Source rock characterization and oil-to-source rock correlation of a Cambrian -Ordovician fold-and-thrust belt petroleum system, western Newfoundland

Marine and Petroleum Geology 115 (2020) 104283

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Research paper

Source rock characterization and oil-to-source rock correlation of a Cambrian -Ordovician fold-and-thrust belt petroleum system, western Newfoundland

T

Martin Schwangler∗, Nicholas B. Harris, John W.F. Waldron Department of Earth and Atmospheric Sciences, University of Alberta, Edmonton, AB T6G2E3, Canada

ARTICLE INFO

ABSTRACT

Keywords: Canada Western Newfoundland Biomarkers Maturation Migration Hydrocarbons Oil-to-source correlation Fold-and-thrust belt

In this study, we use biomarker and isotope data to address the complexities of petroleum system analysis in foldthrust systems, specifically related to hydrocarbon generation and migration, such as variable thermal maturities of source rocks, complex migration pathways, and mixing. Source rocks, extracts, and oil samples are taken from Paleozoic rocks along the Appalachian structural front in western Newfoundland. Oil seeps along this fold-andthrust belt have motivated episodic exploration efforts over the last 150 years. However, economic development has been unsuccessful to date, in part because of the complex nature of oil-to-source relationships. Pyrolysis analyses identify promising source intervals in Lower Ordovician (Floian) formations, with an excellent source potential containing type I/II organic matter (TOC up to 9.35%, HI up to 840). A second good source interval, identified within the late Cambrian (Furongian) continental slope and rise sediments, contains type II/III organic matter (TOC up to 2.34%, HI = 380). Source rock samples from outcrops are marginally mature to mature with Tmax values between 436 and 447. Geochemical analyses of source rock extract imply a clastic shale-dominated source rock with a minor contribution from carbonate source rocks. Chemometric analyses yield 3 extract groups. Groups 1 and 2 contain lower Ordovician samples with organic matter derived from oxidized micro-plankton with varying amounts of Gleocapsomorpha prisca. Extract group 3 originates from Cambrian samples and shows evidence of a bacterial-derived organic matter. Similar genetic relationships among 10 oil samples from natural oil seeps and abandoned well sites are indicated by high-resolution biomarker analyses. Seven oil samples originated from Ordovician source rocks that produced high API oils with low bisnorhopane/hopane, tricyclic/hopane ratios, and high sterane concentrations, supporting interpretation of a source containing algal-derived organic matter. Three oils originated from Cambrian shales. These high API oils show high bisnorhopane/hopane and tricyclic/hopane ratios, low sterane concentrations, and low carbon isotope values, all indicative of organic matter derived from bacteria, generated over a wide range of maturities (0.98–1.26 %Ro). Thermal maturity-sensitive biomarkers and naphthalene ratios show that source rocks generated oils with a wide range of maturities related to their dipping character in the imbricated thrust stack. The Cambrian source generated oils that locally experienced secondary cracking during Acadian inversion, whereas the Ordovician source generated oil with low maturities after the Acadian inversion. Oil operaters exploring fold-and-thrust belt petroleum systems may expect extreme changes of oil properties (for example, API gravity) in spacially restricted areas.

1. Introduction The interpretation of oil-to-source rock relationships in structurally complex terranes is challenging, particularly when several source rock intervals are present. Challenges are introduced by spatially variable thermal maturity, which can result in the generation of oils with different characteristics from an individual source. Additional challenges

∗

result from complex migration pathways from source rock to reservoir and biodegradation that may produce oils of highly variable composition in spatially restricted areas. In this study, we present a geochemical analysis of source rock and oil samples from an active but poorly studied onshore petroleum system in the fold-and-thrust belt in western Newfoundland (eastern Canada), located at the deformation front of the Appalachian orogen and the adjacent Anticosti Basin (Fig. 1). Oil seeps

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

https://doi.org/10.1016/j.marpetgeo.2020.104283 Received 26 November 2019; Received in revised form 28 January 2020; Accepted 5 February 2020 Available online 11 February 2020 0264-8172/ © 2020 Elsevier Ltd. All rights reserved.

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Fig. 1. Simplified geologic map of western Newfoundland including bordering petroleum basins. Boxes indicate study areas, shown in more detail in Fig. 4 (modified after Waldron et al., 2003; Enachescu, 2011). Inset (a) shows Lithotectonic subdivision of the northern Appalachians.

along this fold-and-thrust belt have sparked episodic exploration interest. Despite limited production in the early 20th century and renewed exploration efforts in the 1960s and early 2000s (Weatherhead, 1922; Baker, 1928; Brown, 1938; Fleming, 1970; Fowler et al., 1995; Cooper et al., 2001; Hicks and Owens, 2014), the basin remains economically unsuccessful. Cambrian and, in particular, Ordovician mudrocks are recognized worldwide as the source of significant volumes of oil and gas (Fowler and Douglas, 1984). This research aims to identify viable source rocks in Cambrian to Ordovician rocks along 170 km of coastal outcrop in western Newfoundland, to determine whether a stratigraphic change in organic matter composition occurs and if organic matter from the Ordovician source rocks contains characteristic Ordovician biomarkers. We apply biomarker and carbon isotope geochemistry to interpret the age and depositional environment of the organic matter that sources oils. We use biomarkers to address the thermal maturity evolution and constrain the onset of oil-generation by integrating it with regional geology. We employ high-resolution geochemical methods, including GC/MS and GC/MSMS, and statistical analyses to establish genetic

relationships between oil seeps and corresponding source rock. Understanding organic matter composition and thermal evolution of source rocks is fundamental for petroleum system analysis. We show that integrating this with an oil-to-source rock correlation analysis can be useful to further delineate petroleum systems in complex tectonic settings in terms of variable maturities in source rocks, the onset of oil generation, migration pathways, biodegradation, and mixing. This, in turn, adds to a nuanced picture of petroleum systems, providing a more realistic framework for future exploration efforts. 2. Geologic background Western Newfoundland is part of the Anticosti Basin, one of the large Appalachian Basins in North America (Fig. 1). The geologic evolution of this basin is linked to the Appalachian orogen, an extensive north-east trending mountain belt of deformed Mesoproterozoic and Paleozoic rocks (Rodgers, 1968). The Newfoundland Appalachians are divided into five tectonostratigraphic units (Williams and Hatcher, 1983): the Humber Zone, Notre Dame Subzone, Exploits Subzone, Avalonia, and Meguma Terrane, which accreted during the closure of 2

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Fig. 2. Schematic tectonic evolution of the Humber Zone. Time steps include the breakup of Rodinia, the opening and closure of the Iapetus Ocean, and the Taconinan and Acadian orogenies (modified after Waldron and van Staal, 2001; van Staal et al., 2014).

the Iapetus ocean (Williams, 1979; Waldron et al., 2015). The Laurentian passive margin, including Cambrian to Ordovician platform and continental slope and rise deposits, is preserved in the Humber Zone (Fig. 1) (Williams and Hiscott, 1987). This zone is bounded to the west by the Appalachian deformation front and to the east by the Baie VerteBrompton Line (BV-BL) (Fig. 1). It also contains a active petroleum systems indicated by oil seeps that occur in Paleozoic rocks along the thrust front between the orogen and its foreland basin (Hicks and Owens, 2014).

polarity reversal led to the development of a post-Taconian foreland basin above a northwest-dipping subduction zone. Arc-continent collision caused imbrication of the continental slope and rise deposits into an accretionary wedge that was thrust onto the former shelf (Fig. 2) (Stevens, 1970; Williams, 1975; Waldron and van Staal, 2001). The structural and stratigraphic expression of the accretionary wedge (Humber Arm Allochthon) varies from north to south. In the Cow Head area (north) the Humber Arm Allochthon is mapped as imbricated thrust sheets (White and Waldron, 2018), in the Bay of Islands area as stacked and folded thrust sheets separated by mélange (Waldron et al., 2003), and on Port au Port Peninsula as stacked thrust sheets with units containing mélanges and broken formation typical of accretionary wedges (Waldron et al., 2003; Lacombe et al., 2019). Tectonic loading of the margin by the encroaching Humber Arm Allochthon initiated a flexural bulge that led to the development of the St. George Unconformity (Jacobi, 1981; Knight et al., 1991). The Taconian orogeny culminated in the collision between Laurentia and the Dashwood microcontinent during the closure of the Iapetus Ocean (Fig. 2) (Waldron and van Staal, 2001). Subsequent foreland basin subsidence activated deep-seated extensional faults, creating accommodation space for shallow marine carbonates. When sedimentation failed to keep up with accelerated subsidence, deep marine carbonates and subsequently, orogen-derived clastics were deposited (Knight et al., 1991; Quinn,

3. Deformation history Continental breakup. Neoproterozoic continental rifting marked the initiation of the basin (Stukas and Reynolds, 1974; Kamo et al., 1989; Cawood et al., 1996, 2001; McCausland et al., 2007; van Staal et al., 2012). Multiple phases of rifting opened the Iapetus Ocean (Fig. 2). Rifting ended before the end of Cambrian Epoch (Leslie et al., 2008; Peng et al., 2012), and evolved into the passive margin of Laurentia (Williams and Hiscott, 1987; Hibbard et al., 2007) (Fig. 2). Taconian deformation. Deformation and subsequent destruction of the passive margin started in the latest Cambrian with the Taconian orogeny (Williams, 1975; Williams and Hiscott, 1987; James et al., 1987) (Fig. 2). In the main stage of the Taconian orogeny, subduction 3

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1992a, b, Quinn et al., 1999). After Taconian collision, the originally southeast-dipping subduction zone changed to northwest dipping subduction on the east side of the accreted Dashwood microcontinent (Zagorevski et al., 2008) (Fig. 2). Break-off of the westerly-subducting slab in the Silurian resulted in an unconformity within this succession (White et al., 2019) (Fig. 2). Acadian deformation. Acadian (Devonian) shortening overprinted Taconian structures and is attributed to the collision of Avalonia with Laurentia (van Staal et al., 2009) (Fig. 2). Thin-skinned westward thrusting created a triangle zone located offshore of western Newfoundland (Stockmal and Waldron, 1990). Original normal faults in the Port au Port and Cow Head areas were inverted into deep-seated reverse faults, forming the Long Range and Parsons Pond Thrusts in the Cow Head area and the Round Head Fault on Port au Port Peninsula (Waldron and Stockmal, 1991; Stockmal and Waldron, 1993; Waldron et al., 1993, 1998; White and Waldron, 2018). Post-Acadian tectonic events. The absence of rocks younger than Carboniferous (Cordroy Group), prohibits evaluation of later tectonic events on Port au Port Peninsula. Further south where Carboniferous rocks are present (e.g. Bay of St. George subbasin), the tectonics are characterized by synsedimentary and salt-related deformation in an overall dextral strike slip setting (Snyder, 2019).

1998). Overlying the Table Head Group is the Goose Tickle Group (Darriwilian), which marks the transition to orogen-derived clastic sediments and rapid filling of the foreland basin (Stenzel et al., 1990; Quinn, 1995). The stratigraphic top of this formation is nowhere preserved but is in thrust contact with the Humber Arm Allochthon. The Late Ordovician Long Point Group (Sandbian to Katian), exposed only on the Port au Port Peninsula (Rodgers, 1968), contains post-Taconian foreland basin deposits that record an overall deepening upward trend (Quinn et al., 1999; Batten Hender and Dix, 2008). The Long Point Group deposition is related to a diachranous subduction polarity reversal along the Laurentian margin (White et al., 2019). During this time the basin was in a hybrid retro-arc and fore-arc position leading to deposition of a thick succession of Long Point Group (White et al., 2019). Lower Devonian Clam Bank (Lochkovian) and Red Island Road Formation (Emsian) are clastic sediments derived from the Acadian Orogeny and represent Acadian foreland basin fill. On Port au Port Peninsula, Carboniferous strata of the Cordroy Group (Visean) are mostly undeformed and lie unconformably above Ordovician units (Stockmal et al., 2004). 5. Hydrocarbon source rocks

4. Stratigraphic evolution

Source rock studies from western Newfoundland have been carried out by Macauley (1987, 1990), Weaver (1988), Weaver and Macko (1988), Sinclair (1990) and Fowler et al. (1995). These studies include samples collected from promising black shale intervals in the Port au Port and Cow Head area, which exhibited hydrocarbon potential from marginal to excellent (Table 1). Weaver and Macko (1988) concluded that the Ordovician Green Point Formation was likely the source of oils collected from Parson's Pond and St. Paul's Inlet. Average total organic carbon (TOC) values were reported at 4.21 wt% and average hydrogen indices (HI) at 471; oxygen indices (OI) are low. Macauley (1987, 1990) and Fowler et al. (1995) reported similar values for the Green Point Formation in the Cow Head area (Table 1). Source-rock characteristics for the shelf-proximal Shallow Bay Formation reported by Sinclair (1990) showed average TOC values of 1.75 wt% and HI values of 303 with low OI values (Table 1). The richest source rocks from the Port au Port Peninsula are reported from the most distal portion of the Cow Head Group, formerly assigned to the Green Point Formation but now mapped as Middle Arm Point Formation (Lacombe, 2017; Lacombe et al., 2019). Macauley (1987, 1990) and Fowler et al. (1995) report high TOC intervals (max. 10.35 wt%), high HI (max. 759), and low OI values for these units. Fowler et al. (1995) concluded that the Paleozoic alga Gleocapsomorpha prisca (G. prisca), found in Cambrian to Ordovician source rock samples, was responsible for type I/II organic matter. An odd-to-even carbon number preference found in the oil samples supports this interpretation (Fowler et al., 1995).

Fig. 3 summarizes the stratigraphy of western Newfoundland (timescales of Peng et al., 2012 and Cooper et al., 2012). Cambrian clastic rift and passive margin. The oldest rocks in the basin are Mesoproterozoic Grenville metamorphic units. Overlying these are syn-rift and passive margin related sedimentary rocks of the Labrador Group. The lowest unit in the Labrador Group (Cambrian Series 2) comprises terrestrial, clastic sediments deposited during Neoproterozoic rifting and opening of the Iapetus Ocean (Williams and Hiscott, 1987). In the upper portions of the Labrador Group, marine shales and limestone mark the transition into a passive margin depositional environment (Cambrian Series 2 and 3) (Williams and Hiscott, 1987; Cawood et al., 2001). The Curling Group, an offshore equivalent to the Labrador Group, is comprised of siliciclastic rocks (Palmer et al., 2001). Ordovician Carbonate margin. The overlying Cambrian (Series 3 to Furongian) Port au Port Group was deposited in a high energy marine setting (Chow and James, 1987; Knight and Boyce, 1991; Westrop, 1992), whereas the Early Ordovician St. George Group (Tremadocian to Dapingian) was deposited in a lower energy marine setting, containing potential reservoir intervals (Knight and James, 1987; Knight et al., 1991; Cooper et al., 2001; Zhang and Barnes, 2004). Continental slope and rise deposits of the Cow Head Group, coeval with shelf deposits, consist of black shales (constituting source rocks), ribbon limestones, and interbedded pebble to cobble conglomerates in varying proportions, depending on their proximal to distal relationship to the paleo-shelf margin. (James and Stevens, 1986; Botsford, 1987). These formations were originally separated into the Northern Head Group and the Cow Head Group. However, because the proximal part of the Northern Head Group is lithologically closely similar to the distal parts of the Cow Head Group, we follow the revised stratigraphy by Lacombe et al. (2019). Foreland Basin. The transition from a passive margin to a foreland basin, indicating the onset of tectonic activity, is placed at the St. George Unconformity (Klappa et al., 1980; Knight and James, 1987). This separates St. George Group from the overlying Middle Ordovician (Darriwilian) Table Head Group, the basal unit of the developing foreland basin (Jacobi, 1981; Knight et al., 1991; Dallmeyer and Williams, 1975; Stenzel et al., 1990; Maletz et al., 2011). Because rocks in the Port au Port, St. George Group, and the basal unit of the Table Head Group have similar geophysical properties, they are combined in seismic interpretation and termed ‘platform succession’ (Waldron et al.,

6. Geochemical sampling We systematically collected 197 source rock samples from measured sections in outcrop and from available core. The most extensively sampled sections are along the coast, from Green Point to Cow Head (Green Point and Shallow Bay Formation), the Bay of Islands (Cooks Brook and Middle Arm Point Formation), and the Port au Port Peninsula (Middle Arm Point Formation) (Fig. 4). Measured sections, biostratigraphically constrained by James and Stevens (1986), Botsford (1987), and Lacombe et al. (2019), represent sections from the proximal to the distal continental slope. We used these sections to sort the samples spatially and temporally. We took source rock samples every 3–5 m along measured sections, with finer spacing (1 m) in black shale lithologies. To minimize the impact of weathering, freshly broken samples were obtained as far as possible from adjacent water. We cleaned all samples to prevent contamination by recent organic matter. 4

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Fig. 3. Stratigraphic table of western Newfoundland depicted using the timescale of Peng et al. (2012) and Cooper et al. (2012). Dating of the strata is based on biostratigraphic ages from trilobites, conodonts and graptolites from Bergström et al. (1974), James and Stevens (1986), Botsford (1987), Knight and Boyce (1987), Knight and Boyce (1991), Lindholm and Casey (1989), Boyce et al. (1992), Quinn et al. (1999), Burden et al. (2001), Cawood and Nemchin (2001), Cawood et al. (2001), Burden et al. (2002), Zhang and Barnes (2004), Quinn et al. (2004), Batten Hender and Dix (2008), and Maletz et al. (2011), White et al. (2012), Lacombe (2017). CC=Cape Cormorant Conglomerate; TC = Table Cove.

Based on pyrolysis analyses, we selected 23 samples with the highest petroleum potential for extract analyses. Oil samples were collected from the Port au Port Peninsula and the Cow Head area (Fig. 4). Samples from the Port au Port Peninsula include oil from the Port au Port #1 well (sampling the pay zone between 3457 and 3473 m), natural oil seeps from Shoal Point (1 sample), and bitumen samples from shoreline outcrops (3) and the Aguathuna Quarry (1). Samples from the Cow Head area include 8 oil samples from old drill holes (0–25 m below ground elevation). Bitumen samples from the Cow Head area were collected from a quarry in St. Paul's (1) and from outcrop at Green Point (1). An additional 5 tar samples were collected along the coast. Oil samples from wells, where oil could be found above water, and from natural seeps were collected in glass vials and immediately sealed to prevent contamination. Bitumen samples were collected with a knife (washed with water and acetone) and stored

in sealed glass vials to prevent contamination. Upon analysis, all tar samples contained oleanane, a biomarker linked to flowering land plants (Ekweozor et al., 1979), which are absent in the Cambrian to Ordovician period. We interpret these samples as discharge from ships and excluded them from discussion. 7. Methods Source rocks, extracts, and oil samples were analyzed by GeoMark Research LLC (Houston) and are tabulated in the supplementary material. Total organic carbon (TOC) was measured with the LECO C230 instrument. Pyrolysis data was obtained with the Rock-Eval II instrument with operating conditions at 300 °C for 3 min (S1), 300 °C–550 °C at 25 °C/min. S3 was trapped after S2 and before the final 1-min hold at 550 °C. Instrument calibration was achieved using an in-house rock 5

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Table 1 Compiled source rock characteristics. Analysis results from previous studies reporting average (av.) values for TOC, HI, and OI. CH = Cow Head area; PaP = Port au Port area; HAA = Humber Arm Allochthon. Formation

Number of sample s

TOC av

HI av.

OI av

Authors

Green Point CH Green Point CH Green Point CH Green Point PaP Green Point PaP Shallow Bay Shallow Bay Shallow Bay Table Head Table Head Black Cove Black Cove HAA undivided Table Cove Mainland Curling

15 3 5 3 4 4 2 1 6 1 2 1 2 1 4 1

4.21 4.61 3.65 8.13 6.41 0.9 1.75 1.21 0.55 0.61 0.99 0.84 1.06 0.82 5.95 1.2

471 605 356 712 576 300 303 379 270 215 218 312 363 290 552 354

17 17 9 8 5 4 50 8 28 13 19 36 36 58 13 7

Weaver (1988), Weaver and Macko (1988) Macauley (1987), 1990 Fowler et al. (1995) Macauley (1987), 1990 Fowler et al. (1995) Weaver (1988), Weaver and Macko (1988) Sinclair (1990) Fowler et al. (1995) Weaver (1988), Weaver and Macko (1988) Fowler et al. (1995) Sinclair (1990) Fowler et al. (1995) Macauley (1987), 1990 Sinclair (1990) Fowler et al. (1995) Fowler et al. (1995)

standard made from Skull Creek Shale (S1 = 0.21, S2 = 9.02, S3 = 0.40, Tmax = 418) (Brian Jarvie - GeoMark, personal communication). Standard deviation for S1 and S2 peaks is 10%, S3 peaks

20%, and Tmax ± 2 °C. Quantitative source rock extraction was performed on a Dionex ASE 350. Rock powder-filled capsules were filled with dichloromethane and pressurized to 1400 psi for 5 min, then

Fig. 4. Overview map with main sample location for oil, bitumen, and source rocks. Map (a), (b), and (c) show main sample location in more detail. (a) Port au Port Peninsula includes 46 samples from measured sections from Lacombe (2017) (b) Bay of Islands includes 34 individual source rock samples from measured sections from Botsford (1987). (c) Cow Head area includes oil samples (eight) from Parson's Pond and St. Paul's Inlet. 115 source rock samples from seven different measured sections (6 around St. Paul's Inlet and one from Green Point) (James and Stevens, 1986). Map based on work by White et al. (2019). (For interpretation of the references to colour in this figure legend, the reader is referred to the Web version of this article.) 6

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flushed three consecutive times into collection vials for further analyses. For whole crude oil analysis, oils and extracts were injected on a J& W DB-5 column and temperature programmed from 60 °C to 350 °C at 12 °C/min using an Agilent 7890 A gas chromatograph with a flame ionization detector - FID. To obtain API gravity, crude oils were injected into an Anton Par DMA 500 density meter using the “API Gravity at 60 °F″ method. Sulfur content in the oils was measured via the process of Dumas combustion on a vario ISOTOPE select elemental analyzer. The < C15 fraction was separated by evaporation in nitrogen. Asphaltenes were precipitated using n-hexane. The C15+ deasphalted fractions were separated into saturated hydrocarbons, aromatic hydrocarbons, and nitrogen-sulfur-oxygen compounds using temperatureactivated (400 °C) gravity-flow column chromatography. The C15+ saturated hydrocarbon fraction was subjected to molecular sieve filtration (Union Carbide S-115 powder), after the technique described by West et al. (1990). To determine biomarker distributions and quantities a gas chromatograph/mass spectrometry (GC/MS) analysis of C15+ branched/ cyclic and aromatic hydrocarbons was performed using an Agilent 7890 A GC, interfaced with a 5975C mass spectrometer at a constant flow rate. The J&W HP-5 column was temperature-programmed from 150 °C to 325 °C at 2 °C/min for the branched/cyclic fraction, and 100 °C–325 °C at 3 °C/min for the aromatic fraction. The mass spectrometer was run in the selected ion mode. To determine absolute concentrations of individual biomarkers, a deuterated internal standard (d4-C29 20 R ethylcholestane; Chiron Laboratories, Norway) was added to the C15+ branched/cyclic hydrocarbon fraction, and a deuterated anthracene standard (d10) was added to the aromatic hydrocarbon fraction. Response factors were determined by comparing the mass spectral response at m/z 221 for the deuterated standard to hopane (m/ z 191) and sterane (m/z 217) authentic standards. To analyze fragments of desired molecules, i.e alkyl aromatics for maturity calculations, GC/MS-MS was performed on an Agilent triple quadrupole mass spectrometer interfaced with an Agilent 7890 GC. To determine absolute concentrations of biomarkers, seven internal standards were used (n-dodecane-d26, n-hexadecane-d34, naphthalene-d8, phenanthrene-d10, dibenzothiophene-d8, cholestane-d2, C26 triaromatic steroid-d2). Bulk and compound-specific carbon isotope compositions (δ13C/ δ12C) of whole oils and C15+ saturate and aromatic hydrocarbon fractions were measured on an Isoprime vario ISOTOPE select elemental analyzer and VisION isotope ratio mass spectrometer. There was insufficient sample material for compound-specific isotope analysis of the extracts. Results are reported relative to Vienna Pee Dee Belemnite (VPDB), with an error margin of ± 0.4‰.

method is commonly used for samples that differ only slightly in composition. The distances represent the similarity between individual samples. PCA is an automated eigenvector analysis that includes an auto-scaling process to ensure the same significance for each parameter. The algorithm was set to calculate up to 8 factors. PCA was cross-validated to achieve an estimate of the true model residual variance. We used commercial software Pirouette® to perform these statistical evaluations. 9. Geochemical results 9.1. Source rocks 9.1.1. Port au port area We collected and analyzed 35 outcrop samples from the Port au Port area (Fig. 4). Four samples from the Middle Arm Point Formation (Floian) (Fig. 3) show TOC concentrations from 7.37 wt% to 9.45 wt% and HI values from 712 to 841 (Table 5, Fig. 5). Samples from the Table Cove Formation (Darriwilian) yield lower TOC (average 0.63%), yet smelled strongly of hydrocarbons on broken surfaces. Vitrinite reflectance was calculated based on Tmax after the empirical equation by Jarvie et al. (2001). Values lie between 0.65 and 0.89 %Rc. Selected samples are shown in Table 5. 9.1.2. Bay of Islands (Bay of Islands) We collected and analyzed 34 samples from the Cooks Brook and Middle Arm Point Formations of the Cow Head Group (Drumian to Tremadocian) in the Bay of Islands, three samples from the underlying Irishtown Formation, Curling Group, and 14 samples from Lobster Cove (?Cooks Brook Formation) (Figs. 3 and 4). TOC values for the richer intervals reach 2.21 wt% (Table 5). All samples show low S1 and S2 peaks and depleted HI and OI values (Fig. 5). Thermal maturities lie between 1.05 and 1.77 %Rc (calculated from Tmax). 9.1.3. Cow Head area 115 samples from seven measured sections were collected from the Cow Head area, including the Green Point Formation and Shallow Bay Formation, which represent depositional settings from proximal to distal continental slope and rise. Two intervals in the Green Point Formation are enriched in organic carbon (Fig. 6). The Cambrian portion of the Green Point Formation (Drumian to Furongian) shows TOC values from 0.06 wt% in the organically lean sections to 1.71 wt% in richer intervals. The second potential source rock interval is the Ordovician (Floian) portion of the Green Point Formation, with TOC values ranging from 0.06 wt% to 2.95 wt%. Average TOC for the 115 samples is 0.63 wt%. Calculated vitrinite reflectance ranges from 0.7 to 0.85 %Rc. Table 5 shows the key parameters for selected samples.

8. Multivariate analysis Multivariate statistical analysis provides a more robust interpretation than a hand-selected, potentially biased parameter selection. Typically, for chemometric analysis only age and source-related biomarker ratios are used, excluding biomarkers sensitive to biodegradation and maturity because they are unrelated to the source organic matter and can lead to erroneous classification (Peters et al., 2005). This chemometric approach is a factor-based process that classifies oil and source rock extract samples based on 17 source and age-related biomarker ratios, and 3 carbon isotope values (Tables 3 and 4). We relate identified oil families to corresponding source facies via an indirect oil-to-source correlation. A direct oil-to source correlation is only possible for samples with the same maturities. To evaluate the multivariate dataset and identify groupings we employ hierarchical cluster analysis (HCA) and principal component analysis (PCA). HCA includes auto-scaling followed by an iterative calculation of Euclidian distances and agglomerative linkage calculation (incremental) to establish clusters. The incremental linkage

10. Source rock extracts 10.1. Bulk composition Extracts from 23 source rocks and hydrocarbon-stained rocks with the highest petroleum potential were analyzed for biomarker and stable isotopes: 19 from the Cow Head area, originating from the Cow Head Group (Drumian to Darriwilian); and four from the Port au Port Peninsula, taken from the upper Cow Head Group (Floian) and Table Head Group (Darriwilian). Table 5 shows the bulk composition of the extracted hydrocarbons. The samples are relatively low in saturated hydrocarbons and higher in aromatic and NSO compounds (Table 5). Higher sulfur content is linked to higher NSO concentrations in the extracts. The carbon isotope values for whole extracts range from −28.46 to −32.36‰ (VPDB) (Table 5). 7

Oil

Bitumen

8

St. Pauls Inlet Parsons Pond

Green Point St. Pauls Inlet Port au Port

Port au Port

Area

Aguathun

a Tea Cove

Two Guts Pond Green Point

St. Paul Quarry Port au Port #1 Shoal Point

SM036A

SM033A

SM039B

SM050B

Sandy Point Well #7 Oil Point #2 Highland Brook 1 Highland Brook 2 Highland Brook W1 Highland Brook W2

SM057A SM058 SM060 SM062

SM067

SM066

SM063A

Fox Well

SM055A

SM072A

SM038

SM053B

West Bay

Well Name/ Location

SM034A

Sample ID

3

1.5

25

2 1 1 0

8

0

3457–3473

0

0

0

0

0

0

Sample Depth m.b.g.l

454270

454282

454448

453704 456884 457844 454753

442619

363778

335490

430352

442198

376861

356194

366159

355086

UTM Easting

5538364

5538382

5539167

5536605 5535944 5537994 5539277

5520723

5386982

5372856

5503851

5521295

5388097

5390914

5380192

5386933

UTM Northing

to

to

to

to

to

to

not enough sample

35.38

43.14

32.35 36.06 33.93 34.25

not enough sample 35.84

sample thick sample thick sample thick sample thick sample thick sample thick 45.23

API Gravity

0.11

0.05

0.14

0.10 0.13 0.15 0.12

0.09

0.32

0.16

0.61

0.67

1.43

4.13

%S

62.00

76.97

76.22

69.57 64.99 69.22 68.56

60.95

42.21

76.81

17.66

27.12

43.28

34.53

15.13

26.92

% Sat

28.50

11.71

17.42

20.29 26.53 23.81 22.90

31.24

43.53

15.07

29.13

32.71

29.84

38.57

26.41

30.77

% Aro

9.00

11.32

5.99

9.67 8.16 6.80 8.23

7.35

14.03

8.12

31.38

34.75

16.93

22.65

26.00

36.54

% NSO

0.50

0.00

0.37

0.48 0.31 0.17 0.30

0.46

0.24

0.00

21.82

5.42

9.95

4.26

32.46

5.77

% Asph

2.18

6.57

4.38

3.43 2.45 2.91 2.99

1.95

0.97

5.10

0.61

0.83

1.45

0.90

0.57

0.87

Sat/Aro

−30.83

−29.98

−30.18

−31.05 −30.70 −30.67 −30.47

−31.55

−30.43

−31.06

−29.85

−30.17

−30.70

−30.26

−30.59

−30.10

13Cs,

Table 2 Sample location for oil and bitumen samples collected from natural seeps and shallow wells, including bulk composition and stable carbon isotopes.

−30.32

−29.32

−29.44

−30.28 −29.71 −29.81 −29.47

−31.01

−29.49

−29.67

−29.19

−29.55

−30.43

−29.97

−30.08

−30.32

13Ca

−30.64

−29.94

−29.89

−30.93 −30.33 −30.59 −30.29

−31.45

−30.33

−30.56

−29.40

−29.86

−30.03

−30.37

−29.79

13Cwo

0.92

0.60

0.36

0.74 0.36 0.51 0.36

0.38

1.03

0.26

Pr/nC17

0.48

0.30

0.16

0.43 0.18 0.26 0.22

0.24

0.48

0.14

Ph/ nC 18

2.15

2.31

2.52

2.08 2.32 2.34 2.07

2.01

2.51

2.25

Pr/Ph

1.10

1.07

1.13

0.98 1.07 1.10 1.20

1.09

1.07

1.01

CPI

1.08

1.14

1.14

1.21 1.15 1.23 1.19

1.17

1.15

1.24

OEP

−0.98

−0.91

−0.66

−0.32 0.07 −0.22 0.01

−0.66

−0.14

1.06

−0.92

−0.92

−1.53

−1.63

−1.04

−2.80

CV

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Table 3 Source and age-related biomarker ratios used in the statistical analysis (HCA and PCA) of 10 oil samples. Well

C19/C23

C24/C23

C26/C25

Tet/C23

C31 R/H

C31 (22S/(22 S + 22 R)

C32 (22S/(22 S + 22 R)

C31/C33

C35S/C34S

BNH/H

TNH/H

Port au Port #1 Fox Well Sandy Point Well#7 Oil Point #2 Highland Brook 1 Highland Brook 2 Highland Brook W1 Highland Brook W2 Shoal Point

0.28 0.23 0.27 0.16 0.19 0.13 0.14 0.13 0.10 0.09

0.65 0.74 0.85 0.81 0.79 0.82 0.83 0.84 0.88 0.66

1.21 1.09 1.38 1.33 1.30 1.17 1.37 1.40 1.23 0.68

0.08 0.61 0.23 0.25 0.22 0.20 0.09 0.06 0.21 0.27

0.00 0.21 0.20 0.16 0.11 0.14 0.00 0.00 0.16 0.16

0.61 0.61 0.67 0.62 0.70 0.67 0.60 0.61 0.65 0.60

0.62 0.60 0.60 0.60 0.60 0.61 0.61 0.62 0.61 0.60

1.57 2.32 1.26 2.04 1.42 1.39 1.55 1.56 1.72 2.38

0.49 0.37 0.50 0.52 0.00 0.00 0.48 0.49 0.00 0.45

1.06 0.03 0.26 0.05 0.15 0.16 0.94 1.31 0.10 0.02

1.06 0.42 0.52 0.46 0.38 0.52 0.03 5.71 0.42 0.51

Well

BNH/TNH

% C27

% C28

% C29

C28/C29

C27DIA/(DIA + REG)

%C27 MAS

%C28 MAS

%C29 MAS

13Cs

13Ca

13Cwo

Port au Port #1 Fox Well Sandy Point Well#7 Oil Point #2 Highland Brook 1 Highland Brook 2 Highland Brook W1 Highland Brook W2 Shoal Point

0.00 0.10 0.26 0.20 0.00 0.07 0.26 0.26 0.09 0.23

29.23 28.15 27.40 28.14 28.21 26.71 26.76 27.60 27.29 25.94

30.51 24.98 31.81 27.05 31.25 29.56 29.18 30.60 31.13 24.47

40.26 46.87 40.79 44.81 40.54 43.73 44.06 41.79 41.58 49.59

0.51 0.39 0.57 0.46 0.58 0.49 0.52 0.56 0.53 0.36

0.59 0.42 0.50 0.34 0.47 0.40 0.33 0.47 0.44 0.12

26.30 23.47 29.01 26.22 28.91 28.22 27.06 27.36 29.29 17.09

31.12 34.19 31.22 32.00 30.55 28.95 27.29 28.73 30.08 37.08

42.57 42.34 39.77 41.78 40.54 42.83 45.65 43.91 40.63 45.83

−31.06 −31.55 −31.05 −30.70 −30.67 −30.47 −30.18 −29.98 −30.83 −30.43

−29.67 −31.01 −30.28 −29.71 −29.81 −29.47 −29.44 −29.32 −30.32 −29.49

−30.56 −31.45 −30.93 −30.33 −30.59 −30.29 −29.89 −29.94 −30.64 −30.33

10.2. Biomarker analyses

11. Oil samples

The chemometric analysis identified three extract groups, using 17 biomarker ratios, and three carbon isotope values that are only influenced by the source and age of the organic matter (Table 4) (Peters et al., 2005). The first group (Furongian samples) is characterized by the highest ratios of bisnorhopane/hopane (BNH/H), C26/C25, and C31/C33. The second group (Floian samples) has the most positive carbon isotope compositions and the highest C19/C23 ratios. Ratios of C24/C23, Tet/C23, C35S/C34S, and trisnorhopane/hopane (TNH/H) are the lowest in this group. The third group (Floian to Darriwilian samples) is characterized by the lowest ratios of C31 (22S/ (22 S + 22 R), C32 (22 S/(22 S + 22 R), BNH/H, and the lightest carbon isotope composition. All other selected biomarker ratios are higher in the third group than in the other two groups. The same groupings are evident when considering source and maturity dependent ratios, such as S/H, TET/C23, and C26(R + S)/Ts, which are higher in group two (Floian to Darriwilian) samples and smaller in the other groups (Fig. 7a and b). These groupings are also apparent for terpanes and aromatic biomarkers, such as TNH, BNH, phenanthrene, and methylphenanthrenes including associated isomers (3-MP, 2-MP, 1-MP, 9-MP) (Table 6, Fig. 7).

11.1. Whole oil analysis Table 2 lists geochemical parameters for analyzed oil samples. They show high API° gravity (32°–45°), low total sulfur (0.05–0.32%), δ13C, saturated, aromatic and low NSO compounds (7–14%), key isoprenoid ratios, and carbon preference index (CPI range from 1.07 to 1.09). Saturates are the dominant hydrocarbon components (62–77%) except in sample SM072A from Shoal Point (%Sat = 42.21%). Pristane/phytane ratios range from 2.01 to 2.52. Oils from the study areas (Port au Port Peninsula and Cow Head area) show full n-alkane profiles with minimal unresolved complex mixtures (UCM) underlying the profiles (Fig. 9). 11.2. Carbon isotopes for oil The δ13C compositions of the saturated and aromatic fractions and whole oil portions of the 11 oil samples range from −29.89 to −31.45‰ VPDB (δ13Cwo) (Table 2). Eight samples had sufficient material for compound-specific carbon isotope analysis. Four of these preserve the light ends, allowing the collection of the n-alkane envelope down to nC-6. The remaining four have lost their light ends to varying degrees (Fig. 10). Most samples preserve insufficient amounts of n-alkanes greater than nC-27 to provide viable data in this range. The chromatography of the oils preserves several patterns (Fig. 10). Sample SM055A (Fox Well, St. Paul's Inlet) has the most negative δ13C for all analyzed compounds, while samples SM066 and SM063A (Parson's Pond) show the most isotopically positive compounds. The remaining five oil samples show intermediate carbon isotopic values. The isotopic trend of the n-alkanes for samples SM066, SM063A, and SM038 shows a relative depletion in δ13C for alkanes nC-10, nC-13, and nC-17 and relative enrichment in nC-12, nC-14, and nC-25. Sample SM055A shows depleted δ13C values for alkanes nC-10, nC-12, nC-17, and nC-28. All oil samples demonstrate increasingly depleted isotopic values with increasing carbon number.

10.3. Maturity indicator We evaluate thermal maturity of extracts with standard maturity indicators from tri-aromatic steranes (TAS1 and TAS2) and phenanthrene ratios (MPI-I). Tri-aromatic ratios TAS 1 (C20/[C20 + C27] triaromatic steranes) range between 0.4 and 0.8 and TAS 2 (C21/ [C21 + C28] triaromatic steranes) range between 0.1 and 0.5. The Methylphenanthrene Index (MPI-I = 1.5*[3 MP+2 MP]/[P+9 MP +1 MP]) has low values between 0.3 and 0.5. A positive correlation exists amongst related maturity indices, for example, TAS1 versus TAS2 and MPI versus phenanthrene indices (Fig. 8a and b), but not across independent maturity indices (e.g. TAS1 versus MPI with R2 = −0.1, or MPI versus Tmax with R2 = 0.05). A weak correlation (R2 = 0.46) exists between TAS1 and Tmax, and TAS2 and Tmax. 9

Table Cove Shallow Bay Shallow Bay Green Point Green Point Shallow Bay Shallow Bay Middle Arm Point Middle Arm Point Middle Arm Point Green Point Green Point Green Point Green Point Green Point Green Point Green Point Green Point Green Point

PA009A PA049A PA050A SM056D SM064A SM068B SM068D SC003A

10

BNH/H

5.86 5.49 4.32 10.04 6.82 5.35 7.93 6.05 6.61 6.61 9.13 11.01 9.95 10.73 10.01 8.25 9.82 8.87 8.03

Sample ID

PA009A PA049A PA050A SM056D SM064A SM068B SM068D SC003A SC004A SC005A PA032A SM077M SM052C SM054A SM054D SM054P SM054S SM077B SM077E

PA032A SM077M SM052C SM054A SM054D SM054P SM054S SM077B SM077E

SC005A

SC004A

Formation

Sample ID

2.53 2.59 2.93 3.18 3.37 2.23 1.88 1.79 1.90 1.93 1.80 2.05 1.86 2.51 2.27 2.85 2.92 1.79 2.30

TNH/H

Forungian

Floian

FloianDariwilian

Age

0.43 0.47 0.68 0.32 0.49 0.42 0.24 0.30 0.29 0.29 0.20 0.19 0.19 0.23 0.23 0.35 0.30 0.20 0.29

BNH/TNH

0.00 0.04 0.00 0.01 0.00 0.00 0.00 0.01 0.01

0.03

0.04

0.01 0.04 0.06 0.02 0.02 0.10 0.09 0.05

C19/C23

27.56 30.15 31.47 42.95 31.67 29.74 26.04 33.76 32.63 32.76 31.31 33.13 28.48 33.19 35.52 33.28 34.74 30.71 33.62

% C27

0.53 0.60 0.64 0.54 0.88 0.49 0.63 0.62 0.69

0.40

0.42

0.75 0.74 0.71 0.62 0.67 0.73 0.57 0.42

C24/C23

20.39 23.44 23.42 20.19 22.81 23.25 24.35 25.02 23.49 24.32 22.49 23.96 23.17 23.23 22.07 25.60 25.79 22.68 24.28

% C28

1.20 1.14 1.19 1.32 1.59 1.22 1.28 1.25 1.38

1.19

1.21

1.12 0.92 1.19 1.24 0.92 0.94 0.97 1.30

C26/C25

52.05 46.41 45.11 36.85 45.53 47.02 49.61 41.21 43.88 42.92 46.21 42.91 48.35 43.58 42.41 41.11 39.47 46.61 42.09

% C29

0.61 0.59 0.65 0.64 1.90 0.76 1.27 0.69 0.62

0.29

0.26

0.32 0.36 0.62 0.76 0.43 0.35 0.46 0.28

Tet/C23

Table 4 Source and age-related biomarker ratios used in the statistical analysis (HCA and PCA) of 23 source rock extract samples.

0.31 0.39 0.43 0.41 0.40 0.37 0.36 0.38 0.34 0.35 0.32 0.39 0.35 0.36 0.32 0.41 0.40 0.34 0.38

C28/C29

0.18 0.15 0.17 0.18 0.19 0.20 0.16 0.18 0.18

0.18

0.18

0.22 0.23 0.25 0.19 0.20 0.23 0.20 0.21

C31 R/H

0.26 0.27 0.22 0.26 0.29 0.30 0.29 0.16 0.15 0.14 0.19 0.25 0.26 0.21 0.21 0.20 0.20 0.26 0.27

C27 DIA/ (DIA + REG)

0.54 0.55 0.55 0.54 0.54 0.57 0.60 0.56 0.57

0.53

0.53

0.52 0.48 0.51 0.54 0.52 0.50 0.51 0.54

C31 (22S/ (22 S + 22 R)

−32.00 −29.81 −31.26 −31.00 −31.27 −31.46 −30.53 −29.10 −29.11 −29.35 −29.85 −30.20 −30.81 −30.22 −29.48 −30.75 −29.65 −30.18 −30.69

13Cs

0.60 0.63 0.66 0.66 0.58 0.56 0.57 0.59 0.68

0.56

0.57

0.55 0.55 0.63 0.70 0.58 0.56 0.56 0.56

C32 (22S/ (22 S + 22 R)

−30.89 −30.12 −31.22 −30.48 −29.55 −29.85 −29.21 −28.01 −28.08 −28.08 −28.66 −28.93 −30.23 −29.49 −28.93 −30.63 −29.73 −29.50 −30.55

13Ca

1.12 0.47 0.63 0.44 0.64 0.97 0.79 1.49 0.69

0.38

0.43

0.26 0.18 0.22 0.12 0.15 0.22 1.21 0.36

C31/C33

−31.24 −30.81 −31.51 −30.71 −30.59 −30.96 −30.28 −28.46 −28.46 −28.52 −29.22 −29.59 −29.82 −29.91 −29.09 −30.46 −29.66 −29.87 −30.58

13Cwo

0.41 0.56 0.58 0.48 0.00 0.50 0.70 0.42 0.91

0.44

0.42

0.52 0.52 0.64 0.55 0.68 0.48 0.39 0.42

C35S/C34S

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1.10 1.09 1.17 1.21 1.17 1.19 1.15 1.16 1.20 1.26 1.16 1.26 1.23 1.11 1.30 1.18 1.12 1.21 1.14 1.20 1.17 1.15 1.22 −31.24 −30.81 −31.51 −30.71 −30.59 −30.96 −30.28 −28.46 −28.46 −28.52 −32.06 −30.68 −32.32 −29.18 −29.22 −29.59 −29.82 −29.91 −29.09 −30.46 −29.66 −29.87 −30.58 −30.89 −30.12 −31.22 −30.48 −29.55 −29.85 −29.21 −28.01 −28.08 −28.08 −31.29 −30.40 −31.85 −28.69 −28.66 −28.93 −30.23 −29.49 −28.93 −30.63 −29.73 −29.50 −30.55 −32.00 −29.81 −31.26 −31.00 −31.27 −31.46 •30.53 −29.10 −29.11 −29.35 −30.82 −30.81 −31.00 −29.57 −29.85 −30.20 −30.81 −30.22 −29.48 −30.75 −29.65 −30.18 −30.69 0.00 1.15 0.00 0.00 2.13 0.70 0.00 0.44 0.86 6.20 0.00 12.07 1.82 0.00 7.89 3.28 0.00 6.90 0.00 0.00 0.00 4.65 0.00 35.00 37.93 44.23 45.95 51.06 24.65 34.85 37.99 40.40 39.15 30.16 36.21 34.55 38.46 55.26 32.79 54.29 34.48 50.00 44.19 69.57 34.88 40.62 1.62 6.57 1.52 3.75 4.06 7.98 8.66 76.25 67.83 52.49 1.62 11.5 1.48 12.65 2.48 5.99 3.04 5.63 5.13 4.1 2.34 3.29 2.34

257 361 228 321 276 355 408 841 718 712 244 390 279 512 260 344 279 391 340 350 271 276 259

6 16 24 15 20 17 18 6 7 6 11 0 8 6 2 6 12 8 8 13 9 2 12

443 441 442 441 439 447 440 435 434 434 444 441 439 443 439 443 439 439 442 436 437 446 446

0.81 0.78 0.80 0.78 0.74 0.89 0.76 0.67 0.65 0.65 0.83 0.78 0.74 0.81 0.74 0.81 0.74 0.74 0.80 0.69 0.71 0.87 0.87

Oil samples from old well sites and natural seeps have the potential to show recent biodegradation. We use Biodegradation scales from Wenger et al. (2002), and Peters and Moldowan (1993) (PM scale) to assess biodegradation levels in the oils. Table 7 summarizes the petroleum compounds that are quasi-sequentially removed with increasing biodegradation. All oil samples retain their cyclic saturated biomarkers; therefore, biodegradation is characterized as “light” (from 1 to 3) on the PM scale. Three samples (SM057, SM060, and SM066) are heavily biodegraded on the Wenger et al. (2002) scale, due to partial n-alkane removal and loss of alkylcyclohexane (Table 7). These samples also show the development of an unresolved complex mixture (UCM). There is no systematic geographic distribution of biodegraded and non-biodegraded oil samples. Counter to the oil samples, bitumen samples have a biodegradation level of 6–7 on the PM scale, because all isoprenoids have been removed and steranes are also affected; therefore, these samples cannot be reliably used for correlation (Peters and Moldowan, 1993). 11.5. Maturity indicators

Table Cove Shallow Bay Shallow Bay Green Point Green Point Shallow Bay Shallow Bay Middle Arm Point Middle Arm Point Middle Arm Point Green Point Green Point Green Point Green Point Green Point Green Point Green Point Green Point Green Point Green Point Green Point Green Point Green Point PA009B PA049A PA050A SM056D SM064A SM068B SM068D SC003A SC004A SC005A SM078D3 SM078H′ SM079Da SM078La PA032A SM077M SM052C SM054A SM054D SM054P SM054S SM077B SM077E

Forungian

Formation

Floian

0.63 1.82 0.67 1.17 1.47 2.25 2.12 9.07 9.45 7.37 0.67 2.95 0.53 2.47 0.95 1.74 1.09 1.44 1.51 1.17 0.86 1.19 0.91 Floian -Darriwilian

Tea Cove1 Cow Head2 Cow Head1 St. Paul's InletN2 Parsons Pond Cow Head2 Cow Head2 Tea Cove1 Tea Cove1 Tea Cove1 Black Brook1 Black Brook2 Long Point2 Black Brook2 Green Point2 The Scrape2 Broom Point2 Green Point2 Green Point2 Green Point2 Green Point2 The Scrape2 The Scrape2

0.34 1.39 0.44 0.41 0.41 2.26 1.12 3.05 3.45 3.07 0.28 0.71 0.23 0.66 0.21 0.59 0.34 0.42 0.45 0.28 0.20 0.35 0.22

Cwc 13

Ca 13

Cs 13

% Asph % NSO %S %Ro Tmax OI HI S2 TOC Age Measured Section

S1

1.06 1.13 1.13 1.18 1.20 1.08 1.22 1.29 1.27 1.15 1.16 1.11 1.11 1.09 1.21 1.19 1.11 1.21 1.21 1.10 1.31 1.20 1.10 22.50 24.14 23.08 32.43 31.91 33.10 20.71 40.61 44.13 39.15 30.16 36.21 20.00 39.42 26.32 39.34 11.43 41.38 40.62 34.88 26.09 41.86 46.88 42.50 36.78 32.69 21.62 14.89 41.55 44.44 20.96 14.61 15.50 39.68 15.52 43.64 22.12 10.53 24.59 34.29 17.24 9.38 20.93 4.35 18.60 12.50 0.66 0.36 0.27 0.72 1.63 0.55 0.26 0.66 1.84 1.06 0.43 8.43 1.27 0.69 0.49 0.74 1.06 0.81 1.61 0.74 1.51 0.96 2.31

11.4. Biodegradation

CPI % Aro % Sat

OEP

11.3. Biomarker analysis The multivariate biomarker analysis applies 20 different age and source-related biomarker ratios and three carbon isotope values to distinguish the oils compositionally (Table 3). These are the same parameters used to characterize the extracts, with the addition of monoaromatic steranes. It identifies three groups among the oil samples. Group one includes two samples from geographically different locations (Port au Port Peninsula, and St. Paul's Inlet). These oils are characterized by the lowest BNH/H, S/H, C26(R + S)/Ts, the highest C31/C33, Tet/C23, and high TNH and dibenzotheophene (DBT) (Figs. 7 and 11). The second group contains five oils from Parsons Pond, showing intermediate ratios and values of the listed. The third group contains one sample from Port au Port Peninsula and two from Parsons Pond, characterized by the highest Sat/Aro and BNH/H ratios. They present high S/H and C26(R + S)/Ts ratios, low Tet/C23 ratios, low concentrations of TNH, BNH, and DBT, but high phenanthrene and methylphenanthrene concentrations. C31 and hopane are too low to calculate a C31/H ratio (Fig. 7). Additional source- and maturity-dependent biomarker ratios (the same as for extracts) are used to further evaluate compositional differences. The biomarker ratios S/H and C26(R + S)/Ts show higher values in group one. Terpanes and aromatic biomarkers (TNH, BNH, P, 3-MP, 2-MP, 1-MP, 9-MP) cluster the samples in the same three groups stated above (Fig. 7).

Sample ID

Table 5 Rock eval data for 23 selected source rock samples and bulk composition for source rock extracts.1 Measured sections from Lacombe (2017);2 Measured section from James and Stevens (1986);a Samples excluded from statistical analysis due to missing data.

M. Schwangler, et al.

Thermal maturity of oils is assessed using a combination of sterane, terpane, and their associated methylated homologs (MPI-1) (Radke et al., 1982), to calculate an equivalent vitrinite reflectance (%Rc). This ratio depends on thermal maturity while being negligibly influenced by biodegradation and organic facies (Radke, 1988). To conduct a robust and independent maturity evaluation, we calculated 13 naphthalene and phenanthrene ratios, giving a consensus maturity for each sample. This converts into a vitrinite reflectance equivalent (VREQ-5) value (Fig. 12). Fig. 8c illustrates the equilibrium envelope for C29 (20S/ 20 S + 20 R) and C29 ββ/(ββ+αα). Equilibrium for 20S/(20 S + 20 R) is reached at 0.52 to 0.55 (equivalent to maturity of 0.8 ± 0.1 Ro%) and for ββ/(ββ+αα) at 0.67 to 0.71 (equivalent to maturity of 0.9 ± 0.1 Ro%). Values for 20S/(20 S + 20 R) fall below the equilibrium ratio, whereas ratios for ββ/(ββ+αα) show values above 0.74 (above the equilibrium ratio) for SM038 (Port au Port No. 1 well, Port au Port Peninsula), SM063A (Highland Brook 2, Parson's Pond), SM066 (Highland Brook W1, Parson's Pond), and SM057A (Sandy Point, 11

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The listed terpane ratios depend on both the thermal maturity of the samples and the organic matter input, therefore, they cannot be used independently for a maturity evaluation (Seifert and Moldowan, 1978; Ourisson et al., 1984; Peters et al., 2005). Conversion from Tm to Ts starts at relatively high maturities, allowing us to evaluate higher maturity oils (above 0.75 %Ro to 1.3 %Ro). An increase in Ts/Tm ratios can be observed if the release and subsequent thermal destruction of Tm exceeds the concentration of Ts (Farrimond et al., 1998). An inversion of Ts/Tm can occur beyond this maturity range that is related to differential destruction of Tm and Ts (Requejo, 1994; Farrimond et al., 1996). Based on MPI-1, samples SM055A (Fox Well) and SM072A (Shoal Point) represent the lowest maturity (0.7 %Rc) (Fig. 10). Sample SM038 from the Port au Port #1 well exhibits the highest maturity in all maturity-dependent sterane and terpane ratios. To calculate equivalent vitrinite reflectance based on MPI-I, two empirical formulas are used depending on the expected maturity: Rc = 0.6MPI1+0.4 [for 0.65 to 1.35 %Rm], Rc = −0.6MPI1 = 2.3 [for 1.35 to 2.0 %Rm] (Radke et al. (1982). Based on these the calculated vitrinite reflectance for oil SM038 is 1.5%Rc and 1.16 %Rc, respectively (depending on different mean vitrinite reflectance ranges), equivalent to the wet gas to condensate window. This sample also has a high API° gravity (= 45.23), and VREQ-5 is 1.26 %Rc which associates it with the light oil field. All other samples fall between 0.73 and 0.91 %Rc.The VREQ-5 values for the collected oils are consistent with the MPI-1 index but show between 0.1 %Ro and 0.25 %Ro higher calculated vitrinite reflectance values across all samples.

Fig. 5. Modified van Krevelen diagram from source rocks collected along the western coast of Newfoundland including 170 km of coastal outcrop from the Port au Port Peninsula area, Bay of Island to the Cow Head area. Samples were collected from the Cow Head Group (slope and rise) and Table Head Group (platform). Different shades of green represent different formations within the Cow Head Group. Platform samples are represented in blue. (For interpretation of the references to colour in this figure legend, the reader is referred to the Web version of this article.)

12. Interpretation and discussion The data reported enable us to assess the quality and distribution of lower Paleozoic source rocks, characterize oils, bitumen, and extracts, and relate oils to source rock intervals from the study area. To perform a direct oil-to-source rock correlation, it is necessary that the thermal maturity of source rock extracts, source rocks, and oils are comparable (Peters et al., 2005). However, in this study, some analyzed source rock extracts have different maturities than oil samples. Thus, an indirect oilsource rock correlation can be realized.

Parson's Pond) but below the equilibrium ratio for the remaining samples. Sterane and terpane isomerization ratios are listed in Appendix B. C27 ββ/(ββ+αα) ratios exceed the C29 ββ/(ββ+αα) ratios, except for samples SM038 and SM066. Terpane ratios of moretane/hopane and Ts/Tm are shown in Fig. 8d. Terpane ratios include moretane/hopane (0.07–0.22) and tricyclic/hopane (0.25–9.49, higher ratios indicate thermally evolved samples), and 17α(H)-trisnorhopane/18α(H)- trisnorneohopane (Ts/ Tm = 1.05 to 6.6, higher ratios indicate thermally evolved samples).

Fig. 6. Pyrolysis analyses identify two potential source intervals. High TOC wt%, high Hydrogen Index, and high Petroleum Potential (S1+S2) characterize Cambrian Series 3 to 4 and Middle Ordovician intervals. S = Source rock; R = Reservoir; WBP = Western Brook Pond Group; Samples selected for extract analysis are highlighted in red and green (Ordovician clusters from HCA and PCA) and brown (Cambrian cluster). (For interpretation of the references to colour in this figure legend, the reader is referred to the Web version of this article.) 12

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Fig. 7. Selected graphs for the source parameters for Cambrian and Ordovician sample. (a) Source dependent ratios of C24/C23 terpanes and C22/C21 terpanes indicating that source rock extracts originate from marine shale. (b) Source dependent ratios of C31R/Hopane and C26/C25 terpanes indicating that source rock extracts originate from marine shale and marl. (c) Source dependent ratios showing higher sterane/hopane ratios and lower TET/C23 ratios for Ordovician samples and lower sterane/hopane ratios and higher TET/C23 ratios for Cambrian samples. (d) Source dependent sterane/hopane to C26(R + S)/Ts showing lower ratios for Cambrian samples compared to Ordovician samples. (e) The sum of methylphenanthrenes (3-MP, 2-MP, 1-MP, 9-MP) versus phenanthrene concentrations showing substantially higher concentrations in Ordovician samples than in Cambrian samples.

13

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Table 6 Selected source parameters for Ordovician and Cambrian samples used to generate graphs presented in Fig. 7.

oil

Extract

Sample ID

P

3 MP

2 MP

9 MP

1 MP

SUM MP

DBT

TET/C23

S/H

C26(S + R)/Ts

C27T

C28H

SM038 SM055A SM057A SM058 SM060 SM062 SM066 SM067 SM072A SM063A PA009B PA049A SC003A SC004A SC005A SM056D SM064A SM068B SM068D PA050A SM077M SM054A PA032A SM052C SM054D SM054P SM054S SM077B SM077E

153.64 45.41 26.38 65.44 23.21 35.25 5.65 7.88 76.25 16.47 2.11 24.26 404.01 342.93 248.22 5.53 19.67 95.56 376.26 5.44 68.02 1.19 2.28 4.53 1.01 0.95 1.12 2.12 1.22

482.03 37.96 65.26 95.28 86.22 81.41 6.16 18.83 40.64 17.64 4.35 58.07 144.86 150.99 115.62 15.65 57.58 114.54 248.85 15.43 99.99 1.52 11.72 3.16 0.27 1.63 0.40 9.92 1.86

590.92 39.16 64.69 99.59 86.45 87.92 5.87 18.96 43.12 17.06 6.16 73.01 179.79 182.45 135.91 22.08 79.89 138.20 295.46 17.90 124.10 1.85 18.67 4.33 0.34 2.18 0.47 14.48 2.51

457.68 137.29 186.35 224.12 249.62 188.67 19.12 61.92 124.38 51.75 24.69 252.45 414.34 377.58 284.82 86.73 287.71 372.32 866.64 68.19 477.53 5.71 69.81 14.04 0.50 9.33 1.14 74.59 12.52

232.48 51.30 65.47 87.50 77.48 72.76 7.62 22.11 55.40 16.84 10.26 128.44 257.66 236.14 185.92 55.37 151.94 202.87 500.74 34.46 232.52 3.53 44.51 9.39 0.35 5.79 0.37 30.03 5.30

1763.12 265.71 381.77 506.49 499.77 430.75 38.77 121.82 263.53 103.29 45.45 511.97 996.65 947.16 722.28 179.83 577.12 827.93 1911.69 135.98 934.13 12.61 144.71 30.91 1.45 18.93 2.38 129.02 22.19

2.65 9.46 3.12 6.43 2.22 5.13 1.50 0.83 24.62 3.28 – – 62.42 66.47 52.91 2.92 1.28 2.56 23.56 – 10.06 1.07 9.34 6.55 0.38 1.94 1.07 0.84 0.00

0.08 0.61 0.23 0.25 0.22 0.20 0.06 0.21 0.27 0.09 0.32 0.36 0.28 0.26 0.29 0.76 0.43 0.35 0.46 0.62 0.59 0.64 0.61 0.65 1.90 0.76 1.27 0.69 0.62

11.01 0.50 1.94 0.97 1.84 1.78 6.02 1.46 0.51 6.65 0.97 1.23 0.70 0.53 0.58 0.66 1.15 1.24 0.38 0.74 0.32 0.40 0.25 0.39 0.32 0.23 0.22 0.19 0.25

3.66 0.44 0.67 0.78 0.83 1.17 3.15 0.90 0.45 2.14 0.69 0.75 0.59 0.63 0.55 0.31 0.63 0.80 0.50 0.30 0.33 0.44 0.31 0.36 0.23 0.27 0.19 0.22 0.24

0.00 0.15 0.11 0.12 0.00 0.05 0.03 0.08 0.34 0.07 4.29 4.58 30.63 72.03 49.87 36.71 28.44 9.72 20.49 7.77 38.82 46.36 102.37 7.30 13.01 47.63 27.59 69.56 10.25

0.00 0.03 0.06 0.08 0.07 0.06 0.06 0.15 0.16 0.03 0.48 0.19 0.60 1.20 0.84 1.31 1.41 0.44 0.71 0.94 1.11 1.14 1.81 0.27 0.00 1.39 1.05 1.95 0.26

13. Source rock quality and distribution

and organically rich beds (Botsford, 1987; James and Stevens, 1986). TOC content is on average 0.55 wt%, but demonstrates good source potential in organically rich layers reaching a maximum of 2.21 wt% (Cooks Brook Formation, Seal Cove),. A significant number of samples represent lean intervals, with TOC values less than 0.5 wt%. The modified Van-Krevelen diagram characterizes the Cambrian (Series 3 to Furongian) source rock as type II/III organic matter. The approximated total thickness for the organically enriched layers (TOC > 1 wt%) is 9–45 m thick. Both source intervals fall into the low to mid-mature window (0.65–0.89 %Ro) in outcrops, based on Tmax pyrolysis data. The high measured S1 and S2 values demonstrate the remaining petroleum production potential for these units (Fig. 6). A large sample set collected in the Bay of Islands and on Lobster Cove (Cow Head area) shows poor petroleum potential at present day (Fig. 6). Low S1 and S2 peaks, and depleted HI and OI values in combination with high Tmax data (456–496 °C), and high production indices (PI) support the interpretation of post-mature source rock. These pyrolysis data are associated with samples from source rocks that are juxtaposed against or overlain by ophiolites (Fig. 4). Further, the petroleum potential increases with increasing distance from the ophiolite complex. Additionally, Waldron et al. (2003) recognized cleavage in the interior of the Bay of Islands, related to folding and thickening of the thrust stack. During emplacement of the ophiolite, margin and deep marine sediments are accreted in slices and as mélange to the base of the encroaching ophiolite (Stevens, 1970). Evidence for fluid overpressure and hydrocarbon migration exists within the mélange (Lacombe et al., 2019). Subsequent thermal maturation produced solid bitumen residue found in extensional fractures in allochthonous rocks (Lacombe et al., 2019). We interpret that the emplacement of ophiolites over deep marine deposits in the Bay of Islands area during the Taconian orogeny and the folding events leading to thickening of the thrust stacks caused deep burial and over-maturation of potential source rocks. We conclude that the Cooks Brook Formation and Middle Arm Point Formation in the Bay of Islands area had similar original petroleum

We first consider the quality and thicknesses of source rock units and assess the viability of source intervals based on thermal maturity (Tmax) and production index (PI). We then discuss over-mature samples in the Bay of Islands and Lobster Cove in light of relevant tectonic events, calculating the original TOC content. The pyrolysis data show two source rock intervals: one within the Early Ordovician Green Point Formation and more distal Middle Arm Point Formation, the second in the Furongian Green Point Formation and Cooks Brook Formation. Samples collected from ‘platform succession’ (e.g. Table Cove) did not show significant source rock potential (Table 5). The study area includes 170 km of coastal outcrop with significant lateral heterogeneities. Thus, we cannot correlate individual beds across measured sections or demonstrate systematic changes in TOC content or organic matter type from proximal to distal continental slope. The Early to Middle Ordovician Green Point and Shallow Bay formations contain 1.8 wt% average TOC, with maximum values of 2.95 wt% TOC (Table 5). The richest source intervals occur in Early Ordovician Middle Arm Point Formation, the most distal portion of the continental slope (Botsford, 1987). These samples show excellent potential with type I/II organic matter and high TOC (max. 9.45 wt%) (Fig. 6). This formation was identified as enriched in organic carbon by Macauley (1987, 1990), Weaver (1988), Weaver and Macko (1988), Sinclair (1990), and Fowler et al. (1995), who reported even higher TOC values (7.19 wt% to 10.35 wt%). The stratigraphic thickness of these three formations is approximately 150–250 m, based on outcrop measured sections (Botsford, 1987; James and Stevens, 1986). To estimate the total thickness of the organically enriched sections, we multiplied the fraction of TOC rich samples (TOC > 1 wt%) with the overall section thickness. Based on this, the organically enriched sections are 14–23 m thick. A second source exists in Cambrian Series 3 to Furongian Green Point Formation and Cooks Brook Formation (Fig. 6). The source rock interval is between 50 and 200 m thick, constituting interbedded lean 14

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Fig. 8. Different maturity indices for source rock extracts and oils showing (a) Plot of TAS 1 (C20/[C20 + C27] triaromatic steranes) and TAS 2 (C21/[C21 + C28] triaromatic steranes) showing positive correlation (R2 = 0.75). (b) Plot of maturity indicators MPI = 1.5*[3 MP+2 MP]/[P+9 MP+1 MP]) and F1 (F1 = [3 MP +2 MP]/[3 MP+2 MP+9 MP+1 MP])showing positive correlation (R2 = 0.69). (c) Sterane isomerization ratios for C29 20S/(20 S + 20 R) versus C29 ββ/ (αα + ββ); equilibrium envelope is indicated by grey area. (d) Moretane/hopane and Ts/Tm ratios showing two different regression lines potentially associated with two different sources. (e) Diahopane versus hopane (f) tricyclics versus hopane, indicating two endmember oils and potential mixing.

potential to the equivalent rocks on Port au Port Peninsula and Cow Head area. To demonstrate this, we back-calculated the original TOC, S1 extractable, and the conversion factor for over-mature samples from the Bay of Islands using mass balance equations developed by Cooles et al. (1986). These equations require assumptions on the original production index (PIo) and hydrogen index (HIo). To approximate HIo, we used the range of HI values measured on immature samples from the Middle Arm Point Formation on Port au Port Peninsula (400–800) and assumed a PIo of 0.02. The results establish that the original TOC was substantially higher (Table 8) and comperable to measured data for the immature Middle Arm Point Formation on the Port au Port Peninsula.

rocks. Following this, we compare the thermal maturity derived from biomarkers with calculated %Rc from Tmax. We derive the depositional environment for the source rocks from biomarkers, evaluate changes in the depositional environment, and investigate age-related biomarkers associated with Cambrian and Ordovician source rocks. 13.2. Chemometric analysis To identify systematic changes in the extracts, we use a chemometric approach. Source and age-related biomarkers (Table 4) identify three distinct groups of source rock extracts related to a compositional change in organic matter from the Cambrian to the Ordovician (Fig. 13). Groups 1 and 2 are closely related and contain source rock extracts from the same stratigraphic interval (group 1 -upper FloianDariwillian; group 2 - Floian). Group 3 includes samples from the Cambrian Series 3 to Furongian source interval.

13.1. Source rock extracts We now interpret biomarker data collected from extracts. Source and age-related parameters are combined in a multivariate chemometric approach, establishing clusters of geochemically similar source 15

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Fig. 9. Flame Ionization Detector signal for saturated hydrocarbons from C9 – C41 n-alkanes. GCMS/MS fingerprints for monoaromatic steroids (m/z 253.2 - > m/z 143.1), steranes (m/z 217.2 - > m/z 149.1), and tricyclic terpanes and pentacyclic terpanes (m/z 191.1 - > m/z 149.1) of three representative samples characterizing the oil families in western Newfoundland (group 1 = green, group 2 = red, and group 3 = brown, respectively). The selected samples have maturities of 0.91 %Rc (SM055A), 1.03 %Rc (SM063A), and 1.11 %Rc (SM062) based on VREQ-5 calculations. The three samples shown have a biodegradation level of PM 0–1 (Peters and Moldowan, 1993). Peak identification for monoaromatic steroids: 21 = C21A monoaromatic steroid; pk10 = C28R Type I & V, C29S Type I & V. Peak identification for steranes: 19 = C19, 21 = C21, C27 = cholestane; C29 = stigmastane. Peak identification for tricyclic and pentacyclic terpanes: T23 = C23H42 tricyclic terpane, H30 = 17a, 21 b-hopane. (For interpretation of the references to colour in this figure legend, the reader is referred to the Web version of this article.)

13.3. Extract maturity

correlation between Tmax and TAS1 and TAS2 exists. Samples SM054D and SM054P are only 50 m stratigraphically apart from each other, yet their Tmax values vary by 6 °C (442–436 °C). Thus, the data spread and lack of correlation between independent maturity parameters must be

It is expected that the thermal maturities calculated from Tmax and from biomarkers have a positive correlation. However, only a weak

Fig. 10. Compound-specific carbon isotope profiles showing δ13C (VPDB) values for 8 oil samples Error bars show estimated precision of ± 0.4‰. 16

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Fig. 11. Source-dependent ratios indicating depositional environment. (a) Pristane/phytane versus dibenzothiophene/phenanthrene (DBT/P) indicating a marine shale as source rock (Hughes, 1984). (b) Pristane/nC17 versus phytane/nC18 indicating slightly oxidizing depositional environment. (c) Ternary diagram showing the sterane distribution of oil and extracts. (d) Ternary diagram depicting monoaromatic steranes distribution of oil samples. (e) (BNH + TNH) indicating two different regression lines potentially associated with two different sources.

ascribed to uncertainties in the individual measurements. Although there is no direct positive correlation between these parameters, they exhibit the same low bulk thermal maturity, ranging between Tmax 436 and 447 °C (early oil window).

compounds are related to the proliferation of certain organisms that have occurred at known geologic times, for example the odd carbon number preference (nC-15, nC-17, nC-19) or carbon preference index (CPI) in Ordovician source rocks rich in the marine alga Gleocapsomorpha prisca (Reed et al., 1986; Jacobson et al., 1988). Even though G. prisca has been identified in some source rock samples from a previous study (Fowler et al., 1995), the source-related CPI in this dataset is uncharacteristically low for Ordovician sample extracts (1.13–1.23), usually showing an enrichment in uneven hydrocarbon chain lengths (Fig. 9) (e.g. Martin et al., 1963; Fowler and

13.4. Age-related biomarkers In general, specific biomarkers in the organic matter show a characteristic distribution through time and can indicate the age of the generating source rock (Grantham and Wakefield, 1988). Many of these 17

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Table 7 Biodegradation ranking after Wenger et al. (2002) and Peters and Moldowan (1993). ‘+’ and ‘-‘ indicate the presence or absence of molecules or UCM. Molecules

C1–C5

C8 to C15

C15–C35

Wenger et al. (2002) Peters and Moldowan (1993)

propane n-butane pentanes Iso-butane ethane n-alkanes isoalkanes isoprenoids BTEX alkylcycclohexane n-alkane, isoalkane isoprenoids naphthalenes phenanthrenes DBT regular steranes C30–C35 hopanes C27–C29 hopanes triaromatic steranes monoaromatic steranes UCM Biodegradation Level Biodegradation Level

Port au Port #1

Fox Well

Sandy Point

Well#7

Oil Point #2

Highland Brook 1

Highland Brook 2

Highland Brook W3

Highland Brook W1

Highland Brook W2

Shoal Point

SM038

SM055A

SM057A

SM058

SM060

SM062

SM063A

SM065

SM066

SM067

SM072A

+ + + + – + + + + + + + + + + + + + +

+ + + + + + + + + + + + + + + + + + +

– – – – – – + + – – + + + + + + + + +

+ + + + + + + + + + + + + + + + + + +

– – – – – – + + – – + + + + + + + + +

+ + + + – + + + + + + + + + + + + + +

+ + + + – + + + + + + + + + + + + + +

+ + – – + + + + + + + + + + + + + + +

– – – – – – + + – – + + + + + + + + +

– – – + – + + + + + + + + + + + + + +

+ + + + – + + + + + + + + + + + + + +

−−− very slightslight 0–1

−−− very slightslight 0–1

+++ Heavysever

−− slight

+ heavy

−− Slightmoderate

−−− very slight - slight

−−− slight moderate

++ Heavysever

++ heavy

+ moderate

3

2

3

1–2

0–1

2

3

3

3

Douglas, 1984; Longman and Palmer, 1987; Hoffmann et al., 1987; Douglas et al., 1991; Blokker et al., 2001). However, the Ordovician samples show a slightly higher CPI (1.23) than Cambrian samples (1.15), possibly related to a higher algal content in Ordovician organic

matter. Two parameters which differentiate between Paleozoic and Mesozoic oils are C28/C29 ratios and carbon isotopes (Fig. 14). The increase in C28 steranes relates to the diversification and proliferation of phytoplankton assemblages (Moldowan et al., 1985; Grantham and Wakefield, 1988). With increasing C28 steranes in the organic matter, C28/C29 ratios increase above 0.7 in the Mesozoic. Extracts from source rock samples from western Newfoundland have C28/C29 ratios from 0.3 to 0.5, consistent with Paleozoic source rock. The carbon isotope values for whole extracts also fall within the established isotope range for Paleozoic marine source rocks (Sofer, 1984; Hatch et al., 1987; Andrusevich et al., 2000) (Fig. 14). Neither ratio is sufficiently accurate to determine the exact age of the source, but both confirm a Paleozoic, marine source with low amounts of G.prisca in the organic matter. 13.5. Depositional environment Different depositional settings favor the preservation of specific Table 8 Recalculated generative potential for varying HI indices after Cooles et al. (1986) and Espitalé et al. (1987) (see Appendix A). PIo = assumed original production Index (0.02); f = expulsion factor; TOCo = original total organic carbon; TOC = measured total organic carbon; S1 = free hydrocarbon; S1 Ex = expelled free hydrocarbon.

Lobster Cove Bay of Islands

Fig. 12. Vitrinite reflectance calculated from VREQ-5 ratios with an error of ± 0.1 %Ro. 18

HI o(mg HC/g TOC)

PIo

f (%)

TOCo (wt. %)

S1 Ex(mg HC/g TOC)

800 600 400 800 600 400

0.02 0.02 0.02 0.02 0.02 0.02

1 0.99 0.98 1 1 0.99

5.73 3.83 2.88 5.02 3.35 2.51

46.41 23.09 11.39 40.71 20.2 9.95

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populations of organisms which can produce characteristic sets of biomarkers. For example, 18α-Oleanane is associated with higher plants from the Cretaceous or younger (Ekweozor et al., 1979). Changes in the depositional environment often manifest as a shift in the composition of aromatic, saturated, NSO, and asphaltene fraction of the extracted organic matter. For a more detailed look at the depositional environment, it is helpful to evaluate changes in sterane concentrations (C27: C28: C29), which are facies dependent but show some overlap for different depositional environments (Moldowan et al., 1985). Because this dataset shows a narrow distribution of C27, C28, and C29 steranes, a differentiation of depositional environments is difficult (Fig. 11). Samples enriched in C29 are usually assigned to a larger contribution of higher land plant material, but these rocks are Cambrian to Early Ordovician in age, predating the proliferation of land plants. Therefore, stigmastane (C29) present in the data is better explained by C29-sterols from algal lipid-membranes (Grantham and Wakefield, 1988). Tricyclic terpane and hopane ratios imply a marine shale source rock with a few exceptions from the Green Point Formation (SM054P, SM052C, and PA032A), which show minor contributions from carbonate rocks (Fig. 7); DBT/P and pristane/phytane ratios support this interpretation (Fig. 11). Pr/nC17 and phytane nC18 ratios suggest an oxidizing depositional environment (Fig. 11b). In summary, biomarker evidence confirms a marine shale source rock with minor amounts of carbonates deposited in an oxidizing environment.

Cambrian extracts present lower ratios of C26(R + S)/Ts, S/H, higher ratios of TET/C23 parameters, and low concentrations in phenanthrene, methylphenanthrenes and associated isomers (P, 3-MP, 2-MP, 1-MP, 9MP), and BNH and TNH (Fig. 7). Phenanthrene, methylphenanthrenes, BNH, and TNH have been related to bacterially-derived organic matter in studies by Radke et al. (1982, 1984), McKirdy et al. (1983), and Grantham et al. (1980). The statistical analysis of biomarkers that are source and age-related yields groups of samples that are identical to biomarkers that are source and maturity related. These independent analyses give consistent results, where molecules indicate a shift in source composition from a prokaryotic to algae-derived organic matter assemblage from the Cambrian to Ordovician, respectively. 13.7. Oil samples – age, depositional environment, and compositional changes We now examine age-related biomarkers in Cambrian and Ordovician oils and markers related to a change in depositional environment. We also use biomarker concentration from oils to infer the maturity of generating source rocks and constrain the onset of generation. 13.8. Chemometric analysis To establish genetically related groups of oil samples without bias, we utilize the same source and maturity dependent parameters as for the extracts (Table 3). This chemometric approach identified three oil endmember groups. Groups 1 and 2 are closely related, showing a close resemblance to extracts from Ordovician samples (Fig. 15). Group 3 clusters oil samples that show characteristics similar to extracts from Cambrian source rock samples. Both the Cambrian and Ordovician oil groups contain samples from the Cow Head area and Port au Port Peninsula (Fig. 4).

13.6. Sources of organic matter and compositional changes from the Cambrian to the ordovician Biomarker ratios influenced by source and maturity allow for further characterization of the extracts. Systematic changes in these parameters (Table 6) from the Cambrian to Ordovician can be identified in samples with similar maturities, but not between Ordovician or Cambrian samples with different maturities. For example, samples from Ordovician extracts have higher ratios of C26(R + S)/Ts, S/H, and low ratios of TET/C23, which have been related to a change in source composition by other studies (Hughes, 1984; Palacas et al., 1984; Tissot and Welte, 1984; Connan et al., 1986, Riolo et al., 1986). High concentrations of sterane and high S/H ratios have been associated with marine organic matter constituting planktonic and/or benthic algae (Moldowan et al., 1985). Samples from

13.9. Age-related biomarkers in oils Cambrian and Ordovician oils are generally typified by high paraffin content, low sulfur content, and low δ13C isotope values for whole oils (e.g. Martin et al., 1963; Fowler and Douglas, 1984; Longman and Palmer, 1987; Hoffmann et al., 1987; Douglas et al., 1991; Blokker et al., 2001). Other key characteristics that differentiate these from Fig. 13. Dendrogram showing genetic relationships between source rock extract samples based on chemometric analysis of selected source-related geochemical data (Table 8). Cluster distance is a measure of genetic similarity indicated by the horizontal distance from any two samples on the left to their branching point on the right. Excluded from the statistical analysis are maturity dependent parameters and biomarkers affected by biodegradation. Scores plot based on auto-scaled principal component analysis (PCA) using geochemical parameters listed in Table 4 showing three distinct groups of samples. PC1, PC2, and PC3 are principal components accounting for 33.4%, 21.0%, and 13.9% of the variance in the data. Piroutte® settings are described in ‘Multivariant Analysis’.

19

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Fig. 14. Age-related biomarker ratios and carbon isotope graphs. (a) Pristane/phytane versus δ13C indicating a Paleozoic age of a marine shale or carbonate source rock (Chung et al., 1992). (b) Stable carbon isotope of the aromatic fraction versus the saturated hydrocarbon fraction indicating a marine origin of the organic matter (Sofer, 1984). (c) Oil and source rock extract samples from western Newfoundland in relation to the original study by Grantham and Wakefield (1988). Differentiation into Cambrian and Ordovician oils based on C28/C29 is not possible. All oil samples have been assigned an age of 500 Ma and an error of ± 50 Ma to cover the period from the middle Cambrian to the Middle- Early Ordovician. Source rock extracts show interpolated ages, based on biostratigraphic levels, from which they were collected.

sources (Chung et al., 1992; Sofer, 1984; Peters et al., 2005). Pristane/phytane ratios (2.01–2.52) in combination with carbon isotope values in the oil samples further imply a Paleozoic marine source rock deposited in an oxidizing environment (Figs. 11b and 14a) (Chung et al., 1992). Ratios of C28/C29 sterane (0.48–0.61) in oils from western Newfoundland are unusually high (Fig. 14c). An increase in the C28/ C29 ratio is related to increasing ergostane (C28) concentration through geologic time, which in turn is related to increased algal diversity (Grantham and Wakefield, 1988). While this ratio cannot be used for definitive age determination of an oil source, ratios over 0.5 are characteristic for late Paleozoic to lower Mesozoic source rocks (Grantham and Wakefield, 1988). Observed ratios in western Newfoundland imply an unusually high concentration of algae contributing ergostane to source rocks in western Newfoundland. In summary, compound-specific carbon isotope composition and other age-related biomarkers in the oils suggest a Paleozoic source likely generating from two intervals.

younger oils include a high carbon preference index (CPI) and low C28/ C29 sterane ratios (Reed et al., 1986; Jacobson et al., 1988; Moldowan et al., 1985; Grantham and Wakefield, 1988). Measured carbon isotope values of saturates and aromatics from analyzed samples fall within the normal range for marine Paleozoic crude oils (Fig. 14b) (Sofer, 1984; Hatch et al., 1987; Andrusevich et al., 2000). Depleted carbon isotope compositions (−31.45 to −29.94‰ VPDB) indicate a Paleozoic origin of the source material (Andrusevich et al., 2000). However, while the bulk carbon isotope values are very low, they do not unambiguously distinguish between the Cambrian and Ordovician oils (Moldowan et al., 1985; Grantham and Wakefield, 1988). Similarly, compound-specific carbon isotope analysis cannot alone distinguish between Cambrian and Ordovician oil-samples. Nevertheless, the results suggest two distinct sources in the same area based on a difference in compound-specific carbon isotope composition (nC-6 to nC-30) (Fig. 10). For example, samples SM063A, SM066 vs. SM055A from the Cow Head area show values differing by over 2‰ for each compound. This is a sufficient difference to indicate separate 20

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Fig. 15. Dendrogram shows genetic relationships between oils based on chemometric analysis of selected source-related geochemical data (Table 4). Cluster distance is a measure of genetic similarity indicated by the horizontal distance from any two samples on the left to their branching point on the right. Excluded from the statistical analysis are maturity-dependent parameters and biomarkers affected by biodegradation. ‘Scores-plot’ based on auto-scaled principal component analysis (PCA) using geochemical parameters listed in Table 4 shows three distinct groups of samples. PC1, PC2, and PC3 are principal components accounting for 39.7%, 27.9%, and 13.5% of the variance in the data. Piroutte® settings are described in ‘Multivariant Analysis’.

OEP resulting from increased G. prisca in the organic matter (Fig. 9), consistent with Fowler et al. (1995), who identified G. prisca in their samples. Isoprenoid ratios imply an oxidized organic matter as a source for oils from group 2 (Fig. 11b). A similar phenomenon was explored by Jacobson et al. (1988) who defined two compositional endmember groups (“assemblage A” and “assemblage B″) within source rocks of similar age (Middle Ordovician) from Iowa. “Assemblage A″ is dominated by an odd carbon number preference typically derived from G. prisca, resulting in type I/II organic matter. “Assemblage B″ is characterized by n-alkanes with a reduced odd carbon number preference and the presence of present isoprenoids, mainly derived from type II/III organic matter. The organic matter for assemblage B may originate from degraded and oxidized microplankton (Douglas et al., 1991; Peters et al., 2005). The marginal odd preference observed in samples from group 2 (CPI = 1.09 and OEP = 1.16) is unusually low for Ordovician samples even with a composition similar to Jacobson et al.’s (1988) “assemblage B”; however, the low DBT/P ratios (Fig. 11a) are consistent with a marine shale with type II/III organic matter (i.e. a low input of G. prisca). We derive additional evidence for a change in source composition from markers that are source and maturity dependent. For example, BNH/H and TNH/H are two common ratios used in oil-to-source correlation directly derived from free bitumen in source rocks; they identify organic matter originating from chemo-autotrophic bacteria (Peters et al., 2005). On a (BNH + TNH)/H versus API gravity plot, Ordovician oils fall on the lower of two regression lines (i.e low BNH, TNH input), supporting the interpretation of low bacterial contribution for Ordovician oils (group 1, 2) (Fig. 11e). Fig. 8b shows two regression lines in a graph of moretane/hopane vs. Ts/Tm separating Ordovician oils (groups 1 and 2) and Cambrian samples (group 3). Both ratios depend on maturity and source, placing oil samples generated from source rocks with different organic matter on different maturity trajectories (Peters et al., 2005). Similarly, graphs illustrating ∑tricyclic-hopanes/hopane and DIA-hopane/hopane show two endmember clusters, also suggesting two source rocks (Fig. 8c and d). This leads to the interpretation that two closely related groups of Ordovician oils exist. Group 1 represents oils derived from a eukaryotic organic matter, slightly influenced by G. prisca. Oils from group 2 originate from potentially degraded and oxidized micro-plankton with a lesser input of G. prisca. Group 3 comprises oils derived from Cambrian source rocks. The

13.10. Depositional environment Biomarkers can differentiate between oils sourced from marine shale, marine carbonate, marine sulfate-rich carbonate, and lacustrine settings (Fig. 7). Other parameters allude to the redox conditions of the depositional environment (Fig. 11). The tight cluster in sterane distribution (C27: C28: C29) implies a marine depositional environment (Fig. 11c). A predominance of C29over C27-steranes has been recognized in pre-Devonian oils by many authors (McKirdy and Hahn, 1982; Fowler and Douglas, 1984; Rullkötter et al., 1986) and relates to high cyanobacterial input that produces C29-sterane precursor molecules. The difference in monoaromatic sterane distribution between the oils is marginal (Fig. 11d) and tentatively points to a change in organic matter composition in the same depositional environment (continental slope and rise). Pristane and phytane ratios indicate oxidizing depositional environments for the oil sources (Fig. 11b). Biodegradation-resistant dibenzothiophene/phenanthrene (DBT/P) versus pristine/phytane relationships identify the depositional environment as “marine shale” (Fig. 11a) (Hughes, 1984; 1995). These results are consistent with previous work completed in western Newfoundland (Macauley, 1987, 1990; Weaver, 1988; Weaver and Macko, 1988; Sinclair, 1990; Fowler et al., 1995). High ratios of DIA/(Reg + DIA), from the conversion from regular C27-steranes (Reg) to rearranged C27-steranes (DIA), further supporta clastic, shale-dominated source rock (Table 3). This is also described by Fowler et al. (1995) for oils from western Newfoundland, and ascribed to the presence of acid sites in clay minerals which promote this conversion (Rubinstein et al., 1975; Sieskind et al., 1979). Slightly lower DIA/(Reg + DIA) values in oil samples SM055A, SM072A, and SM058 may be related to a sediment source richer in carbonate. 13.11. Compositional difference between Cambrian and Ordovician oils We now discuss the characteristic source parameters of oil endmembers that change from the Cambrian to the Ordovician. Oil samples from groups 1 and 2 show the presence of pristane, phytane, and a full n-alkane profile, which suggests type II/III organic matter as the underlying bulk composition of the Ordovician source rocks (Fig. 9). Differences in the CPI and OEP could be ascribed to varying amounts of Gleocapsomorpha prisca in the source organic matter. Specifically, group 1 (SM055A, SM072A) shows slightly higher CPI and 21

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Fig. 16. Schematic cross-sections through Port au Port Peninsula, Western Newfoundland, from Middle Ordovician to present. Vertical exaggeration x 4 approximately. (a) Middle Ordovician, emplacement of a thrust sheet containing Cambrian source rocks. (b)–(c) Late Ordovician to Early Devonian, emplacement of second thrust sheet containing Ordovician source rocks. (d) Present-day, Ordovician source rocks carried in the hanging wall of the Round Head Thrust dip towards the north (Modified after Lacombe et al., 2019).

corresponding source facies (groups 1, 2, and 3) via an indirect oil-tosource correlation because the maturities of the source rocks and oil samples differ. Pyrolysis analyses identified two source intervals, one in the Cambrian (Furongian) and in the Early Ordovician (Floian). Fluctuating amounts of TOC and HI values characterize the latter, which directly relates to the organic matter composition characterized by the extract analysis. Extract group 1, represented by Early Ordovician (Floian) samples, have the highest TOC and HI values and are characterized by organic matter derived from algae with a small contribution from G.prisca. Extract group 2 also originates from the Early Ordovician but is composed of degraded and oxidized micro-plankton with less input of G. prisca. Oil group 1 shows the same characteristic biomarker ratios, indicative of an algal-derived organic matter with G. prisca, seen in extract group 1. Conversly, oil-group 2 contains biomarker ratios comparable to the Ordovician extract group 2 (Figs. 7 and 11).

samples present a full n-alkane profile, including peaks for pristane and phytane, suggesting type II/III organic matter as principle composition (Fig. 9). In contrast to the Ordovician oils, the Cambrian oils have higher (BNH + TNH)/H ratios related to a bacterially derived organic matter. Group 3 also shows high ratios of the sum of tricyclic terpanes relative to pentacyclic terpanes (∑TriCyc/H) but has low concentrations of tetracyclic terpanes (TET) and C23 tricyclic molecules (T23) compared to Ordovician oils (Fig. 7). These findings compare well to Cambrian oils from Oman (Grantham, 1986), the Bikaner-Nagaur Basin (Dutta et al., 2013), and parts of the Tarim Basin, China (Yang, 1991). This suite of biomarker parameters supports a Cambrian source rock with bacterially derived (prokaryotic) organic matter generating oilgroup 3, represented by samples SM038, SM066, and SM063A. 14. Oil-to-source correlation Here we relate identified oil families (groups 1, 2, and 3) to their 22

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Extracts from the Cambrian source interval produce a biomarker fingerprint related to a bacterial-derived organic matter. The discrepancy between biomarker ratios of extract-group 3 and oil-group 3 (Fig. 7), especially S/H, can be ascribed to different maturities of the source rock extracts and oils. Nevertheless, both extract-group 3 and oil-group-3 contain evidence of bacteria-derived organic matter, a statistically significant difference from the Ordovician groups, allowing an indirect correlation. The values for bulk and compound-specific carbon isotopes, detected in western Newfoundland oil-samples, are consistent with source rocks generating these oils. The low values indicate deposition before the Middle Ordovician Carbon Isotope Excursion (Hatch et al., 1987; Jacobson et al., 1995). Yet, the isotopic data does not distinguish between Cambrian and Ordovician age.

generated oil and placed mature source rocks adjacent to the Round Head Fault, a normal fault during the Taconian (Fig. 16b and c). Based on biomarker evidence, we propose that oil produced from Port au Port #1 well originates from the sliver of Cambrian source rock in the hanging-wall, adjacent to the fault. It is feasible that the generated oil migrated up-dip through the fault and was trapped in the adjacent carbonate platform in the footwall of the Round Head Fault. A second, overlying thrust sheet containing Ordovician source rocks was emplaced in a later, thick-skinned Acadian thrusting event. The high calculated vitrinite reflectance equivalent of the Port au Port #1 oil (SM038) may result from secondary cracking of an originally low-maturity oil in the reservoir. Thus, analysis of SM038 shows the maturity parameters of the deeply buried reservoir (4000 m), rather than the maturity of the generating source rock. This deep burial may also explain the oil's low biodegradation level. Deep burial and a temperature increase greater than 80 °C with no connection to groundwater could result in pasteurization of the oil (Head et al., 2003; Wilhelms et al., 2001). Active charge through the Round Head Fault at present day is unlikely because the source rock in the hanging wall does not reach sufficiently high maturities to explain those observed in the oil from the Port au Port #1 well. The biomarker signature in the Shoal Point oil correlates well with the high-quality Early Ordovician source rocks and bitumen collected from nearby Tea Cove, interpreted as the most distal portion of the Humber Arm Allochthon and carried in the upper, later thrust sheet. This thrust sheet is exposed on the north shore of the Port au Port Peninsula, dipping slightly to the north under Port au Port Bay. The thermal maturity of rock samples collected along the coast is 0.65 %Ro and arguably insufficient for oil generation; however, adequate thermal stress occurred in the subsurface farther north to have generated low maturity oil on Shoal Point. We propose that oil collected from Shoal Point was generated from the Ordovician source rock after the Acadian inversion from the shallower hanging wall of the Round Head Fault (Fig. 16d).

14.1. Oil maturity and timing of generation Samples collected from the Port au Port Peninsula and Cow Head area show different source and age-related biomarker compositions and varying maturities, raising questions about the timing of oil generation and migration. Here, we present interpretations based on biomarker and isotope data with geologic evidence from map relations. 14.2. Oil maturity Maturity-related biomarkers in this dataset have not been affected by biodegradation and can be used for maturity evaluation. To cover the full maturity spectrum, from marginally mature to over-mature, we use several isomerization ratios, and naphthalene and phenanthrene ratios to bracket the thermal parameters of the oils. To assess maturities between 0.55 %Ro and 1.3 %Ro, we rely primarily on sterane and terpane isomerization ratios (Fig. 8a–d). Sterane isomerization ratios can be used below 0.75 %Ro (Peters and Moldowan, 1993). Terpane ratios assess higher maturity oils above 0.75 %Ro to 1.3 %Ro (Seifert and Moldowan, 1978; Peters et al., 2005). Maturity ratios that are also influenced by the source input (most terpane ratios) supplement this interpretation (Seifert and Moldowan, 1980; Rullkötter and Marzi, 1988; Isaksen and Bohacs, 1995). Based on the calculated ratios, the oil samples span a maturity spectrum from the early oil window to dry gas (Fig. 12). It is of interest that not only genetically related samples, but also geographically related samples, vary in thermal maturities (Fig. 12). This is obvious for samples SM038 and SM072 (Port au Port Peninsula) and samples from the Cow Head area (i.e. Parsons Pond and St. Paul's Inlet). We interpret that Cambrian and Ordovician source rock intervals are present in both study areas and the dipping character of the imbricated thrust package caused the generation of oils with varying thermal maturities and distinct source characteristics.

14.4. Cow Head area Oil most similar in biomarker composition to the Shoal Point oil was found in Fox Well on St. Paul's Inlet, just south of Parson's Pond (oilgroup 1) (Fig. 4). Other oil samples (oil-group 2) collected from Parson's Pond also show a strong resemblance to the Shoal Point and Fox Well oil in their biomarker signature, but have varying maturities. These oils likely generated during the thin-skinned imbrication of the Humber Arm Allochthon in the Taconian orogeny or Acadian Inversion. This results in oils with different thermal maturities (0.7–1.1 %Ro), corresponding to their generation depth within the imbricated stack. Two oils from Parsons Pond (SM066, SM063A) show the same biomarker signature as oil from Port au Port #1 well (oil-group 3), but with lower thermal maturities. This demonstrates that the Cambrian source rock responsible for SM038 oil (oil-group 3, Port au Port Peninsula) also exists in the Cow Head area, but did not experience the same burial history.

14.3. The onset of oil generation on port au Port Peninsula The high maturities calculated for oil from Port au Port #1 well (SM038) give insights into the onset of oil generation on the Port au Port Peninsula. However, it is essential to consider the area's tectonic evolution and integrate this with the maturity data to infer the onset of oil generation. During the Taconian orogeny, deep marine deposits were thrust onto the carbonate shelf as imbricated stacks or sheets (White and Waldron, 2018; White et al., 2019; Lacombe et al., 2019). We propose that the emplacement of the allochthon caused oil generation. Lacombe et al. (2019) suggest a pre-Acadian emplacement of a sheet of Humber Arm Allochthon (containing Cambrian source rocks), which was thinned and rapidly emplaced due to overpressure related to hydrocarbon generation. Evidence for early oil generation and migration could be found in thin sections from allochthonous rocks (Lacombe et al., 2019). In our interpretation, the emplacement of this thrust sheet

14.5. Oil mixing In a complex fold-and-thrust belt containing multiple generating source rock, long-distance migration and mixing of oils is likely, but could not be proven. To determine the amount of mixing in this dataset, we used an alternating least squares of concentration data (ALS-C) to deconvolve mixtures of oils from the Cambrian and Ordovician sources. As discussed in Peters et al. (2008), ALS-C identifies mixtures of oils and assigns relative amounts of mixed oils by comparing biomarker concentration. Mixed oils from two endmembers, containing the same biomarker in different concentrations, display a linear relationship between the concentration of this biomarker and the fraction of one oil endmember. Given that oil-group 2 is closely related to group 1 23

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(Ordovician) but also exhibits biomarkers found in group 3 (Cambrian), it is likely that group 2 is a mixture of group 1 (Ordovician) and group 3 (Cambrian). However, not enough oil samples are available in this study area to determine the extent of mixing in more detail.

settings. Here, these data are critical to understanding relationships between variable source rock maturities related to different burial depths of the source material within the dipping thrust sheets. Biodegradation-related biomarkers proved useful in understanding the effects of deep burial on oil-filled reservoirs. The presence of two source rock intervals with changing organic matter enabled us to constrain the onset of oil generation, migration pathways, and mixing. These variable controls led to complex geographic distribution of related oils on one hand, and highly variable composition of oils in spatially restricted areas on the other. Oil operators exploring fold and thrust belts can expect significant changes of oil properties and quality over short distances, related to underlying complexities encountered in fold and thrust belts.

15. Conclusions Our data demonstrate that two hydrocarbon source rocks were active on the western Newfoundland margin, one in Cambrian (Series 3 to Furongian) strata, and another in Early Ordovician (Floian) formations. The two source intervals show fair to excellent TOC concentration with type II/III and type II organic matter and low maturities in outcrops. The organically enriched layers comprise 20–30 m of the overall thickness of the source rock formations. Source-related biomarkers in extracts and oils identify the source intervals as clastic shale-dominated rocks deposited in an oxidizing marine environment and reveal a change from a primitive bacterial organic matter (Cambrian source) to more algal-dominated organic matter (Ordovician source). Notably, G. prisca is inferred in small quantities in the Ordovician source in western Newfoundland but is not expressed in the typical odd carbon number preference identified in other Ordovician source rocks, which could also be related to effects of thermal maturity. This implies that one cannot identify this characteristic in all Ordovician sources, and other available biostratigraphic or isotopic data may be required to reliably constrain the age. Both sources were active in the two study areas, generating oil from Cambrian and Ordovician intervals with varying thermal maturities depending on the structural position of the source within the foldand-thrust belt. The compositional differences in the source material resulted in two oil families with a characteristic set of biomarkers, enabling us to correlate the oil seeps to source intervals. Oil generation occurred in phases related to the emplacement of two thrust sheets containing different age source rocks. Biomarker and isotope data are instrumental in unraveling the intricacies of oil-source relationships found in tectonically complex

CRediT authorship contribution statement Martin Schwangler: Writing - original draft, Conceptualization, Visualization. Nicholas B. Harris: Writing - review & editing, Supervision, Funding acquisition. John W.F. Waldron: Writing - review & editing, Funding acquisition. Acknowledgments Funding for this project was supplied by the Petroleum Exploration Enhancement Program (PEEP) of Newfoundland and Labrador to the second and third authors. We are grateful to Larry Hicks and the Newfoundland and Labrador Department of Mineral Resources and Energy for advice. Ryan Lacombe and Morgan Snyder are thanked for their assistance with data collection and for many helpful discussions. We thank Brian Jarvie (GeoMark) and Ron Hill (EOG Resources) for valuable discussions and comments on the thesis from which this paper was developed. We thank an anonymous reviewer for helpful comments that improved the manuscript.

Appendix A Calculation of Original Generative Potential One key parameter in the calculation is the fractional conversion factor (f), which is a measure for the original petroleum potential to petroleum generated. The ratio is expressed in equation (1) of Cooles et al. (1986), where S2o is the original S2 and S2x(CF) represents the measured S2 after generation and explosion (corrected for weight-loss). The correction factor (CF) for weight loss can be expressed with the measured TOC from pyrolysis using a basic assumption from Espitalé et al. (1987), who estimated that the generated petroleum contains 83.3 wt% of organic carbon. Therefore, CF can be expressed with equation (2), where TOCo is the original TOC and TOCx is the measured TOC content from pyrolysis. After rearranging and substituting equation (1) we can express the conversion factor f with HI (=S2/TOC) and PI (=S1/(S1+S2)) formulated in equation (3). The same equation can be solved for the original TOC (equation (4)). To perform the calculations we used pyrolysis data S1, S2, measured TOC, HI, and PI.

f=

S 20

CF =

S 2x × (CF ) S 20

TOC0 TOCx

(1)

83.33 × (S10 + S 2 0) 83.33 × (S1x + S 2 x )

(2)

HIx 100

0.0833

100

0.0833

f=1

TOC0 =

(1

HIx PIx

(1

HI0 PI0

(3)

HIx × TOCx × 83.33 f ) × (83.33 TOCx ) HIx × TOCx

(4)

HI0

HI0 × (1

24

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Appendix B Sterane and terpane biomarker maturity parameters for analyzed oil samples from western Newfoundland, calculated methylated homologes, and 13 naphtalene and phenanthrene ratio for VREQ-5 consensus maturity calculation. Location

Parsons Pond Port au Port Peninsula

St. Pauls's Inlet

Parsons Pond Parsons Pond Parsons Pond

Well name Sample ID

Highland Brook W2 SM067

Shoal Point SM072A

Fox Well Highland SM055A Brook W1 SM066

Highland Brook 2 SM063A

C27 ββ/(ββ +αα) C29 ββ/(β β +αα) C29 (20S/(20 S + 20 R)) C27DIA/(DIA + REG) DIA/REG 30M/30H Ts/Tm Tricy/30H X/30H MDR MPI-I (Radke et al., 1982) %Rc low (0.6 × MPI-I + 0.4) %Rc high (0.6 × MPI-I + 2.3) MN2/(MN2+1)*100 EN2/(EN2+1)*100 DMN26/(DMN26 + 12)*100 (DMN26 + 27)/(total DMNs)*100 TMN137/(TMN137 + 124+125)*100 TMN(137 + 136)/(total TMNs)*100 TeMN13/(TeMN13 + 14+15 + 16)*100 DMP(EFGK)/(total DMPs)*100 (MP3+2)/(M P3+2 + 9+1) * 100 DMP26/(DMP26 + 18)*100 DMP23/(DMP23 + 19)*100 DMP18/(DMP18 + 12)*100 TMP_A/(TMPA + TMP128)*100 consensus %Rc (VREQ-5)

0.77 0.54 0.50 0.44 3.66 0.07 4.43 1.14 0.81 4.00 0.62 0.77 1.93 84.01 0.00 0.00 0.00 75.38 28.42 47.53 0.00 14.80 0.00 0.00 0.00 96.07 346.21 0.60

0.68 0.25 0.45 0.12 2.29 0.10 1.05 0.25 0.06 2.42 0.49 0.69 2.01 54.38 58.42 67.24 19.52 49.24 31.50 12.90 12.78 33.45 48.21 28.68 50.51 46.97 513.79 0.80

0.75 0.36 0.48 0.42 2.63 0.09 1.84 0.23 0.20 4.52 0.49 0.70 2.00 48.76 64.68 72.18 18.56 70.71 36.83 24.55 13.07 32.28 53.55 28.05 63.01 84.74 611.00 0.91

0.71 0.81 0.45 0.33 3.97 0.18 6.00 4.82 7.23 2.13 0.61 0.77 1.93 57.01 53.34 84.03 19.87 88.77 47.03 41.77 15.39 36.79 77.08 36.70 65.99 97.26 721.04 1.03

0.68 0.91 0.46 0.47 4.22 0.14 6.06 5.14 8.66 2.91 0.56 0.73 1.97 59.63 56.90 71.72 14.90 80.41 44.01 28.14 16.24 42.84 63.60 40.31 69.14 93.79 681.64 0.98

Parsons Pond

Parsons Pond

Parsons Pond

Port au Port Peninsula

Sandy Point SM057A

Oil Point #2 SM060

Well#7 SM058

Highland Brook 1 SM062

Port au Port #1 SM038

0.77 0.74 0.50 0.50 4.99 0.10 6.60 1.46 3.38 7.72 0.70 0.82 1.88 76.79 55.43 87.30 25.28 89.68 47.88 39.42 13.76 37.44 74.51 27.58 73.25 96.58 744.91 1.06

0.81 0.62 0.46 0.47 16.83 0.07 5.64 1.56 1.23 4.10 0.74 0.84 1.86 53.65 73.30 90.98 24.72 89.78 48.05 42.08 17.26 40.59 76.51 34.73 75.88 97.04 764.59 1.08

0.73 0.52 0.49 0.34 1.84 0.08 2.67 0.76 0.40 6.72 0.78 0.87 1.83 58.57 79.57 90.40 26.85 88.72 45.49 42.64 18.60 42.55 75.79 38.81 71.39 95.57 774.95 1.10

0.83 0.55 0.47 0.40 16.69 0.08 3.58 1.66 0.85 8.27 0.86 0.91 1.79 61.05 76.90 92.13 28.22 89.22 46.45 42.67 19.14 44.12 76.61 41.77 74.88 97.39 790.56 1.11

0.75 0.97 0.41 0.59 7.16 0.22 3.09 9.49 3.50 20.42 1.91 1.54 1.16 77.56 88.20 95.68 43.69 93.96 50.37 44.25 35.75 65.51 93.79 75.07 62.54 98.75 925.13 1.26

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