

Re–Os analyses of bitumen from the Polaris Mississippi Valley-type Zn–Pb deposit demonstrate the potential utility of the Re–Os system for establishing the absolute timing of hydrocarbon migration and generation. The Polaris deposit is hosted by carbonate rocks of the Upper Ordovician Thumb Mountain Formation, and sulphide mineralization during Late Devonian time is constrained by a Rb–Sr sphalerite date of 366 ± 15 Ma and a paleomagnetic date. Bitumen occurs in open-space fillings and coatings, and is interpreted to have formed during the main and late stages of sulphide mineralization. Samples of bitumen were taken from a variety of locations from the main deposit at Polaris; Re and Os contents are ∼ 3–78 ppb and ∼ 55–1155 ppt, respectively. The 187Re/188Os ratios are very high, ranging from ∼ 300 to 1800, and the Os isotopic composition is moderately to highly radiogenic, with 187Os/188Os ratios ranging from ∼ 3.3 to 13.7. Calculated 187Os/188Os ratios at 366 Ma are variable, but an obvious grouping is defined by 11 of 16 analyses on a Re–Os isochron diagram, and these data yield a Re–Os date of 374 ± 9 Ma (MSWD = 12, Model 3), in agreement with Rb–Sr sphalerite and paleomagnetic dates for mineralization at Polaris. The combined dates suggest that the migration of fluids responsible for both Pb–Zn mineralization and bitumen formation at Polaris was broadly contemporaneous, and was coeval with the Late Devonian Ellesmerian Orogeny. Though considerable further research is required to understand the Re–Os isotopic systematics of migrated hydrocarbon systems, bitumen Re–Os geochronology may provide the possibility of establishing a more comprehensive understanding of MVT deposits, sedimentary basin and petroleum systems.

The Whitehorse Trough is an early Mesozoic marine sedimentary basin, which extends from southern Yukon to Dease Lake in British Columbia. This paper outlines the stratigraphy and structure, and characterises the overall petroleum resource potential of the central Whitehorse Trough. Strata within the central Whitehorse Trough include carbonate rocks of the Upper Triassic Sinwa Formation, and interbedded sandstone, siltstone and argillite of the Lower Jurassic Inklin Formation. The central Whitehorse Trough is structurally dominated by a Middle Jurassic southwest-vergent fold and thrust belt. Programmed pyrolysis data indicate that potential source rocks in the Inklin Formation are gas-prone, and, along the northeastern flank of the central Whitehorse Trough, are within the oil and gas window. Variably tuffaceous feldspathic arenites in the Inklin Formation have fair to good reservoir characteristics, but are a minor component of the stratigraphy. Potential petroleum traps are provided by antiforms, thrust faults and stratigraphic pinch-outs. Three conceptual gas plays for the central Whitehorse Trough are proposed: (1) the Sinwa Structural Gas Play; (2) the Inklin Structural Gas Play; and (3) the Inklin Stratigraphic Gas Play. The Inklin Structural Gas Play presents the greatest potential in the central Whitehorse Trough because levels of organic maturation along the northeastern flank of the basin are favourable and structural traps are readily identifiable. This prospective belt of strata may extend to the northeast beneath the structurally overlying Cache Creek terrane.

Petrographic analyses of dispersed organic matter (including macerals and palynomorphs), siliceous and calcareous microfossil assemblages and microtextures (e.g. stromatolitic) have been used to define and interpret five organic facies and regionally map their distribution for the following informal groupings of potential hydrocarbon source rocks in the Western Canada Sedimentary Basin: Upper Devonian Woodbend group, Upper Devonian Winterburn group and Upper Devonian to Lower Mississippian black shales of the Exshaw and Bakken formations. Five petrographic organic facies (A–E) are defined for the potential source rocks based on assemblages of alginites, acritarchs, sporinites, siliceous microfossils and algal mat microtextures. Organic facies A, B (prasinophyte alginites and acritarchs) and C (coccoidal alginite), represent accumulation in relatively deep (basin), intermediate (shelf-platform), and shallow water depths (bank-reef margin to lagoonal). Organic facies D is defined by siliceous microfossils (e.g. Radiolaria) and accumulated in deep basinal to outer shelf settings immediately east of an ancient Pacific Ocean, or south of an ancient Arctic Ocean. This facies may reflect regions of upwelling which extended into intracratonic and epicontinental settings. Organic facies E, characterized by stromatolitic microtextures with or without coccoidal alginite, only occur within Upper Devonian Winterburn Group shallow water, restricted shelf to lagoonal dolostones associated with evaporites. As a whole, the regional distribution of organic facies is related to paleogeography, paleobathymetry or paleostructure in the source rocks. Surprisingly, petrographic organic facies do not show strong positive correlation with kerogen type as defined by Hydrogen-Oxygen indices or TOC-S2 plots.

The formation and composition of natural gas generated from the Duvernay Formation was simulated by heating immature kerogens in a closed system (MSSV pyrolysis) at three different heating rates (0.1, 0.7 and 5.0 °C/min). It was not possible to evaluate reasonable kinetic parameters for the formation of single compounds using accepted protocols, because even at the highest pyrolysis temperatures there is still methane formation, while ethane and propane formations show a significant heating rate dependency of their maximum yields. To circumvent these obstacles a new method was developed utilising the following observations: (1) bulk gas fraction C 1−5 does not show any heating rate dependency of its maximum yield, (2) omitting either ethane or propane, the generation of both of which are heating rate dependent, from the total gas fraction (which gives the C 1−5 − C 2 as well as C 1−5 − C 3 ) resulted in yields which were not heating rate-dependent. Thus, the kinetic evaluation for these fractions is valid and could be used to predict the formation of the bulk fractions for geological heating rates. By calculating the difference of C 1−5 and C 2−5 , C 1−5 − C 2 as well as C 1−5 − C 3 , it was possible to predict the temperatures of methane, ethane and propane formation under geological conditions. Methane was predicted to represent 60–70 mol% of the natural gas formed from the Duvernay Formation with an onset temperature of 120 °C for a geological heating rate of 3 °C/my. Ethane and propane were predicted to represent 20 and 10 mol% of the Duvernay gas, respectively. The onset of ethane and propane formations was predicted to take place at 130 °C. Interestingly, using this concept the composition of gas formed from the Duvernay Formation can be predicted very well and fits to reservoired Duvernay gas in petroleum accumulations along the Rimbey–Leduc–Meadowbrook Reef System, which was formed during the main phase of petroleum formation.

Organic-rich intervals within the Late Devonian Camrose Member of southern Alberta, Canada show optical and chemical characteristics very similar to those of Ordovician samples whose organic matter is dominated by Gloeocapsomorpha prisca-derived alginite. This includes saturate fraction gas chromatograms dominated by n-alkanes with a pronounced odd carbon number up to C19, and much lower abundances of C19+n-alkanes, acyclic isoprenoids and biomarkers. Microscopy reveals these samples contain G. prisca-like alginite with a morphology that previously has been suggested for the growth of this organism under higher salinity conditions which is in agreement with the depositional environment of the Camrose Member. One unusual feature of the G. prisca-rich samples is the very high concentration of C21 and C23n-alkylnaphthalenes and n-alkylbenzenes in the aromatic fractions of their extracts. The origin of these compounds is not known but their occurrence could be related to the high concentrations of C21 and C23n-alkyl phenols that have been noted in pyrolysates of Estonian kukersites by previous workers. Other Camrose Member extracts show very different distributions that are more typical for carbonates deposited under anoxic, higher salinity conditions. Many oils that occur in Nisku Formation reservoirs in the Enchant-Hays field in southern Alberta show saturate fraction gas chromatograms and other evidence that indicate an important contribution to these oils from the G. prisca-rich intervals. These are thought to have a contribution from Camrose Member source rocks. Hence, caution should be used in only attributing G. prisca geochemical characteristics to Cambro-Ordovician oils as, on rare occasions, they can also occur in younger source rocks and their derived oils.

Heavy crude oils occurring in the Mississippian Bakken and Lower Cretaceous Mannville reservoirs in west-central Saskatchewan display variable geochemical composition in their light (C 5 -C 8 ) and medium (C 12 -C 30 ) molecular weight fractions. All oils show a depletion of normal alkanes, and to a lesser extent acyclic isoprenoids, which appears to increase progressively southward. As biodegradation seems to be the primary control of the n-alkane distributions, it appears that oils produced from deeper reservoirs in the south are more biodegraded than the oils in shallower Mannville reservoirs in the north. However, several other compositional characteristics, including gasoline range and aromatic fractions, are inconsistent with the trend in biodegradation defined by the relative n-alkane abundance. Oils from the shallower northern reservoirs are enriched in cycloalkanes, show lower relative concentrations of isoheptane, lower paraffin indices, much higher Kl ratios and lower relative concentrations of lower molecular weight naphthalenes. Moreover, some oils show a persistent presence of lower homologs of n-alkanes (C 5 -C 8 ) and light aromatics such as benzene and toluene when higher (> C 15 ) homologs are not present. Such compositional characteristics may indicate that some of the reservoirs containing biodegraded oil were subjected to a subsequent secondary charge of lighter, unbiodegraded crude or to different post-generative alteration mechanisms. This later charge of light hydrocarbons suggests the timing of most biodegradation to be pre-Eocene. Destructive microbial action resulting in preferential removal of n-alkanes, isoprenoids, alkylbiphenyls and methylated naphthalenes had little effect on higher molecular weight fractions. Therefore, despite their apparently very low gravities (average API of 14°), most of these oils suffered only light to moderate biodegradation. Although generally similar biomarker signatures indicate an overall genetic affinity and the same source rock for these oils, minor but systematic variations in the biomarker compositions likely reflect regional source organic facies variation or indicate a progressive change in oil maturity.

A suite of 27 oils from predominantly Nisku reservoirs of the Western Canada Sedimentary Basin (WCSB), in central and southern Alberta, can be classified into six groups or families based on stable carbon isotope ratios of individual gasoline range (C5-C10) compounds. A novel analytical technique combining Solid Phase MicroExtraction (SPME) and Continuous Flow Isotope Ratio Mass Spectrometry (CF-IRMS) is employed to measure the 13C/12C ratios. The majority of oils show characteristics of generation from a common source rock, the Upper Devonian Duvernay Formation. Systematic isotope distributions in straight chain and branched alkanes can help to delineate a common source rock along with the influence of secondary alteration processes such as biodegradation, evaporation, and thermochemical sulfate reduction. A 1-2‰ enrichment in 13C between groups can distinguish different levels of thermal maturity during oil genesis. Numerous analytical challenges are inherent in obtaining accurate 13C measurements for gasoline range analytes, but when utilized in conjunction with biomarkers and other compound specific geochemical techniques, the isotopic composition of these compounds exhibits good potential as a correlation tool. End_Page 99

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.

Nonpolar GC-columns are normally used for GC–MS analysis of saturate fractions from crude oils. Under these conditions lupane coelutes with oleananes and some minor C30 compounds of non-terrigenous origin having lupane-like mass spectra. Because any peak eluting fractionally earlier than 17α,21β(H)-hopane in the m/z 191 mass chromatogram is routinely assigned to oleanane, the presence of lupane may sometimes have been overlooked. Lupane and oleananes are easily separated using reverse phase HPLC. Triterpane concentrates from 10 crude oils known to contain oleananes were HPLC-separated. Lupane was unambiguously identified in six of the oils by full-scan GC–MS analysis of fractions having the HPLC-retention time of authentic lupane. GC-separation of lupane and oleananes is possible using polar GC-columns having a polyethylene glycol stationary phase [Organic Geochemistry, 23 (1995) 21], allowing estimation of the lupane/(lupane+oleanane) ratio. High ratios were measured in the Marraat oil, West Greenland (0.8) and the Amauligak oil from the Beaufort–Mackenzie Delta (0.26). The results suggest that lupane may be more frequently occurring than previously thought, and that this compound is preferably associated with high latitude samples. High concentrations of 28-nor- and 24,28-bisnortriterpanes (oleananes, lupanes and taraxastanes) were detected in the Marraat oil.

Petroleum geochemistry improves exploration efficiency by accounting for many of the variables that control the volumes of crude oil and natural gas available for entrapment, including source-rock distribution, richness and quality, thermal maturity, and the timing of generation-migration-accumulation relative to trap formation. It is most powerful when used with other disciplines, such as seismic sequence stratigraphy and reservoir characterization. Four key technology milestones form the basis for most modern applications of geochemistry to exploration. These are the concepts and applications of (1) petroleum systems and exploration risk, (2) biomarkers, stable isotopes, and multivariate statistics for genetic oil-oil and oil-source rock correlation, (3) calibrated three-dimensional thermal and fluid-flow modeling, and (4) controls on petroleum composition by secondary processes. Petroleum geochemistry offers rapid, low-cost evaluation tools to aid in understanding development and production problems. Some technology milestones in reservoir geochemistry include (1) assessment of vertical and lateral fluid continuity, (2) determination of proportions of commingled production from multiple zones and leaky casing, (3) prediction of oil quality in reservoir zones, and (4) prediction of gas/oil and oil/water contact locations. As described in the conclusions, future research will continue a trend toward predictive geochemistry. Examples of predictive tools that draw major research support include piston-core surveys to assess deepwater petroleum systems prior to drilling and three-dimensional basin modeling to predict the regional timing of generation, migration, and accumulation of petroleum. Among other research objectives, models are needed to better predict the distribution and quality of petroleum in reservoirs.

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 lipid's 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.

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.

Devonian strata within the Western Canada Sedimentary Basin contain large reserves of oil and gas. These vast hydrocarbon reserves can be largely attributed to the occurrence of abundant mature, excellent to good quality Devonian source rocks. The Middle Devonian Elk Point Group contains several units with hydrocarbon potential including the Evie Formation in British Columbia, the Keg River Formation in northern Alberta, and the Winnipegosis Formation in east-central Alberta and southern Saskatchewan. Many of these are proven source rocks of oils occurring in Middle Devonian reservoirs. Elk Point Group potential source rocks contain a wide variety of organic matter types reflecting the diversity of their depositional environments. No hydrocarbons have been definitively linked to a Beaverhill Lake Group source rock but it is possible that such a unit is the source of Slave Point Formation reservoired oils in northwest Alberta. The Late Devonian Woodbend Group contains the Duvernay Formation, the most prolific Devonian source rock in the Alberta Basin. It is characterized by marine Type II/I organic matter with TOC contents up to 15% in immature samples and is the source of most oils in the Bashaw Reef Complex, the Rimbey-Meadowbrook Reef Trend, and in the Swan Hills Formation in Alberta. The stratigraphically equivalent Muskwa Formation in northern Alberta has a much lower hydrocarbon potential than the Duvernay Formation. Oils have been correlated to Winterburn Group source rocks within the Nisku Formation of east-central Alberta, Camrose Member/Nisku Formation of southern Alberta, and the time-equivalent Birdbear Formation of southeast Saskatchewan. Winterburn Group potential source rocks in central to southern Alberta can have high TOC contents (up to 15%) and contain Type I and Type II organic matter deposited in open marine to lagoonal palaeoenvironments. The Cynthia Member shale of the Nisku Formation in west-central Alberta, previously thought by some workers to be a source rock, is actually organic-lean. The underlying Bigoray Member is more organic-rich and may be a minor contributor to hydrocarbons in the West Pembina area. The Wabamun Group contains no regionally extensive potential source rocks. Almost all the oil generated from Devonian source rocks appears to have remained within Devonian-aged reservoirs and very little is biodegraded. In contrast, where Exshaw Formation sourced oil is found in Devonian reservoirs, such as in the Grosmont and Nisku formations in the vicinity of the Athabasca Mannville Group bitumen deposit (i.e. "Carbonate Trend"), it tends to be biodegraded. RESUME Les strates du Devonien du bassin sedimentaire de l'Ouest du Canada contiennent de grandes reserves de petrole et de gaz. Pour une grande part, ces vastes reserves d'hydrocarbures sont attribuables a l'occurrence de roches meres du Devonien, abondantes, matures, et de bonne a excellente qualite. Le Groupe d'Elk Point du Devonien moyen contient plusieurs unites ayant un potential en hydrocarbures, dont la Formation d'Evie en Colombie-Britannique, la Formation de Keg River dans le nord de l'Alberta, et la Formation de Winnipegosis dans le Centre-Est de l'Alberta et le sud de la Saskatchewan. Il a ete demontre que plusieurs de ces roches meres sont a l'origine de petroles se presentant dans les reservoirs du Devonien moyen. Les roches meres potentielles du Groupe d'Elk Point contiennent une grande variete de types de matiere organique, refletant la diversite des environnements de depot. Il n'y a pas d'hydrocarbure qui ait ete definitivement associe a une roche mere du Groupe de Beaverhill Lake, mais il est possible qu'une telle unite soit la source des petroles de reservoir de la Formation de Slave Point dans le Nord-Ouest * Geological Survey of Canada Contribution Number 2000179 End_Page 117------------------------ de l'Alberta. Le Groupe Woodbend du Devonien superieur inclut la Formation de Duvernay, la roche mere la plus prolifi que du Devonien du bassin de l'Alberta. Celle-ci est caracterisee par de la matiere organique d'origine marine de type II/I montrant des contenus en MOT allant jusqu'a 15% dans les echantillons immatures, et est la source de la plupart des huiles du complexe de recif de Bashaw, de l'alignement de recifs de Rimbey-Meadowbrook, et de la Formation de Swan Hills en Alberta. L'equivalent stratigraphique de la Formation de Muskwa du nord de l'Alberta montre un potentiel en hydrocarbures beaucoup plus bas que la Formation de Duvernay. Les huiles ont ete correlees avec les roches meres du Groupe de Winterburn a l'interieur la Formation de Nisku du Centre-Est de l'Alberta, avec le Membre Camrose (Formation de Nisku) du Sud de l'Alberta, et aussi avec la Formation de Birdbear, equivalente en age, du Sud-Est de la Saskatchewan. Les roches meres potentielles du Groupe de Winterburn, de la region allant du Centre au Sud de l'Alberta, peuvent montrer un haut contenu en MOT (jusqu'a 15%) et contiennent de la matiere organique de Type I et de Type II, deposee dans des paleo-environnements de type marin ouvert a lagunaire. Le shale du Membre Cynthia de la Formation de Nisku du Centre-Ouest de l'Alberta, precedemment juge par des chercheurs comme la roche mere, est en fait pauvre en matiere organique. Le Membre de Bigoray sous-jacent est plus riche en matiere organique et peut contribuer de facon mineure aux hydrocarbures de la region de West Pembina. Le Groupe de Wabamun ne contient aucune roche mere potentielle d'etendue regionale. Presque toutes les huiles generees par des roches meres du Devonien semblent etre demeurees a l'interieur des reservoirs d'age Devonien, et sont tres peu biodegradees. En contraste, quand une huile provenant de la Formation de Exshaw est retrouvee dans des reservoirs du Devonien, comme dans les formations de Grosmont et de Nisku aux environs du gisement de bitume du Groupe de Mannville de l'Athabasca (i.e. alignement de Carbonate), elle a tendance a etre biodegradee. Traduit par Lynn Gagnon

Biomarker analyses were conducted on a suite of oil and rock samples from the Middle Silurian Guelph-Salina interval in southern Ontario. The oils occurring in the Guelph reef reservoirs have a distinct biomarker composition (e.g. high concentrations of acyclic isoprenoids with phytane greater than pristane, abundant gammacerane, prominent C34 and C35 homohopanes) which not only indicates a single oil family, but also suggests a carbonate source rock deposited in a hypersaline, strongly reducing environment. Analyses of the extracts of rock samples from brown, laminated dolostone lithofacies occurring in the stratigraphically adjacent Guelph-Salina strata show that they have compositional similarities to the majority of the reef-hosted oils. These rocks contain significant amounts of marine Type II kerogen (TOC values ranging from 0.5 to 3.5%) and have good source potential. Though most of the organic matter is amorphous in nature, a structured, identifiable algal component is also common. A broad distribution of n-paraffins, with a relatively high concentration of C21+ members and abundant acyclic isoprenoids are typical in the organic extracts, suggesting a contribution from microbial organisms. A strong predominance of phytane over pristane in the Salina extracts suggests highly anoxic bottom waters and/or hypersaline conditions. Reducing conditions are further suggested by a broad C31-C35 extended hopane profile with prominent C34 homohopane and a high concentration of gammacerane. The overall geochemical similarities among the examined rock samples indicate periods of recurrence of back-reef lagoonal and inter-biohermal paleodepositional conditions during the deposition of both the Guelph Platform and Salina Group carbonates. Geochemical correlation of the extracts and oils indicates that they are genetically related. Although geochemical maturity parameters suggest that the kerogen is only marginally mature, the presence of bitumen and hydrocarbon fluid inclusions in the Guelph samples suggest that early generation of hydrocarbons has occurred in this stratigraphic interval. The Salina extracts occurring in close proximity to reefs show a closer resemblance to the oils (Pr/Ph

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-C 5 H 12 - n -C 8 H 18 ) to verify the biomarker-based classification of oil families. The oils belong to four distinct compositional oil families — A, B, C and D—broadly confined to specific 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 C 7 (“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 different for each oil family, clearly indicating their compositional distinction. Other Mango parameters (N2, P2, P3) show a similar reflection of the oil families. However, while C 7 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, differences in the gasoline range composition suggest that the existing biomarker-based classification of oil families can be more universally applied throughout the entire Williston Basin. Moreover, because the light hydrocarbon parameters prove very useful in refining 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.

Coal samples from Florina (Vevi), Lava, Moschopotamos and Kalavryta basins, Greece, have been subjected to petrographic and organic geochemical analysis. The reflectance of the samples ranged from 0.26% to 0.42%, which ranks them as soft brown coals and sub-bituminous C coals. Lower reflectance values were encountered in the Florina and Kalavryta coals, whereas higher values were obtained for Lava and Moschopotamos samples. Maceral composition of the samples from the Florina area shows a high concentration of textinite A and texto-ulminite A. The samples from the Lava and Moschopotamos area are comparatively rich in humodetrinite. Samples from Florina are rich in resinite, whereas samples from Lava are rich in liptodetrinite. Rock–Eval pyrolysis data show that the samples from Florina and Kalavryta have generally high HI, SI and S2 and low T max values. The coal samples from Moschopotamos and Lava show the opposite, having low HI, S1 and S2 values. These distinct differences are related to the maceral composition (tissue rich in resinitic material) and rank of the coals. Gas chromatography of the saturate fraction indicates that the samples from the Lava and Moschopotamos are rich in n -alkanes from n -C 23 to n -C 33 . In contrast, the samples from Florina are rich in diterpanes, whereas those from Kalavryta are rich in sesquiterpenoids. Gas-chromatography-mass spectrometry of the saturate fraction reveals that the diterpenoids present in the lignites from Kalavryta are derivatives of abietanic acid and pimaric acid, which are found in Pinaceae. The lignites from Florina mainly contain the diterpane, phyllocladane, which implies an input from Cupressaceae and/or Taxodiacaea. The difference in the composition of these xylitic lignites may be attributed to differences in gymnosperm input as a response to climatic change, as the Kalavryta coals are of Pliocene age, whereas the Florina coals are of Miocene age. The study suggests that the petrology and organic geochemistry of these coals are related to the different peat-forming plant communities that were present in the Florina, Kalavryta, Lava and Moschopotamos basins. A mainly non-woody, angiosperm-dominated vegetation made up the peat that went to form the coal deposits of Lava and Moschopotamos, while the Florina and Kalavryta lignites were formed by peats derived mainly from gymnosperms.

The perchloroethylene (PCE) sorption distribution coefficient ( K d , measured at 40–100 μg/l solution concentration in batch experiments) ranged from 4.0 to 134 l/kg over the sampled thickness (1.0–6.0 m depth) of a moderately-low organic carbon (0.002–0.005), fractured and weathered diamict (poorly sorted, glacially deposited) aquitard. The organic carbon-normalized K d ( K oc ) for deeper, unoxidized (reduced) samples from this deposit (log K oc =4.4–4.59) were generally consistent with the kerogen in the underlying Devonian-age shale (log K oc =4.57), a likely source rock for these sediments. The similarities between these samples suggest that the sorption capacity of the kerogen was minimally altered during transport and deposition, and that humic substances were not co-deposited with the kerogen in the glacially-deposited sediments. The K oc within the diamict was correlated to the oxidation state of the organic matter, characterized by the H/O ratio through elemental analysis. The K oc for more oxidized samples from shallower depth samples (log K oc =3.35–3.65) were approximately an order of magnitude less than those determined for the reduced samples. The K oc for 1.5- to 2.5-cm thick oxidation haloes surrounding fractures and characterized by visible Fe-oxidation, were approximately 20–30% lower than the adjacent unaltered matrix samples. The linear trend observed between log K oc and log H/O is similar to, but steeper than, the relation reported previously, which represents increasing sorption magnitude with increasing diagenesis in coal and shale samples. The spatial distribution of the K oc within this aquitard, in concert with qualitative geologic observations, suggests that oxidative weathering of the native kerogen exerts an important control on hydrophobic organic compound sorption.

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.

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.

The Jedburgh well (location: 16-14-27-8W2) was drilled on a small salt dissolution structure in the Williston Basin. The well lies near the Cussed Creek structure, a complex feature involving both Phanerozoic faults that offset the Precambrian basement and the dissolution edge of the Middle Devonian Prairie Formation halite. The chemical compositions of crude oils recovered from cores of Devonian strata in this well are unique in the Williston Basin and unusual in a global perspective, because they contain significant quantities of α -olefins (with the n -C 17 alk-1-ene/alkane ratio ranging from 0.28 to 0.72). The gross chemical compositions and distributions of aliphatic biomarkers, aromatic hydrocarbons and pyrrolic nitrogen compounds in the oils indicate that they were generated by high-temperature, short-term pyrolysis of thermally immature organic matter. Their composition indicates that they were not generated in situ , but accumulated in the Jedburgh well after lateral migration from areas that were influenced by post-Devonian magmatic intrusions. The inferred migration distance (∼10 km) suggests that such intrusions occur within the Cussed Creek structure.

The Upper Devonian Rimbey-Meadowbrook reef trend of central Alberta, Canada, is one of the classical examples that was originally used to support Gussow's model of differential hydrocarbon entrapment. However, the clear discrepancies existing between the ideal hydrocarbon distribution predicted by this model and the one actually observed led to several alternative geological models, most of which have not been constrained by organic geochemical data. The present study uses a wide range of bulk and molecular parameters to determine the oil source characteristics and thermal maturity along the reef trend. The concentrations and isomeric distributions of alkylcarbazoles and non-alkylated benzocarbazoles in oils are employed to study petroleum migration pathways and to constrain the existing secondary petroleum migration models. The data indicates that Gussow's principle is generally applicable, as the oils in the up-dip direction generally have longer implied migration distances although this is not always the case. Other factors not recognized previously, such as the presence of two subfamilies of the Duvernay Formation sourced oils, may also have contributed significantly to the discrepancies in the oil and gas distributions between the model predictions and the actual observational data.

Tertiary age lignites from Arctic Canada were analysed by petrographical, palynological and organic geochemical methods. Results from petrographic analyses indicate the predominance of wood-derived macerals (humotelinite group) in seams from the Strathcona and Stenkul Fiord areas, whereas in the Bache Peninsula area many seams are characterized by the predominance of detrital macerals (humodetrinite) and have also higher inertinite contents. Palynological assemblages are dominated by Taxodiaceae pollen, whereas Pinaceae pollen and pteridophyte spores are less common. Angiosperm derived pollen contents are quite variable. Organic geochemical results indicate that norisopimarane and pimarane are the most abundant diterpenoids. Cadalene was present in the aromatic fractions of all samples, with other components such as simonellite and retene in variable abundance. Rock-Eval data obtained from Stenkul Fiord area samples indicate low petroleum generation potential for this predominantly woody material. The depositional environment at Strathcona and Stenkul Fiords was that of a forested swamp, which formed in a lagoonal/alluvial plain setting. Palynomorph assemblages, petrographic indices and the abundance of diterpenoids suggest that the mire flora was dominated by gymnosperms, although locally angiosperms may also have been abundant as indicated by the occurrence of tetra- and pentacyclic aromatic hydrocarbons. At Bache Peninsula the mire was less forested as indicated by palynological assemblages typical for a marsh environment and petrographic characteristics such as low tissue preservation and the abundance of detrial macerals.

Lower Cretaceous oils in southern Alberta have been assessed using column chromatography, sulphur analysis, gas chromatography (GC) and gas chromatography-mass spectrometry (GC-MS). These oils can be divided into four oil families, E, Q, EQ and F, on the basis of biomarker characteristics. Family E oils are characterized by low pristane/phytane ratios and a C 35 homohopane prominence. Family Q oils are identified by the presence of so-called “Q compounds” (Q/R ratio > 0.5) and have high C 27 diasterane to regular sterane ratios. Family EQ oils are a mixture of Family E and Family Q oils, with biomarker characteristics intermediate between these two families and low abundance of “Q compounds” (Q/R ratio 1.2) and no C 35 homohopane prominence. Oil-source rock correlation to available source rock data suggest that Family E oils are derived from the Upper Devonian-Mississippian Exshaw Formation and Family Q oils correlate to the Lower Cretaceous Ostracode Zone. Family F oils are likely derived from shales of the Upper Jurassic Rierdon Formation, however additional geochemistry data from this potential source rock are required to confirm this interpretation.

Detailed petroleum system analysis allows the direction and extent of hydrocarbon flow to be assessed. In most parts of the Western Canada Sedimentary Basin, the major pulse of hydrocarbon generation and migration occurred as a result of the Laramide Orogeny in Late Cretaceous–Early Tertiary time. The distribution and chemistry of oils provide a detailed picture of fluid flow at this time with oil migration up to hundreds of kilometres observed. Hydrocarbon generation and migration mostly ceased once uplift of the basin commenced during Eocene time. As the basin evolved so did the hydrodynamic regime reflecting changes in topography, glaciation and other factors. This indicates possible problems with using present day hydrogeology to determine oil migration pathways although hydrogeology can help explain petroleum alteration.

The Upper Devonian Nisku Formation reservoirs of the Brazeau river area of west-central Alberta, Canada, produce oil and sweet and sour gas condensate. Generally, oil pools are located updip in the study area and sour (6–31% H2S) gas condensate downdip. H2S in the study area is formed by thermochemical sulphate reduction (TSR). All liquid hydrocarbons probably have one source, with the Duvernay Formation being the most likely candidate. Assessing the relative maturity of the oils and condensates is difficult because of the wide variation in thermal maturity and the effects of TSR, but the ratio of pristane/n-heptadecane does appear to decrease with increasing maturity for this sample set. With increasing TSR, the following changes were noted: decrease in the saturate/aromatic hydrocarbon ratio; increase in the relative abundance of organo-sulphur compounds (e.g. benzothiophenes); δ34S values of liquid hydrocarbon samples approached the values for anhydrite of the Nisku Formation in the study area; and an increase in δ13C of the saturate fraction. H2S concentrations in hydrodynamically “isolated” pools provide a good estimate of the extent of TSR in these reservoirs. However, other pools have anomalously high H2S concentrations for their depth, suggesting that the H2S was generated at greater depths and migrated updip into these pools.

Analyses of the aromatic hydrocarbon fractions of extracts of Lower Cretaceous Ostracode Zone sediments from the Western Canada sedimentary basin indicate the predominance of polycyclic hydroaromatic components. Most of these have not been previously reported in the literature, but are obviously diagenetically related to a new class of molecule whose natural distribution and biological significance remain to be determined. The components whose molecular structures have been confirmed, together with those for which tentative structural assignments are given, provide strong support for a pathway of progressive aromatisation of the presumed polyprenol precursors. These compounds appear to be specific markers for the Ostracode Zone sourced oils in the Lower Mannville Group reservoirs of the Provost area and may serve as excellent oil-source correlation parameters.

Carbonates from the Keg River Formation, La Crete Basin, Alberta, western Canada were examined in order to define: (a) oil source rock potential; (b) bulk maceral composition; (c) extract yield; and finally (d) facies variations using PY-GC-MS. Thirty samples from 6 different wells were examined from the lower Keg River member and 4 from the upper Keg River member using conventional geochemical methods. As maturity differences are absent within the sample set, variations in TOC, Tmax, hydrogen index, organic petrography and extract yields are caused by variability in organic matter input, which is revealed by molecular characterisation using PY-GC-MS. Lower Keg River member bituminous wackestones are excellent potential source rocks containing Types I–II and Type II organic matter. Types I–II organic matter contains large well preserved (up to 200μm in diameter) thick-walled Tasmanites (10–15% of sample) and akinete algal cells indicative of algal blooms within an amorphous bituminite. Type II organic matter contains a higher proportion of degraded alginites/bituminite relative to well-preserved alginites. Extract yields (mg/g TOC) were seen to increase from Types I–II to Type II organic matter. PY-GC-MS revealed that 1,2,3,4-tetramethylbenzene was a major peak in most samples. This is a pyrolysis product arising from β-cleavage of C40 diaromatic carotenoids incorporated within the kerogen during diagenesis. The source of this compound is thought to be from an unknown diaromatic compound with a 2,3,6-/3,4,5-trimethyl substitution pattern and isorenieratene, which is specific to photosynthetic green sulphur bacteria (Chlorobiaceae) suggesting that the photic zone was at least partially anoxic during deposition of these samples. The relative abundance of this compound/n-C11-alkene and organic sulphur (calculated from the thiophene ratio) both increase from Types I–II to Type II organic matter. This trend was grossly similar to the trend seen in the variability of extract yield with hydrogen index. A similar trend for HI and Tmax indicates samples containing a higher proportion of degraded alginites/bituminite relative to well-preserved alginite are more labile than Type I–II organic matter. Upper Keg River member marls contain Type II organic matter, which is characterised by heavily degraded algal material within a bituminous groundmass. Pyrolysates of two of the marl samples contain only low amounts of 1,2,3,4-tetramethylbenzene, in contrast to the bituminous wackestones, indicating that the depositional environment/source input was different during deposition of the marl samples. Although both marls contain similar organic matter, their pyrolysates were significantly different. One marl (1141.9 m) was highly paraffinic containing dominantly short-chain alkene/alkane doublets, while the other marl (1137.6 m) contained a bimodal n-alkane/alkene distribution and high amounts of alkylphenols, which may be derived from preservation of resistant algal polyphenolic molecules or suggest a terrestrial input.

A quantitative study of pyrrolic nitrogen compounds was conducted on a series of marine carbonate petroleum source rock extracts taken from the Upper Devonian Duvernay Formation in the central Alberta portion of the Western Canada Sedimentary Basin. With increasing thermal maturity, concentrations of various pyrrolic nitrogen compounds in the rock extracts increase drastically, together with significant compositional variations related to alkyl substitution position. The study provides circumstantial evidence for adsorptive interactions operating between organic nitrogen compounds and solid organic/mineral phases in subsurface sedimentary rocks during petroleum generation and expulsion. The absolute concentrations and relative distributions of pyrrolic nitrogen compounds in the extracts of different maturity ranges provide background information for the calibration of such data in migrated petroleums, as an independent measurement of secondary oil migration range of Duvernaysourced oils in the basin

The hydrocarbon source rock potential of the Devonian Marcellus and Kettle Point black shales in southern Ontario has been assessed using Rock-Eval pyrolysis, gas chromatography, gas chromatography-mass spectrometry and incident-light microscopy. Both formations contain sufficient hydrogen-rich organic matter (Type II) to be considered possible source rocks. The kerogen is predominantly marine in origin. This organic matter was deposited in a clastic algal-dominated environment, and mainly consists of unstructured bituminite and unicellular alginite. The organic microfacies indicate shelf paleodepositional settings with a transition to an open basinal region. The optical (reflectance, fluorescence) and geochemical (Rock-Eval Tmax, extract yields, distributions of steranes and terpanes) maturity data indicate that the organic matter in the Kettle Point Formation is immature, whereas in the Marcellus Formation it has reached the early stages of hydrocarbon generation and expulsion. Some Devonian oils occurring in this area have characteristics similar to the Marcellus extracts, suggesting that more mature equivalent units from the Appalchian Basin could be their source.

Several series of unusual polycyclic alkanes (ranging from tricyclic to heptacyclic) have been identified as major components in extracts of Lower Cretaceous Ostracode Zone sediments of the Western Canada Sedimentary Basin. These compounds appear to be specific markers for the Ostracode Zone-sourced oils in the Lower Mannville Group reservoirs of the Provost area and may represent a new class of molecules whose natural distribution and biological significance remains to be determined. The stable carbon isotopic data of the tri-, tetra- and pentacyclic alkanes appear to be related to pristane and phytane, yet the significant isotopic depletion observed in the hexacyclic compounds suggests that they may be derived from different groups of organisms or different biosynthetic routes.

The reflectance of chitinozoa (%ChR0) was investigated as an alternative technique of determining the level of thermal maturity of organic-rich Palaeozoic rocks in southern Ontario. These sedimentary strata, which include the Ordovician Collingwood Member and the Blue Mountain Formation, as well as the Devonian Marcellus Formation, lack vitrinite precluding the application of a standard vitrinite reflectance (%VR0) technique. ChR0 shows a proportional increase at marginal to moderate maturities, being on average 20 to 25% higher than expected vitrinite reflectance. The reflectance data fall into a very narrow range showing a high degree of consistency for each lithostratigraphic unit. The average ChR0 are as follows: Collingwood Mbr 0.63% (Georgian Bay area) and 0.88% (Toronto area), Blue Mountain Fm 0.92%, Marcellus Fm 0.68%. Correlation with more conventional optical and geochemical maturity parameters obtained from the same set of samples (fluorescence of Tasmanites, Leiosphaeridia and Gloeocapsomorpha alginite, Rock-Eval Tmax, extract data, distribution of terpanes and steranes in extracts) indicates that, within the area of study, the beginning of the catagenetic stage corresponds to ChR0=0.65% (equivalent VR=0.50%) whereas the threshold of significant oil generation is reached at ChR0=0.9% (equivalent VR=0.70%). Therefore the Blue Mountain Formation is thermally mature with respect to hydrocarbon generation throughout the whole area of study. The Collingwood shales are mature only in the Toronto area while those occurring in the Georgian Bay area as well as the Marcellus shales have yet to enter the main stage of hydrocarbon generation. This integrated approach of assessing thermal maturity shows that ChR0, when constrained with other maturity parameters, is a very reliable indicator of thermal maturity in Lower to Middle Palaeozoic sedimentary rocks.

Late Paleocene/Early Eocene coal-bearing strata are widespread across the Canadian Arctic Archipelago. Laterally continuous seams of substantial thickness are present in the Iceberg Bay Formation, Eureka Sound Group, at Stenkul Fiord, Ellesmere Island. Sixty-four coal seams with a cumulative thickness of 53 m of coal occur in a 450 m sequence. The investigation of the composite section is based on examination of 19 samples from seams thicker than 1 m and 7 samples from marker seams used for correlation purposes. The coals consist predominantly of wood-derived huminite macerals (79–98 vol%). Structured huminite macerals are dominant in the top part of the section whereas detrital components are abundant in the lower part. The liptinite fraction is dominated by sporinite and cutinite (1–9 vol%). Inertinite content is very low except at the base of the section (0–14 vol%). Reflectances determined on eu-ulminite (0.36–0.43% R o ), geochemical parameters, and Thermal Alteration Indices indicate that the coals are of lignite to subbituminous rank. The dominance of diterpanes and the abundance of Taxodiaceae and Pinaceae pollen suggest that most of the organic matter is of gymnospermous origin. Pinaceae pollen is abundant in the lower part of the section and Taxodiaceae is abundant in the upper part. The abundance of angiosperm pollen in most of the section suggests, however, that angiospermous plants were significant members of the flora. The depositional environment for the Iceberg Bay Formation coals at Stenkul Fiord is that of forested swamps on an alluvial plain. Pollen assemblages indicate a Late Paleocene/Early Eocene age for the section, and a temperate moist climate.

Understanding the sources and pathways of pollutant transport to the Arctic is fundamental to our custody of this sensitive ecosystem. To achieve such an understanding, we need to go beyond a catalog of environmental concentrations. Sediments, which are a final sink for particle-active contaminants, can provide a valuable resource to assess fluxes and sources of contaminants. Here, we interpret PAH distributions from widely distributed Arctic marine sediments both as indicators of anthropogenic contribution and to illuminate transport pathways. We use principal components analysis (PCA) to reveal the potential sources of PAHs and their geochemistry in sediments from the Beaufort and Barents Seas. PCA distinguishes between natural and anthropogenic inputs and supports a direct linkage between anthropogenic emissions and Arctic contamination. In the Beaufort Sea, PAHs and triterpenes reflect strong Mackenzie River-dominated inputs of natural PAHs and petroleum which overwhelm anthropogenic sources. In the B...

Creosote, a distillation product of coal tar, is made up of an extremely complex mixture of phenols and polycyclic aromatic compounds (PAC) which include polycyclic aromatic hydrocarbons (PAH) and nitrogen, sulphur and oxygen (NSO) containing heterocyclics. It is considered to be an environmental hazard. This report presents some preliminary results from a large field experiment that is evaluating the mobility, persistence and fate in groundwater of compounds present in coal tar creosote. This involved setting up a long-term field experiment where a limited plume of contaminated ground water was created by placing creosote into an extremely well characterized sand aquifer. The original creosote was dominated by PAH components with minor amounts of NSO containing PAC. The concentration of the dominant nitrogen heterocyclic (quinoline) was only 10% of the abundance of the major PAH components (naphthalene and phenanthrene). Analysis of groundwater samples collected 278 days after the emplacement of the creosote shows that with increasing distance from the source the concentration of naphthalene is reduced while that of quinoline increases, eventually becoming dominant. A similar trend was also observed for samples collected after 471 days and this can be related to the relative aqueous solubilities and mobility of the two compounds. Also observed in the outermost 471 day samples was the presence of quinolinone which is believed to be an aerobic metabolite of quinoline. Strategies for the final part of the project which involve cleaning up the Borden experimental site are briefly discussed in light of these results.

Benched channel samples and continuous block samples of the Hub and Harbour seams from the Sydney Basin, Nova Scotia were studied to define the variations in petrography, geochemistry and palynology of the seams and to interpret the depositional environments of the precursor mires. Petrographic compositions of the seams are very similar with high vitrinite content, low inertinite, moderate liptinite and negligible clastic mineral content. Pyrite content is moderate. There is little variation in petrographic composition between benches in either seam. There are marked variations in petrographic compositions at the lithotype scale. Petrographic facies parameters indicate deposition of the bulk of both seams under fairly uniform conditions in relatively wet mires. Unusually wet or dry periods were rare. The palynological assemblages of both seams indicate a middle to late Westphalian D age. The common to abundant palynomorphs are derived from “arborescent” and “herbaceous” lycopsids, tree ferns and other ferns(?), and sphenopsids. The palynological assemblages support the petrographic interpretation of relatively wet mires. Cordaites pollen (Florinites) is rare, suggesting that there was little contribution from plants growing in dry or upland areas. The absence of the Densospore miospore phase, and the petrographic data, indicate there were no periods in which domed mires occurred. The distinctive dull bands occurring in the Hub and Harbour seams are characterised by low vitrinite contents, high inertinite content, high liptinite and common detrital minerals. Sporinite, showing varying degrees of degradation, is commonly highly concentrated in thin bands. The geochemistry is marked by much higher hi values than normally reported for coals but other indices are typical for coals of this rank. The palynological assemblages of the dull bands are dominated by tree fern spores and other ferns(?) with only a minor contribution by sphenopsid spores. The dull bands were deposited during periods of inundation of mires. Relatively low mineral content indicates that the distributary channels which flooded the mires were quite distant from the depositional sites of the samples.

Some of the oldest coals in the world are found within the Middle to Upper Devonian clastic wedge of the Canadian Arctic Archipelago. The coals investigated here occur in the Weatherall, Hecla Bay and Beverly Inlet formations on western Melville Island and range in age from Late Givetian to Middle Frasnian. Many of these coals are rich in liptinite macerals, particularly sporinite and hence can be termed canned coals. Both elemental and Rock-Eval analysis indicate these coals have the potential to generate liquid hydrocarbons. A good correlation between % liptinite with both H/C or Hydrogen Index is observed up to about 50% liptinite after which the latter two parameters level off. The coals range in maturity from 0.61 to 0.87% R o and hence should be in the oil window. The amounts of hydrocarbons that can be extracted from the coals when expressed in mg/g organic carbon are very low, suggesting that they are poor source rocks for oil. All the extracts except for the most mature and vitrinite-rich sample show high pr/ph ratios and biomodal n -alkane distributions. A cannel coal from The Beverley Inlet Formation has a very unusual triterpane distribution that includes regular, AB-ring desmethyl and AB-ring methyl hopanes. Steranes are in very low concentrations compared to hopanes in all samples. The relative abundance of C 28 and C 29 steranes appears to be influenced by maceral composition. Hydrous pyrolysis at 330°C for 72 h generated greater amounts of hydrocarbons from the coals suggesting they could be the source of liquid hydrocarbons at greater maturities. The hydrous pyrolysis experiments also indicate that thin-walled spores are more reactive than thick-walled spores at lower temperatures. The coals on Melville Island are not thought to be significant source rocks for the oil and gas occurrences in this area of the Canadian Arctic because they make up only a very small fraction of the total sedimentary package.

A comparison is made of the distributions of certain classes of saturated hydrocarbon biomarkers in an unaltered oil and a severely biodegraded oil from the Kelamayi oilfield in the Zhungeer Basin of northwestern China. Both oils are thought to have the same source rock. The n-alkanes, acyclic isoprenoids, carotenoid-derived alkanes and regular C27C29 steranes which are present in the nondegraded oil were not detected in the biodegraded sample. Additionally, the biodegraded oil shows an increase in the abundance oil, and the presence of 17α(H)-25-norhopanes, 17s(H)-25-norhopanes, C-10 demethylated tricyclic terpanes and a C-10 demethylated C23 tetracyclic terpane which were not detected in the nondegraded oil. C26 and C25 regular steranes appear to show a much greater resistance to microbial attack than the C27C29 regular steranes, as indicated by an isomer distribution for these low molecular weight steranes that is expected for nondegraded samples in the biodegraded oil. Unknown tricyclic compounds showing a base fragment ion of m/z 219 and a similar carbon number abundance to the steranes in the nonbiodegraded sample are present in relatively high concentrations in the biodegraded oil. These compounds are also present in very low abundance in some nondegraded oils from the Kelamayi Basin, indicating that their much higher concentration in the microbialy altered oil is possibly due to their resistance to biodegradation. However, at present their derivation from the microbial alteration of steranes cannot be ruled out. Several series of bicyclic compounds are also present in higher concentrations in the biodegraded oil.

The Jeanne d'Arc Basin is situated in the northeastern part of the Grand Banks, off the east coast of Newfoundland. Several large oil and gas fields have been discovered in this basin, the largest of which is the giant Hibernia field. The principal source rock of most of the oils in the Jeanne d'Arc Basin is the Kimmeridgian-aged Egret Member of the Rankin Formation. A characteristic feature of the biomarker distributions of both the oils and the Egret Member extracts is the very high abundance of 4-methyl steranes. The high concentration of these compounds prevents the accurate measurement of maturity and other parameters based on 4-desmethyl steranes using GC-MS-SIM. The use of Collision Activated Decomposition (CAD) GC-MS-MS is demonstrated as a method of overcoming the problem of chromatographically co-eluting compounds to obtain reliable biomarker data. Biomarker and other geochemical data are then used to help elucidate the history of oil migration into stacked reservoirs in two wells in the Jeanne d'Arc Basin. All the Hibernia K-18 oils are sourced from the Egret Member. We interpret our data to indicate that all the reservoirs over a 1570 m depth interval were originally filled by a single pulse of oil that migrated vertically via faults. In the lowermost Hibernia reservoirs this event is being overprinted by more mature hydrocarbons leaking from the underlying overpressured zone. With increasing depth at Ben Nevis I-45, oils show an increase in maturity and in the proportion of hydrocarbons that are derived from a source rock other than the Egret Member. This second source is dominated by terrestrially-derived organic matter. Oils are found in other wells in the Jean d'Arc Basin with similar characteristics. All these wells are located in one small area of the basin and are in close proximity to the Trinity Fault.

Triassic oils and their potential Mesozoic source rocks in the Peace River Arch region (Western Canada Basin) have been examined using various analytical techniques. Triassic oils are divided into two groups, 1 and 2, on the basis of biomarker composition. Triassic outcrop samples from the Rocky Mountain Foothills are mature to overmature, and contain Type II/III organic matter with TOC's ranging from 0.1 to 15.0 wt% and HI values up to 445. Subsurface core samples from the Triassic Montney Formation are mature to overmature with TOC's (rarely) up to 2.8 wt% and HI values up to 398. The Triassic Doig Formation has good to excellent source potential and moderate to high maturity, with TOC values over 5.0 wt% and HI values commonly in excess of 300. The Jurassic “Nordegg Member” ranges from early mature to overmature, with TOC's as high as 23.5 wt% and HI values greater than 600 where maturity is low. Oil-source rock correlations are established, based on biomarker signatures, between the Group 1 oils and the Doig Formation. Group 2 oil was sourced by the “Nordegg Member”

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.

Kerogen concentrates prepared from four rocks of Ordovician age have been analyzed by pyrolysis-gas chromatography using a sulphur-specific flame photometric detector and by pyrolysis-gas chromatographymass spectrometry.