The role of calcareous and shaly source rocks in the composition of petroleum expelled from the Triassic Shublik Formation, Alaska North Slope

Accepted Manuscript The role of calcareous and shaly source rocks in the composition of petroleum expelled from the Triassic Shublik Formation, Alaska North Slope Inessa A. Yurchenko, J. Michael Moldowan, Kenneth E. Peters, Leslie B. Magoon, Stephan A. Graham PII: DOI: Reference:

S0146-6380(18)30084-6 https://doi.org/10.1016/j.orggeochem.2018.04.010 OG 3714

To appear in:

Organic Geochemistry

Received Date: Revised Date: Accepted Date:

1 September 2017 15 April 2018 20 April 2018

Please cite this article as: Yurchenko, I.A., Michael Moldowan, J., Peters, K.E., Magoon, L.B., Graham, S.A., The role of calcareous and shaly source rocks in the composition of petroleum expelled from the Triassic Shublik Formation, Alaska North Slope, Organic Geochemistry (2018), doi: https://doi.org/10.1016/j.orggeochem. 2018.04.010

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The role of calcareous and shaly source rocks in the composition of petroleum expelled from the Triassic Shublik Formation, Alaska North Slope

Inessa A. Yurchenko a, *, J. Michael Moldowan b, Kenneth E. Peters a, c, Leslie B. Magoon a, Stephan A. Graham a a

Department of Geological Sciences, Stanford University, Stanford, CA 94305, USA

b

Biomarker Technologies, Inc., 638 Martin Avenue Rohnert Park, CA 94928 USA

c

Schlumberger Information Solutions, 18 Manzanita Place, Mill Valley, CA 94941, USA

* Corresponding author: email: [email protected], Geological Sciences Department 450 Serra Mall Bldg. 320 Rm.118, Stanford, CA 94305-2115 USA

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Abstract For nearly thirty years, the Triassic marine carbonate Shublik Formation has been suggested and confirmed as a key source rock for hydrocarbons in the North Slope of Alaska. The formation accounts for roughly one third of the oil in the supergiant Prudhoe Bay Field, and for nearly all of the oil in the second largest Kuparuk River Field. Recent studies of oil types in the vicinity of the Northstar Field suggested presence of “shaly” organofacies of the Shublik Formation based on the likely Triassic age and marine shale biomarker signatures of some analyzed oil samples. Current work fills the gap between biomarker analysis of predicted “calcareous” and “shaly” oil types and source rock geochemistry. Biomarker-based oil-source rock correlation confirms the presence of two genetically-distinct organofacies and related oil families. Both groups were deposited under a similar redox condition (anoxic to suboxic) with dominantly marine algal input but in either 1) a clay-rich or 2) a clay-poor depositional setting. Chemometric evaluation of multivariate biomarker data reveals mixtures with variable degrees of mixing between end members. Analysis of diamondoids confirms mixed oil types and establishes diamondoid signatures of source rock end-members. This allows for correlation of biomarker-poor, overmature Shublik source rock samples to oils, and extends these interpretations over large areas of the North Slope. Keywords: Shublik Formation; source rock; Arctic Alaska; North Slope; biomarkers; diamondoids; oil-source rock correlation. 1. Introduction It is widely recognized that petroleum is a complex mixture of hydrocarbons and nonhydrocarbons generated and expelled from fine-grained-organic-rich source rock. Many petroleum accumulations in the North Slope of Alaska consist of contributions from more than 2

one source rock, or different organic facies of the same source rock (Seifert et al., 1980; Wicks et al., 1991; Masterson, 2001; Peters et al., 2008; Wang et al., 2014). Four main petroleum source rocks in the North Slope include (1) the Triassic Shublik Formation; (2) Jurassic Lower Kingak Shale; (3) Cretaceous pebble shale unit; and, (4) the Cretaceous Hue Shale (Magoon and Bird, 1985; Bird, 1994; Houseknecht and Bird, 2004; Peters et al., 2006) (Fig. 1). It is widely accepted that the Middle to Upper Triassic Shublik Formation is one of the major origins of source rocks for oil, accounting for nearly all of the oil in the Kuparuk River unit along with a large volume of petroleum in the Prudhoe Bay unit (Fig. 2), (Seifert et al., 1980; Magoon and Bird, 1985; Bird, 1994; Masterson, 2001; Peters et al., 2008). In addition, crude oil composition is influenced by secondary effects, such as thermal maturity of the source rock at the time of oil generation, and biodegradation and cracking of the oil during migration and accumulation. Thus, de-convolution of oil mixtures and oil-source rock correlation on the North Slope has been a challenge for many years. Recent studies of Alaska North Slope oil types by Peters et al. (2007) and Wang et al. (2014) used decision-tree chemometrics of selected source- and age-related biomarker ratios to classify over forty Shublik crude oil samples into two genetically-distinct families, which were linked to calcareous and shaly organofacies of the Shublik source rock (Figs. 2 and 4). Peters et al. (2007) proposed a “shaly” organofacies based on likely Triassic age and distal-marine shale biomarker signatures of some analyzed oil samples. Wang et al. (2014) extended this interpretation by emphasizing the difference between samples collected from wells located north and south of the Barrow Arch, a regional structural high that first formed during rift-related uplift in the Jurassic and Early Cretaceous. Later it served as a focal point for petroleum migration and accumulation of the largest North Alaskan oil fields (Bird and Houseknecht, 2011). Wang et al.

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(2014) suggested the source for the “shaly” oil family to be a clay-rich equivalent of the calcareous Shublik Formation that occurs to the north of the Barrow Arch (Fig. 2). In addition, Peters et al. (2008) classified oil samples from the Prudhoe Bay field area into a separate family, indicating approximately equal contributions from Shublik Formation and Hue-GRZ source rocks (37% each), and less from the Kingak Shale (26%). That oil family was not addressed in this study. Masterson (2001) compared some biomarker characteristics of five Shublik source rock extracts from the Phoenix-1 well to nine extracts from cores in two Prudhoe Bay wells. He used the term “calcareous facies” for the distal, organic-rich facies of the Shublik Formation in the Phoenix-1 well, whereas the more shoreward, proximal facies at Prudhoe Bay Field was described as the “shaly facies.” Despite much work, most published research was conducted on Shublik oils rather than source rock, and there remains a gap between biomarker analysis of various North Slope oil families and geochemical and geological assessment of the Shublik organofacies. Moreover, Peters et al. (2006) noted that much of the present-day Shublik Formation is mature to postmature, complicating the analysis of biomarkers and oil-source rock correlation. In this study, the terms ‘calcareous’ and ‘shaly’ are used inherently to describe two genetically-distinct oil families. This initial distinction was based on the biomarker analysis of over forty (40) oil samples from all over the North Slope and source rock character was inferred from oil composition (Peters et al., 2007; Wang et al., 2014). This current work builds upon previous geochemical interpretations of the two Shublik oil families but adds additional insight from source rock analysis of biomarkers and oil-source rock correlation, and recently-acquired diamondoid data to better distinguish end-member and mixed-oil types. Utilization of biomarker and diamondoid analyses provided the ability to

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overcome problems in correlating biomarker-poor overmature source rocks and oils, which helped to extend interpretations over large areas of the North Slope. 2. Materials and methods 2.1. Samples Twenty oil samples and rock extracts were selected for this study. Samples, well names, and performed analyses are listed in Table 1. Sample locations are displayed in Fig. 2. Rock extracts 207 and 208, and oil samples NS13, SP1a, SP1b, N1, KC4, F5a, M1, MB13b, D1 reanalyzed in this study, were previously investigated by Seifert et al. (1980) and Wang et al. (2014), respectively. Previously-published sample names were utilized for consistency. Sample CO1 is oil tested from the Shublik interval in the Colville St-1 well of the Kuparuk River unit. Rock samples PH01, PH07, PH08, and PH09 collected from the most-studied Shublik core in the Phoenix-1 well were discussed in Yurchenko et al. (2018). Sample PH04 is oil extracted from the Ivishak rock samples in the Phoenix-1 well. Rock samples AL02, AL03, and 13AL31 were collected from the Shublik core in the Alcor-1 well drilled about 20 km south of the Prudhoe Bay Unit by Great Bear Petroleum in 2012. These data present first insight into geochemical characteristics of the Shublik source rock in a frontier area south of the producing fields. The dataset targets a large area of the North Slope (about 140 km east to west and 80 km north to south). It includes previous and newly-acquired geochemical data, provides improved understanding of distinguished Shublik end-member and mixed-oil types, and allows their correlation to Shublik organofacies.

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2.2. Methods 2.2.1. Source rock screening All collected rock samples were analyzed for carbonate and total organic carbon content (TOC), and Rock-Eval pyrolysis to assess organic matter quantity, quality, and thermal maturity (Peters and Cassa, 1994). Analyses (GeoMark Research, Ltd.) employed Rock-Eval II and LECO C230 instruments. In addition, two samples (AL02 and AL03) were subjected to whole rock and clay x-ray diffraction (XRD) analysis (K-T GeoServices, Inc.) in order to provide mineralogy of the samples. 2.2.2. Analysis of Biomarkers Analysis was performed at Biomarker Technologies, Inc., and included organic matter extraction, gas chromatography (GC), gas chromatography – mass spectrometry (GCMS), and gas chromatography – mass spectrometry – mass spectrometry (GCMS/MS) using laboratory procedures described in Peters et al. (2005) and Wang et al. (2014). Measured biomarker concentrations and calculated ratios were used to assess thermal maturity, organic matter input, and environment of deposition, as well as for oil-source rock correlation. In addition, statistical analysis of multivariate biomarker ratios was completed using a commercial chemometrics program (Pirouette Version 4.5, Infometrix) for genetic classification and oil-source rock correlation. Exploratory data analysis included hierarchical cluster analysis (HCA) and principal component analysis (PCA). A detailed description of applied HCA and PCA methods is described in Peters et al. (2007). 2.2.3. Analysis of Diamondoids Analyses (Biomarker Technologies, Inc.) included quantitative diamondoid analysis (QDA) and quantitative extended diamondoid analysis (QEDA), as described in Moldowan et al. 6

(2015). Diamondoids are highly stable cage-like compounds that are more thermally resistant than biomarkers and most other hydrocarbons in oil (McKervey, 1980). The correlation between diamondoid (3- + 4- methyldiamantanes) and biomarker (stigmastane) concentrations in analyzed samples was used to estimate the level of thermal maturity and the extent of secondary cracking (Dahl et al., 1999). The distribution of extended diamondoids (larger than three-caged triamantane) is related to the source and was used to distinguish Shublik end-member and mixedoil types, and for oil-source rock correlation (Moldowan et al., 2015). In addition, compoundspecific isotope analysis of diamondoids (CSIA-D), an independent correlation tool, complimentary QEDA, was applied for oil-source rock correlation (Moldowan et al., 2015). 3. Results 3.1. Source rock screening and bulk oil characteristics Carbonate content, TOC, Rock-Eval data and calculated parameters such as hydrogen index (HI), oxygen index (OI), and production index (PI = S1/(S1+S2)) are listed in Table 2. The TOC content of the samples ranges from 0.2 to 5.4 wt%. The HI values range from 47 to 759 mg HC/ g TOC. The drastic differences in TOC and HI values are mainly due to a thermal maturity, which range from immature (Tmax < 435 °C) in the Phoenix-1 core to postmature (Tmax > 470 °C) in the Alcor-1 core. However, carbonate content variation from 24 to 89 wt% signifies presence of different lithofacies. Thus, four immature samples from the Phoenix-1well (PH01, PH07, PH08, and PH09), two mature samples from the western part of the Prudhoe Bay Field (207 and 208), and three postmature samples from the Alcor-1 well (AL02, AL03, 13AL31) compose a more than 100 km-long maturity profile from north to south across the Barrow Arch.

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In addition, two postmature samples from the Alcor-1 well were analyzed using bulk rock and clay XRD. The resultant mineralogy is summarized in Table 3 and discussed in the QEDA results section. The bulk characteristics of analyzed oils are presented in Table 1, which include depth of the reservoir and API gravity reported by Wang et al. (2014) and Lillis et al. (2015). The calcareous oil samples have relatively low API values in the range of 6.5 – 29.5°, whereas shaly Shublik oil samples have higher API value ranging from 41.1 – 47.36°. In general, this follows the observations that non-biodegraded oil from carbonate source rocks typically has lower API gravity than that from siliciclastic source rocks (Baskin and Peters, 1992; Peters et al., 2005). However, API gravity is often used as a biodegradation and thermal maturity indicator. Biomarker thermal maturity indicators suggest higher maturities for shaly Shublik oils (e.g. Ts/Tm = 1.26 – 1.44; Table 4) relative to calcareous Shublik oils (e.g. Ts/Tm = 0.23 – 0.25; Table 4). Evidence from GC-FID (Supplementary Fig. 1) shows complete unadulterated set of nalkanes for most of the samples, suggesting they are not significantly biodegraded. Although, the main reason for the very low APIs (6.5° and 12.2°) is likely biodegradation. GC-FID and biomarker analysis of D1 oil sample (API gravity = 6.5°), and the conclusion about its calcareous nature is derived from Wang et al. (2014). GC-FID analysis of this sample suggests strong biodegradation that is in line with very low gravity. Sample M1 (API=12.2; Table 1) appears to have a modest UCM (Supplementary Fig. 1). This sample shows a small charge of paraffins on top of UCM, suggesting there could have been a small secondary charge on top of it. This is common for "hybrid" or "polyphase" oils where fresh charge has entered after an earlier phase of biodegradation has occurred. We note that polyphase charge history may affect the relationship between light and heavy components and ultimately the fluid properties. All oil samples were

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subjected to QEDA. We know from previous work that QEDA is not affected by biodegradation, API gravity etc. (Moldowan et al., 2015). 3.2. Analysis of biomarkers The initial distinction of Shublik oil families was based on biomarker analysis of oil samples throughout the North Slope and source rock character was inferred from oil composition (Fig. 2; Peters et al., 2007; Wang et al., 2014). Six oil samples NS13, SP1a, N1, KC4, F5a, and M1 (previously studied by Wang et al., 2014) were included in order to establish ‘calcareous’ and ‘shaly’ end-member characteristics and to be compared with source rock extracts. Samples compared with these end-members include CO1 oil sample, PH04 oil extract from Ivishak Sandstone, and five Shublik rock extracts (13AL31, PH01, PH07, PH08 and PH09). In addition, saturate and aromatic fractions of Samples 207 and 208, rock extracts from Seifert et al. (1980), were re-analyzed and included in the oil-source rock correlation. Source-specific differences between samples were based on quantification of biomarker concentrations using GCMS and GCMS/MS profiles. The resultant key biomarker ratios are listed in Table 4. For a full list of measured parameters, refer to Supplementary Table S1. All samples, except CO1 and 13AL31, contain tricyclic terpanes ranging from C 19 to C30 with a high relative abundance of extended side-chain tricyclic terpanes (cheilanthanes) to pentacyclic triterpanes (hopanes) (Fig. 3). Oil sample CO1 has relatively abundant cheilanthanes but low hopane concentrations, indicating higher thermal maturity than the other samples. Rock extract 13AL31 lacks biomarkers (Fig. 3), confirming a postmature thermal maturity as suggested by Rock-Eval pyrolysis (Tmax > 470 °C) and diamondoid concentrations (cracking estimate by QDA = 98%, Table 5,). Thus, all oils and rock extracts, except CO1 and 13AL31,

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were subjected to chemometric analysis following guidelines described in Peters et al. (2007) and Wang et al. (2014) for consistency of results. Fig. 4 shows two chemometric runs using identical HCA and PCA methods and sets of biomarker ratios, applied to different sample sets. The first sample set (Fig. 4A, B) includes biomarker results for 40 North Slope oils published by Wang et al. (2014) combined with current results for comparison of chemometric classifications of genetically-distinct groups. The results display similar HCA (Fig. 4A) and PCA (Fig. 4B) grouping of the six previously-studied oil samples (NS13, SP1a, N1, KC4, F5a, and M1) into calcareous and shaly Shublik families, and classify newly-acquired samples within those groups. The second sample set (Fig. 4C, D) includes only results from our current work. Most of the samples show similar genetic relationships to those evident from two chemometric runs; however, in the second scenario, oil sample F5a and rock extract PH08 cluster with the shaly Shublik group on HCA dendrogram (Fig. 4C). On the PCA scores plot (Fig. 4D), sample PH08 is an outlier, whereas sample F5a indicates a mixed-oil type by plotting between the two groups. In the larger sample set, the two Shublik families (Triassic) are distinct from other oil families (Jurassic Kingak Shale, Cretaceous pebble shale unit, Cretaceous Hue-HRZ, and Tertiary Canning Formation). In the smaller sample set composed of the two Shublik families alone, the groups are less distinct, resulting in slightlydifferent less-reliable hierarchical clustering and principal component groupings. 3.3. Quantitative diamondoid analysis (QDA) QDA was performed on all of the samples analyzed for biomarkers and results are listed in Table 5. Fig. 5A shows no greater loss of 1- + 2-methyladamantanes relative to 3- + 4methyldiamantanes for most of the samples, which generally follow the established trend line. This trend is unique and relatively constant for each source, and is independent of oil cracking

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(Moldowan et al., 2015). Thus, both the shaly and calcareous Shublik samples plot within the same source trend. Samples 207, 208, and PH04 yield near zero concentrations and plot away from the trend line, suggesting preferential evaporation of the more volatile compounds during storage. This is not surprising since the saturate and aromatic fractions of previously analyzed extracts 207 and 208 were stored since 1980, and the core (sample PH04) was drilled and stored in 1987. The plots of diamondoid (3- + 4- methyldiamantanes) vs. biomarker (stigmastane) concentrations allows estimates the extent of oil cracking for the samples without significant evaporative losses (Fig. 5B). The extract from sample PH08 yields a high C29 ααα 20R stigmastane concentration (301.3 ppm) and the smallest 3- + 4-methyldiamantanes concentration (7.4 ppm) among the calcareous Shublik samples, suggesting absence of secondary thermal cracking. Thus, the 7.4 ppm value of PH08 is used as the “diamondoid baseline” in the formula of Dahl et al. (1999) to estimate the extent of cracking for calcareous Shublik samples (Table 5). The resulting cracking percentages for F5a, M1, KC4, and CO1 oils are 22, 47, 50, and 75%, respectively. The highest maturity of CO1 oil (75% of cracking) among the calcareous Shublik oils agrees with its high-maturity hopane signature detected from the m/z 191 chromatogram of its saturate fraction (Fig. 3). Extract 13AL31 yielded very high 3- + 4-methyldiamantane concentration (400 ppm) and the resulting estimation of the extent of cracking at 98% (Table 5), confirms a postmature level of thermal maturity predicted also by the absence of biomarkers and a high Tmax value (475 °C). QDA results for calcareous Shublik extracts (PH01 and PH09), and the shaly Shublik extract (PH07) suggest that a high maturity charge infiltrated much of the immature Phoenix-1 well core. Shaly Shublik oils N1 and NS13 yield very low 3- + 4-methyldiamantane

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concentrations (4.5 and 4.6 ppm), which were used as a “diamondoid baseline” for the extent of cracking estimation in the shaly Shublik samples (Table 5). The calculated extent of cracking for sample SP1a is 33 %. Measured 3- + 4-methyldiamantanes concentrations from Wang et al. (2014) are 3.18 and 3.37 ppm, and similar to the 4.5 and 4.6 ppm numbers measured here. However, Wang et al. (2014) used the value of 10.6 ppm as the diamondoid baseline for the whole suite of Shublik oil samples. Current work proposes separate baselines for calcareous (7.4 ppm) and shaly (4.5 ppm) Shublik samples that affects estimates of the secondary cracking. 3.4. Quantitative extended diamondoid analysis (QEDA) All oil samples (NS13, SP1a, N1, KC4, F5a, M1 and CO1) were subjected to QEDA. Due to small sample sizes, the five Phoenix-1 extracts and the one Alcor-1 extract (13AL31) did not yield diamondoid concentrations sufficient for QEDA. However, two additional samples (AL02 and AL03) were taken from the Alcor-1 core. These biomarker-poor overmature Shublik samples correlate to end-member oil types using QEDA. In addition, shaly Shublik oil samples SP1b, and two calcareous Shublik oils MB13b and D1 from Wang et al. (2014) were subjected to QEDA to better distinguish the end-member (Fig. 4A, B) and mixed-oil types suggested by chemometrix (Fig. 4C, D). Fig. 6 and Supplementary Table S2 show QEDA results for the analyzed samples. In this study, the two rock samples (AL02 and AL03) from the overmature Alcor-1 core were found to be calcareous and shaly Shublik organofacies “end-members.” All of the shaly Shublik oils (NS13, SP1a, SP1b, and N1) suggested by Wang et al. (2014) appear to be mixtures with variable degree of mixing between end members. Sample NS13 is the nearest to be an endmember among the analyzed shaly Shublik oils, whereas sample KC4 is the calcareous Shublik end-member oil sample. All of the proposed calcareous Shublik oils plot very near (greyed out

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area on Fig. 6) the rock extract end-member (AL02), displaying a much clearer QEDA signature and oil type than do shaly Shublik oils. Shublik Formation is a heterogenous unit composed of juxtaposed source rock and non-source intervals (Yurchenko et al., 2018). Sample AL03 is not a “typical” Shublik source rock, having a 97.8% carbonate content and TOC<0.2 wt%. This sample is from a non-source layer within Shublik Formation in the Alcor-1 core. Its carbonate content probably surpasses that for the source rocks of any of the Shublik oils, however it’s used as calcareous Shublik end-member rock sample. We suppose the extreme carbonate content results in a more extreme peak at Pentamantanes 1 and 3 (P1 and P3) compared to less pronounced P1 and P3 peaks in the QEDA signatures of any of the oils (Fig. 6). 3.5. Compound-specific isotope analysis of diamondoids (CSIA-D) Moldowan et al. (2015) advised using CSIA-D in conjunction with QEDA for the most reliable interpretations. Contrary to QEDA, CSIA-D of the analyzed oils and rock extracts is not useful for differentiating calcareous and shaly Shublik organofacies. The similar CSIA-D signatures for all of the Shublik samples may suggest common OM source interpretation for both calcareous and shaly Shublik facies (Fig. 7). 4. Discussion 4.1. Organic matter input A monoaromatic steroid biomarker ternary distribution plot was used to determine OM source input (Fig. 8). The relative abundance of C27, C28, and C29 monoaromatic steroids in aromatic fraction were measured by GCMS since they display no significant molecular ion, and therefore, cannot be analyzed by GCMS/MS. Most of the samples plot in the overlap between the marine carbonate and non-marine shale groups (Moldowan et al., 1985). Algal OM may result in elevated proportion of C29 monoaromatic steroids (Volkman, 1986, 2003). This is also 13

supported by the presence of C30 n-propylcholestanes (Supplementary Table S1) and C30 diasteranes (Fig. 9). Both groups of compounds are diagnostic of marine Chrysophyte algae. In addition, the abundant tricyclic terpanes in all of the analyzed samples (Fig. 3) suggest that unicellular green algae Tasmanites was a significant source constituent during the deposition of the Shublik Formation (Aquino Neto et al., 1992; Yurchenko et al., 2018). This is supported by the widespread occurrence of Tasmanites reported in outcrops of the Brooks Range believed to be Jurassic and possibly Triassic (Tourtelot and Tailleur, 1965; Burruss et al., 2008). The Tasmanites cysts are also dominant fossils in the Botneheia Formation of Svalbard and in the correlative beds in the Barents Sea, key Triassic petroleum source rocks of the circum-Arctic region (Vigran et al., 2008). Four source rock samples (PH01, PH07, PH08, and PH09) from Phoenix-1 core discussed in Yurchenko et al. (2018) display high HI values (634, 613, 564, and 759 mg HC/ g TOC) with algal type I kerogens. Robison et al. (1996) also reported that kerogen composition of the Shublik core in the Phoenix-1 well is mainly fluorescent amorphous algal organic matter (amorphite), alginite, and exinite, with minor amounts of non-fluorescent amorphite, vitrinite, and inertinite. In conclusion, algal organic matter is dominant in both calcareous and shaly Shublik organofacies and in biomarker (sterane and cheilanthane) evidence from the oils. In addition, similar CSIA-D signatures (Fig. 7) and shared QDA source-related trend (Fig. 5A) support common OM source interpretation for both calcareous and shaly Shublik samples. 4.2. Oil-source rock correlation The C27 - C28 - C29 sterane and diasterane ternary plots are highly source-specific and are used for oil-source rock correlation (Fig. 9; Peters at al., 2005). The results support a distinction

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between calcareous and shaly Shublik oil families. However, shaly Shublik oil sample N1 plots near the calcareous Shublik family, rather than the shaly group. This distinction is more evident from diasterane distributions. Rock extract PH07 correlates closely to shaly Shublik oils (NS13 and SP1a), whereas the rest of the Phoenix-1 extracts plot within or near the area occupied by the calcareous Shublik oil family. The two Prudhoe Bay extracts (207 and 208) are both plotted within the calcareous group, which contradicts with chemometric analysis predictions (Fig. 4). Diasteranes/(dia + regular) C27 steranes and Ts/(Ts + Tm) depend on both source and thermal maturity but can still be used to differentiate extract and oil samples by their source rock depositional environment (Fig. 10; Moldowan et al., 1994). The samples cluster according to oxicity and acidity of the depositional environment, although the relative importance of lithology and oxicity remains unknown (Peters et al., 2005). The Ts/(Ts+Tm) ratio is sensitive to claymediated acid-catalyzed reactions, thus samples from anoxic the carbonate group have low Ts/(Ts+Tm) ratios compared to anoxic shales (e.g., McKirdy et al., 1984). Similarly, diasteranes (rearranged steranes) are low in clay-poor carbonate source rocks and related oils (Peters et al., 2005). Low Ts/(Ts+Tm) of the shaly Shublik extract PH07 may be due to low maturity. Oil sample CO1 was left out of this plot due to high thermal maturity, which resulted in unreliable trisnorhopane and diasterane measurements. Fig. 11 shows C24/C23 tricyclic terpane versus C29/(C29 + C30) hopane ratios that also support separation of the Shublik into two genetically-distinct groups. Shaly Shublik samples plot closer together, while calcareous samples have a wider spread. All four peaks (C 23, C24, C29, and C30) are among the largest on the m/z 191 (Fig. 3). Although tricyclic terpanes are likely linked to Tasmanites, various tricyclic terpane ratios are valuable for predicting source-rock depositional environments based on measurements of many world-wide oils (Peters et al., 2005).

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Organic-rich carbonate rocks and related oils usually show larger peak C29 relative to C30 hopane (e.g. Zumberge, 1984). Elevated C29/(C29 + C30) hopane values are consistent with calcareous Shublik source rock. 4.3. Prediction of source rock character from oil composition Petroleum composition depends on the type of organic matter, lithology, and redox conditions, as well as many secondary effects that include, but are not limited to thermal maturation, migration, and biodegradation (Peters et al., 2005). Similar levels of thermal maturity for extracts and oil samples allows for optimal chemometric classification of samples into genetically-distinct groups, as well as for oil-source rock correlation. Thus, distinguishing thermal maturity from organic matter input and depositional environment effects on petroleum composition, including the biomarker fingerprints, is critical for better results. The exception illustrated here comes from diamondoid correlation methods. For example, very mature oil sample CO1 with very low biomarker concentrations can be correlated with biomarker-rich oils KC4 and F5a by QEDA (Figure 6). Although the source rocks and oils in this study vary in thermal maturity, we focus the following discussion on key source-related parameters that control differentiation of calcareous and shaly Shublik oil families and their mixtures. 4.3.1. Redox and salinity The C31 to C35 homohopane distributions support subdivision of Shublik oil samples into two genetically distinct families (Fig. 12). Both calcareous (KC4, M1, F5a) and shaly (NS13 and SP1a) Shublik oils show similar enrichment in C35 homohopanes, typical of organic matter from anoxic depositional settings (Peters and Moldowan, 1991). The regular stair-step progression of C31 - C35 homologs observed on m/z 191 is consistent with this interpretatation (Fig. 3). Except for the C32 homohopanes, N1 oil plots either with calcareous group (C31, C35 homohopanes) or 16

between the two groups (C33, C34 homohopanes), and may be considered as mixture, that is supported by other geochemical data (Fig. 13A). Samples N1 and F5a display lower C35 homohopane indices consistent with suboxic bottom waters during deposition (Fig. 13A). Gammacerane is commonly linked to water-column stratification due to salinity during sourcerock deposition (Sinninghe Damsté et al., 1995). Higher gammacerane indices [gammacerane/(gammacerane + C30 hopane)] suggest a more stratified water column during deposition of the clay-poor facies . 4.3.2. Lithology Biomarker analysis revealed that ratios of C22/C21, C24/C23, C24 tetracyclic (Tet)/C26 tricyclic terpanes, C29/ C30 hopanes, diahopane index (C30* 17α-diahopane /(C30* 17α-diahopane + 17α-hopane); Fig. 3), and diasteranes/(dia + regular) C27 steranes were the most useful for differentiating calcareous from shaly Shublik oil families, as well as organofacies (Fig. 13B-D). Both rearranged steranes (diasteranes) and hopane (diahopane) form as a result of the claymediated acid-catalyzed rearrangement of biological precursors during diagenesis (Rubinstein et al., 1975). Thus, low diasteranes/steranes and diahopane index ratios indicate a clay-poor environment during diagenesis. Conversely, higher values for these ratios suggest deposition under clay-rich conditions. Similarly, diamondoids are believed to result from this catalytic rearrangement of organic precursors (such as multi-ringed terpenoids) on clay minerals during oil generation (Dahl et al., 1999). QEDA analysis also supports the calcareous versus shaly Shublik distinction, but additionally provides signature of rock end-members and oil mixtures (Fig. 6). It is striking that “shaly” Shublik end member AL02 has 58.1 wt% carbonate and 7.7 wt% clay (Table 3), whereas “calcareous” Shublik end member AL03 has 97.8 wt% carbonate and < 1 wt% clay, placing

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them both in the category of “carbonate rocks.” In addition, shaly Shublik extract PH07 and three calcareous extracts (PH01, PH08, and PH09) from the Phoenix-1 core have 25.3, 24.2, 30.2, and 38.5 wt% carbonate, respectively (Table 2). All of these values are in the same range, and there is no difference in carbonate content for the shaly Shublik end-member PH07 (25.3 wt%). The 25 – 40 wt% range of the Phoenix-1 biomarker end-members is drastically different from the Alcor-1 QEDA end-members (58 - 90 wt%; Table 3). Clay creates a more reactive setting for catalytic rearrangements of biomarkers and diamondoids that affects composition of expelled petroleum. Thus, the presence or absence of active clay minerals is more important than the carbonate content per se. Some clays, such as montmorillonite, are very catalytically active and can act as a super acid; while others like illite are not very acidic or catalytically active. Wei (2006) heated various hydrocarbons and other natural products with montmorillonite, kaolinite and illite clay, respectively, and obtained diamondoids (albeit the sensitivity of his analysis at that time did not allow a good accounting for diamondoids larger than triamantane). This shown that small proportion of montmorillonite can have a greater effect than a large proportion of illite (Wei et al., 2006). By analogy the conversion of sterenes to diasterens is controlled by claymediated acid-catalysis (Rubinstein et al., 1975). 5. Conclusions Detailed geochemical analysis of Alaska North Slope rock extracts and oils was performed to address differences in Shublik organofacies and their effect on compositions of oil accumulations. This work confirms classification of the Shublik Formation into two geneticallydistinct organofacies and related oil families and reveals mixtures between the two. These important differences between samples are based on the combined chemometric evaluation of

18

multivariate biomarker data, detailed comparison of mass-chromatograms, and individual biomarker ratios, coupled with QEDA results. These data indicate dominantly marine algal input for both organofacies deposited under similar redox condition (anoxic to suboxic) in either clay-rich or clay-poor depositional setting. However, the analyzed core samples show no apparent correlation between carbonate and clay content and organofacies assignments. It is suggested that presence of active clay minerals, most likely montmorillonite, during the deposition of clay-enriched facies, played a major role in catalytic rearrangements of biomarkers and diamondoids resulting in distinct oil signatures. Additionally, we confirmed presence of both Shublik organofacies in the Phoenix-1 core north of the Barrow Arch, and in the Alcor-1 core to the south. This suggests both organofacies are present across the basin. Details of the map and startigraphic distribution of the Shublik oil families and organic facies is discussed in Yurchenko (2017). It is controlled by the interplay of clay content and siliciclastic input during the deposition, basin geometry and burial history, source rock maturity, lateral and vertical facies variability, and migration pathways. Acknowledgments This study was supported by the Stanford Basin and Petroleum System Modeling (BPSM) Industrial Affiliates Program. Special thanks are due to Ed and Karen Duncan, and Great Bear Petroleum for granting access to the Alcor-1 Shublik core, sampling permission, and funding this research. The authors thank Ken Bird for his recommendations during this research, and for providing oil sample from the Colville-1 well. Special thanks are due to USGS Core Research Center in Denver, Colorado for granting access to the Phoenix-1 Shublik core and allowing core sampling. We also thank Biomarker Technologies, Inc. for academic discount and lab assistance, Agilent Technologies for access to MassHunter workstation software, Infometrix,

19

Inc. for Pirouette software academic package, and K-T GeoServices, Inc. for providing academic discount on their services. Reviews from the associate editor and two anonymous reviewers significantly improved this manuscript. References Aquino Neto, F.R., Triguis, J., Azevedo, D.A., Rodriques, R., and Simoneit, B.R.T., 1992, Organic geochemistry of geographically unrelated tasmanites: Organic Geochemistry, v. 18, p. 791–803, doi: 10.1016/0146-6380(92)90048-3. Baskin, D.K., and Peters, K.E., 1992, Early generation and characteristics of a sulfur-rich Monterey kerogen, AAPG Bulletin, v. 76, p. 1-13.Burruss, R.C., Dumoulin, J.A., Graham, G.E., Harris, A.G., Johnson, C.A., Kelley, K.D., Leach, D.L., Lillis, P.G., Marsh, E.E., Moore, T.E., and Potter, C.J., 2008, Regional Fluid Flow and Basin Modeling in Northern Alaska: Bird, K.J., 1994. Ellesmerian (!) petroleum system, North Slope, Alaska, USA, in Magoon, L.B., Dow, W.G., eds., The Petroleum System – From Source to Trap: AAPG Memoir 60, p. 339–358. Bird, K.J., and Houseknecht, D.W., 2011, Chapter 32 Geology and petroleum potential of the Arctic Alaska petroleum province: Geological Society, London, Memoirs, v. 35, p. 485– 499, doi: 10.1144/M35.32. Dahl, J.E., Moldowan, J.M., Peters, K.E., Claypool, G.E., Rooney, M.A., Michael, G.E., Mello, M.R., and Kohnen, M.L., 1999, Diamondoid hydrocarbons as indicators of natural oil cracking: Nature, v. 399, p. 54-57, doi: 10.1038/19953. Houseknecht, D.W., and Bird, K.J., 2004, Sequence stratigraphy of the Kingak Shale (JurassicLower Cretaceous), National Petroleum Reserve in Alaska: AAPG Bulletin, v. 88, p. 279–302, doi: 10.1306/10220303068. Houseknecht, D.W., Bird, K.J., and Garrity, C.P., 2012, Assessment of Undiscovered Petroleum Resources of the Arctic Alaska Petroleum Province Scientific Investigations Report 2012 – 5147, 33 p. Lillis, P.G., Peters, K.E., and Magoon, L.B., 2015, Oil types of the Alaskan North Slope - a progress report: Search and Discovery, Magoon, L.B. and Bird, K.J., 1985. Alaskan North Slope petroleum geochemistry for the Shublik Formation, Kingak Shale, pebble shale unit, and Torok Formation, in Magoon, L.B., Claypool, G.E., eds., Alaska North Slope Oil/Source Rock Correlation Study, vol. 20. Tulsa, AAPG Studies in Geology 20, p. 31–48. Masterson, W. D., 2001, Petroleum filling history of central Alaskan North Slope fields: Ph.D. thesis, University of Texas at Dallas, Dallas, Texas, 222 p. 20

McKervey, M.A., 1980, Synthetic approaches to large diamondoid hydrocarbons, Tetrahedron 36, p. 971–992. McKirdy, D.M., Kantsler, A.J., Emmett, J.K., and Aldridge, A.K., 1984, Hydrocarbon genesis and organic facies in Cambrian carbonates of the eastern Officer Basin, South Australia, in Petroleum Geochemistry and Source Rock Potential of Carbonate Rocks., p. 13–32. Moldowan, J.M., Seifert, W.K., and Gallegos, E.J., 1985, Relationship between petroleum composition and depositional environment of petroleum source rocks: American Association of Petroleum Geologists Bulletin, v. 69, p. 1255–1268, doi: 10.1080/10916469808949779. Moldowan, J.M., Peters, K.E., Carlson, R.M.K., Schoell, M., and Abu-Ali, M., 1994, Diverse applications of petroleum biomarker maturity parameters: Arabian Journal for Science and Engineering, v. 19, p. 273–98. Moldowan, J.M., Dahl, J., Zinniker, D., and Barbanti, S.M., 2015, Underutilized advanced geochemical technologies for oil and gas exploration and production-1. The diamondoids: Journal of Petroleum Science and Engineering, v. 126, p. 87–96, doi: 10.1016/j.petrol.2014.11.010. Peters, K.E., and Moldowan, J.M., 1991, Effects of source, thermal maturity, and biodegradation on the distribution and isomerization of homohopanes in petroleum: Organic Geochemistry, v. 17, p. 47–61, doi: 10.1016/0146-6380(91)90039-M. Peters, K.E., and Casa, M.R., 1994, Applied Source Rock Geochemistry, in Magoon, L.B., and Dow, W.G., 1994, The petroleum system - from source to trap: AAPG Memoir 60. Peters, K. E., Walters. C. C., and Moldowan. J. M., 2005, The Biomarker Guide 2nd edition volume 2. Biomarker and isotopes in petroleum exploration and earth history: New York, Cambridge University Press, 1155 p. Peters, K.E., Magoon, L.B., Bird, K.J., Valin, Z.C., and Keller, M.A., 2006, North Slope, Alaska: Source rock distribution, richness, thermal maturity, and petroleum charge: AAPG Bulletin, v. 90, p. 261–292, doi: 10.1306/09210505095. Peters, K.E., Ramos, L.S., Zumberge, J.E., Valin, Z.C., Scotese, C.R., and Gautier, D.L., 2007, Circum-Arctic petroleum systems identified using decision-tree chemometrics: AAPG Bulletin, v. 91, p. 877–913, doi: 10.1306/12290606097. Peters, K.E., Scott Ramos, L., Zumberge, J.E., Valin, Z.C., and Bird, K.J., 2008, De-convoluting mixed crude oil in Prudhoe Bay Field, North Slope, Alaska: Organic Geochemistry, v. 39, p. 623–645, doi: 10.1016/j.orggeochem.2008.03.001. Robison, V.D., Liro, L.M., Robison, C.R., Dawson, W.C., and Russo, J.W., 1996, Integrated geochemistry, organic petrology, and sequence stratigraphy of the triassic Shublik Formation, Tenneco Phoenix 1 well, North Slope, Alaska, U.S.A.: Organic Geochemistry, v. 24, p. 257–272, doi: 10.1016/0146-6380(96)00023-X. 21

Rubinstein, I., Sieskind, O., and Albrecht, P., 1975, Rearranged sterenes in a shale: occurrence and simulated formation: Journal of the Chemical Society, Perkin Transactions, v. 1, p. 1833–1836, doi: 10.1039/p19750001833. Seifert, W. K., Moldowan, J. M., and Jones, R. W., 1980, Application of biological marker chemistry to petroleum exploration: Proceedings of the 10th World Petroleum Congress, Bucharest, Romania, September 1979, Paper SP8: Heyden & Son Inc., Philadelphia, Pennsylvania, p. 425–440. Sinninghe Damsté, J.S., Kenig, F., Koopmans, M.P., Köster, J., Schouten, S., Hayes, J.M., and de Leeuw, J.W., 1995, Evidence for gammacerane as an indicator of water column stratification: Geochimica et Cosmochimica Acta, v. 59, p. 1895–1900, doi: 10.1016/0016-7037(95)00073-9. Tourtelot, H. a., and Donnell, J.R., 1967, Oil yield and chemical composition of shale from northern Alaska, in Proceedings 7th world petroleum congress, Mexico City, v. 3, p. 707–711. Vigran, J.O., Mørk, A., Forsberg, A.W., Weiss, H.M., and Weitschat, W., 2008, Tasmanites algae - Contributors to the Middle Triassic hydrocarbon source rocks of Svalbard and the Barents Shelf: Polar Research, v. 27, p. 360–371, doi: 10.1111/j.17518369.2008.00084.x. Volkman, J.K., Allen, D.I., Stevenson, P.L., and Burton, H.R., 1986, Bacterial and algal hydrocarbons in sediments from a saline Antarctic lake, Ace Lake: Organic Geochemistry, v. 10, p. 671–681, doi: 10.1016/S0146-6380(86)80003-1. Volkman, J.K., 2003, Sterols in microorganisms: Applied microbiology and biotechnology, v. 60, p. 495–506, doi: 10.1007/s00253-002-1172-8. Wang, Y., Peters, K.E., Moldowan, J.M., Bird, K.J., and Magoon, L.B., 2014, Cracking, mixing, and geochemical correlation of crude oils, North Slope, Alaska: AAPG Bulletin, v. 98, p. 1235–1267, doi: 10.1306/01081412197. Wei, Z., 2006, Molecular organic geochemistry of cage compounds and biomarkers in the geosphere: a novel approach to understand petroleum evolution and alteration: Ph.D. thesis, Stanford University, Stanford, California, 384 p. Wei, Z., Michael Moldowan, J., Dahl, J., Goldstein, T.P., and Jarvie, D.M., 2006, The catalytic effects of minerals on the formation of diamondoids from kerogen macromolecules: Organic Geochemistry, v. 37, p. 1421–1436, doi: 10.1016/j.orggeochem.2006.07.006. Wicks, J. L., Buckingham, M. L., and Dupree, J. H., 1991, Endicott field– U.S.A., North Slope basin, Alaska, in N. H. Foster and E. A. Beaumont, eds., Structural traps V: AAPG Treatise of Petroleum Geology, Atlas of Oil and Gas Fields, p. 1–25.

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Yurchenko, I.A., 2017, Stratigraphic and depositional controls on source rock heterogeneity and composition of expelled petroleum in the Triassic Shublik Formation of Arctic Alaska: Ph.D. thesis, Stanford University, Stanford, California, 173 p. Yurchenko, I.A., Moldowan, J.M., Peters, K.P., Magoon, L.B., and Graham, S.A., 2018, Source rock heterogeneity and migrated hydrocarbons in the Triassic Shublik Formation and their implication for unconventional resource evaluation in Arctic Alaska, Marine and Petroleum Geology, doi: 10.1016/j.marpetgeo.2018.03.033 Zumberge, J.E., 1984, Source rocks of the La Luna Formation (Upper Cretaceous) in the Middle Magdalena Valley, Colombia: Petroleum Geochemistry and Source Rock Potential of Carbonate Rocks., p. 127–134, doi: 10.1016/0146-6380(90)90053-3.

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Table 1. Summary of oil and rock samples analyzed in this study. Well names and Unique Well Identifier (UWI) are in compliance with Alaska Geologic Materials Center Inventory. Rock extracts 207 and 208, and oil samples NS13, SP1a, SP1b, N1, KC4, F5a, M1, MB13b, and D1 were previously analyzed by Seifert et al. (1980) and Wang et al. (2014) respectively. API gravity is reported by Lillis et al. (2015). Previously published sample names were utilized for consistency. Samples PH01, PH07, PH08, and PH09 were also discussed in Yurchenko (2017) and Yurchenko et al. (2018).

NS13

Oil

Wang et al., (2014) oil type Shaly

SP1a

Oil

Shaly

Sample ID

SP1b

Sample type

Oil

Shaly

N1

Oil

Shaly

F5a

Oil

Calcareous

Field name Well name

UWI

Reservoir

3573.5

41.1

x

x

x

OCS Y-0370 Sandpiper 1

55201000070000

Sandpiper

Ivishak Fm.

3659.1

41.38

x

x

x

55201000070000

Sandpiper

Ivishak Fm.

3630.2

47.36

-

-

x

2660.9

44.13

x

x

x

2140.9

29.5

x

x

x

2160.4

22.7

x

x

x

U. Kuparuk Ss.

2243.3

12.2

x

x

x

Lisburne Gr

2611.5

6.5

-

-

x

3618.0

22.4

-

-

x

2399.4 2743.2

29.6

x

x

x

-

x

x

-

-

x

x

-

-

x

x

-

-

x

x

-

-

x

x

-

-

x

x

-

-

x

x

-

-

x

x

-

OCS Y-0370 Sandpiper 1 Nikaitchuq 1

50629231930000

Fiord 5

50103202920000

NW Mile Point Colville River

Kuparuk Riv Unit 1C-04

50029205470000

M1

Oil

Calcareous

OCS Y-0334 Mukluk 1

55231000010000

D1

Oil

Calcareous

50279200060000

wildcat

MB13b

Oil

Calcareous

CO1

Oil Rock extract Rock extract Rock extract Rock extract Rock extract Rock extract Oil extract Rock

N/A

J W Dalton Test Well 1 Mikkelsen Bay St 13-0919 Colville 1

N/A

Kuparuk St 7-11-12

50029200620000

N/A

W Kuparuk St 3-11-11

50029200140000

N/A

OCS Y-0338 Phoenix 1

55231000050000

N/A

OCS Y-0338 Phoenix 1

55231000050000

N/A

OCS Y-0338 Phoenix 1

55231000050000

N/A

OCS Y-0338 Phoenix 1

55231000050000

N/A

OCS Y-0338 Phoenix 1

55231000050000

N/A

Alcor 1

50223200260000

PH08 PH09 PH04 13AL31

QEDA

Ivishak Fm.

Calcareous

PH07

QDA

Northstar

Oil

PH01

Analyses performed B*

50029230170000

KC4

208

API gravity

Northstar Unit NS-13

Kuparuk River wildcat

207

Depth (m)

50029200550000 50103100020000

24

wildcat wildcat Prudhoe Bay Prudhoe Bay wildcat wildcat wildcat wildcat wildcat wildcat

Sag River Ss. Nechelik Sand Kuparuk Fm.

Lisburne Gr. Shublik Fm. Shublik Fm. Shublik Fm. Shublik Fm. Shublik Fm. Shublik Fm. Shublik Fm. Ivishak Fm. Shublik Fm.

2743.2 2459.7 2442.5 2413.9 2428.2 2463.6 3225.4

extract AL02 AL03

Rock extract Rock extract

N/A

Alcor 1

50223200260000

N/A

Alcor 1

50223200260000

B* - analysis of biomarkers QDA – Quantitative diamondoid analysis QEDA - Quantitative extended diamondoid analysis

25

wildcat wildcat

Shublik Fm. Shublik Fm.

3232.8 3234.3

-

-

-

x

-

-

-

x

Table 2. Carbonate content, total organic carbon (TOC), and Rock-Eval pyrolysis results for analyzed rock samples. TOC and thermal alteration index (TAI) data for samples 207 and 208 are from Seifert et al. (1980). Detailed XRD and XRF (x-ray fluorescence) mineralogy for Phoenix-1 source rock samples (PH01-09) and the entire Shublik interval is reported in Yurchenko (2017) and Yurchenko et al. (2018).

Sample

Defined

Depth

Carbonate

TOC

S1

S2

Tmax

ID

Shublik

(m)

(wt.)

(wt.)

(mg

(mg

(°C)

HC/g

HC/g

rock)

rock)

type

TAI

HI

OI

S1/TOC

(mg HC/

(mg

(mg HC/ g

g TOC)

HC/mg

TOC)

PI

Maturity

CO2)

13AL31

-

3225.4

43.5

4.2

1.6

2.5

473

-

59

11

38

0.4

Postmature

AL02

Shaly

3232.8

64.6

3.9

0.9

2.0

476

-

50

6

24

0.3

Postmature

AL03

Calcareous

3234.3

88.6

<0.2

<0.1

<0.1

-

-

-

-

-

-

Postmature

PH01

Calcareous

2459.7

24.2

4.3

2.2

27.2

432

-

634

12

51

0.07

Immature

PH07

Shaly

2442.5

25.3

4.8

1.5

29.2

431

-

613

11

32

0.05

Immature

PH08

Calcareous

2413.9

30.2

3.1

1.0

17.4

431

-

564

14

32

0.05

Immature

PH09

Calcareous

2428.2

38.5

5.4

1.8

40.8

436

-

759

8

33

0.04

Immature

207

Shaly

2743.2

-

2.9

-

-

-

2.8

-

-

-

-

Peak

208

Shaly

2743.2

-

4.4

-

-

-

2.7

-

-

-

-

Peak

26

Table 3. Whole rock and clay x-ray diffraction (XRD) mineralogy results.

Carbonates

Clays

Sample

Quartz

K-feldspar

Plagioclase

Calcite

Dolomite

Apatite

Pyrite

Gypsum

Illite/Mica

Illite/Smectite

ID

(wt%)

(wt%)

(wt%)

(wt%)

(wt%)

(wt%)

(wt%)

(wt%)

(wt%)

(wt%)

AL02

20.1

0.7

1.9

52.9

5.2

9.4

1.7

0.4

5.6

2.1

AL03

1.1

0

0

97.8

0

0

0.2

0

0.9

0

27

Table 4. Key biomarker characteristics of oils and rock extracts from the North Slope of Alaska. Biomarker Ratio

PH01

PH04

PH07

PH08

PH09

207

208

N1

NS13

SP1a

F5a

KC4

M1

CO1

C24/C23 tricyclic terpanes C22/C21 tricyclic terpanes C24 tetracyclic/C26 tricyclics C29/C30 hopane Diahopane Index Ts/Tm Gammacerane Index Homohopane index C31% C32% C33% C34% C35% Ts/Tm αββC27(20S+20R) / Total αββ(20S+20R) (C27+C28+C29) αββC28(20S+20R) / Total αββ(20S+20R) (C27+C28+C29) αββC29(20S+20R) / Total αββ(20S+20R) (C27+C28+C29) C27 diasteranes/(regulars+dias) C28 diasteranes/(regulars+dias) C29 diasteranes/(regulars+dias) Total C27-C29 diasteranes/(regulars+dias) %C27 (253) %C28 (253) %C29 (253)

0.36 0.31 0.17 0.56 0.03 0.44 0.07 0.08 26.94 16.84 24.05 14.76 17.42 0.62

0.51 0.86 0.54 0.97 0.03 0.35 0.06 0.08 32.21 18.89 17.70 13.20 17.99 0.44

1.24 0.39 0.25 0.40 0.05 0.36 0.02 0.06 32.88 22.13 18.62 11.50 14.87 0.45

0.61 0.31 0.14 0.61 0.03 0.41 0.01 0.03 39.45 22.59 16.94 12.01 9.00 0.56

0.68 0.51 0.76 0.75 0.03 0.38 0.03 0.02 49.11 24.34 15.08 7.01 4.46 0.49

0.79 0.38 0.24 0.35 0.10 0.80 0.03 0.04 35.65 24.78 17.44 12.10 10.03 3.27

0.78 0.39 0.19 0.40 0.14 0.82 0.02 0.02 40.77 27.85 17.28 9.18 4.93 3.23

0.79 0.53 0.30 0.50 0.16 0.65 0.03 0.06 31.53 23.17 18.58 13.03 13.69 1.44

0.80 0.36 0.16 0.39 0.19 0.65 0.02 0.07 27.65 21.07 19.21 14.46 17.61 1.35

0.80 0.38 0.14 0.43 0.18 0.63 0.02 0.09 26.63 20.36 19.36 13.92 19.74 1.26

0.58 0.86 0.53 0.69 0.06 0.45 0.03 0.06 34.20 21.18 17.70 13.21 13.70 0.63

0.57 0.85 0.52 0.94 0.04 0.36 0.04 0.07 32.69 20.61 16.95 12.80 16.96 0.47

0.53 0.95 0.61 1.06 0.03 0.33 0.05 0.06 34.96 20.53 16.81 12.19 15.51 0.41

0.62 0.82 0.24 0.70 0.26 0.90 0.05 0.00 43.89 32.18 23.93 0.00 0.00 6.15

0.24

0.24

0.21

0.21

0.27

0.23

0.23

0.23

0.22

0.22

0.24

0.23

0.25

0.23

0.32

0.33

0.28

0.34

0.33

0.32

0.31

0.30

0.29

0.30

0.31

0.32

0.32

0.33

0.44

0.42

0.51

0.45

0.40

0.45

0.46

0.47

0.49

0.48

0.46

0.45

0.43

0.44

0.44 0.33 0.31

0.38 0.29 0.28

0.59 0.47 0.49

0.39 0.26 0.24

0.33 0.23 0.22

0.56 0.45 0.43

0.61 0.50 0.46

0.65 0.55 0.53

0.74 0.63 0.63

0.74 0.62 0.63

0.57 0.46 0.43

0.50 0.39 0.39

0.44 0.35 0.35

0.55 0.47 0.46

0.35

0.31

0.51

0.28

0.26

0.47

0.52

0.57

0.66

0.65

0.48

0.42

0.37

0.49

0.26 0.28 0.46

0.36 0.25 0.39

0.21 0.28 0.50

0.23 0.28 0.49

0.31 0.31 0.38

0.23 0.27 0.50

0.26 0.28 0.47

0.30 0.28 0.43

0.28 0.28 0.43

0.29 0.29 0.42

0.30 0.30 0.40

0.34 0.29 0.37

0.37 0.25 0.37

0.30 0.27 0.43

28

Table 5. Quantitative diamondoid analysis (QDA) results and calculated extent of oil cracking for analyzed oil and rock samples.

C29 ααα 20R stigmastane (ppm)

1- + 2-methyl adamantanes (ppm)

3- + 4-methyl diamantanes Cc (ppm)

Baseline Co (ppm)

Extent of cracking (1 – (Co/Cc)) x 100 (%)

PH01

359.1

126.6

27.1

7.4

73

PH04

83.8

0.0

1.7

7.4

N/A

PH07

62.7

117.2

21.8

4.5

79

PH08

301.3

100.0

7.4

7.4

0

PH09

17.4

196.3

36.7

7.4

80

207

21.4

0.0

0.2

4.5

N/A

208

18.5

0.0

0.4

4.5

N/A

N1

11.2

54.0

4.5

4.5

0

NS13

12.6

91.7

4.6

4.5

0

SP1a

16.9

145.3

6.8

4.5

33

F5a

18.2

80.0

9.4

7.4

22

KC4

19.1

114.4

14.8

7.4

50

M1

9.2

90.4

14.0

7.4

47

CO1

5.7

93.4

29.6

7.4

75

13AL31

0.0

1493.2

400.0

7.4

98

Sample ID

29

Figure captions Figure 1. Generalized chronostratigraphic column of Arctic Alaska after Houseknecht et al. (2012). Key petroleum source rocks are Shublik Formation (grey), Kingak Shale, pebble shale unit, and Hue Shale, including the GRZ (gamma ray zone). LCU – Lower Cretaceous Unconformity. Figure 2. Map of part of Arctic Alaska showing the study area, sampled and referenced data. Main producing oil field units (light grey) are located in the northern part of the Central North Slope along the structural axis of the Barrow Arch (dashed line). See table 1 for details on well names and locations for analyzed oil and rock samples. Referenced published data are from Peters et al. (2006, 2008) and Wang et al. (2014). Figure 3. Comparison of terpane mass chromatograms (m/z 191) for all crude oil and source rock extract samples. Black dots indicate the most useful biomarker compounds for differentiating calcareous from shaly Shublik oil families, as well as organofacies. Figure 4. A - Hierarchical cluster analysis (HCA) dendrogram, B - principal components analysis (PCA) scores plot resulted from chemometric analysis of forty North Slope oils published by Wang et al. (2014) combined with current results. C - HCA, D - PCA results from current dataset alone. Figure 5. Quantitative diamondoid analysis (QDA) results. A - The relationship between concentrations of methyladamantanes and methyldiamantanes. Established trend is unique and relatively constant for each source and is independent of oil cracking. B - The correlation between diamondoid (3- + 4- methyldiamantanes) and biomarker (stigmastane) concentrations estimates the extent of oil cracking for analyzed oils and rock extracts from the Shublik Formation. Based on ten replicate analyses of the same sample, calculated %RSD (relative standard deviation) values for 1- + 2- methyladamantanes, 3- + 4- methyldiamantanes, and stigmastane are 8.2%, 1%, and 2.9% respectively. Figure legend shows example error bars. Figure 6. Quantitative extended diamondoid analysis (QEDA) results for distinguishing Shublik end member and mixed oil types, and oil-source rock correlation. Concentrations of all the compounds are plotted relative to the triamantane concentrations. The end-member oil samples assignment to shaly and calcareous oil families was pre-determined by biomarker analysis. Based on ten replicate analyses of the same sample, calculated %RSD values for T1, T2, T3, P1, P2, P3, P4, and CHXT are 3.3%, 2.4%, 1.9%, 2.8%, 4.6%, 15.7%, 8.1%, and 13.5% respectively. Figure shows example error bars for sample NS13. Figure 7. Compound specific isotope analysis of diamondoids (CSIA-D) for calcareous and shaly Shublik comparison. Data for sample D1* are from Wang et al. (2014). The error in CSIA measurements is estimated to be +/- 0.3‰ (Peters et al., 2005). Figure shows example error bars for sample KC4.

30

Figure 8. The ternary diagram shows the relative abundance of C27, C28, and C29 monoaromatic steroids in aromatic fraction of Shublik oils and extracts determined by gas chromatographymass spectrometry (GCMS). Labeled fields associated with terrigenous, marine, and nonmarine (lacustrine) input are adopted from Moldowan et al. (1985). Figure 9. Ternary diagrams of C27, C28, and C29 sterane and diasterane are highly source specific and support calcareous and shaly Shublik oil family distinctions. Figure 10. Diasteranes/(Dia + regular) C27 steranes versus Ts/(Ts + Tm) plot supports oil-source rock correlation, however it is partly dependent on thermal maturity and depositional environment. Figure 11. Distribution of tricyclic terpanes and hopanes for oil-source rock correlation. Figure 12. Homohopane distributions for six North Slope oils vary between calcareous and shaly oil families. Figure 13. A - Variations in homohopane and gammacerane indices indicate redox and salinity stratification during source-rock deposition. B-D - Representative lithology-related biomarker parameters support subdivision into calcareous and shaly oil families.

31

Figure

Ma SW

NE

. Fm k to

Gubik Fm.

Sa

50

g Fm.

CRETACEOUS

n Canni

Hue Shale

. Fm k o r

100

BROOKIAN

irk

n va a g

To

GRZ pebble shale unit LCU

JURASSIC

144

Kingak Shale

BEAUFORTIAN

CENOZOIC

2

Sag River Ss.

208 208

TRIASSIC

Shublik Fm. Eileen Ss.

PERM

Sadlerochit Group

Ivishak Ss.

ELLESMERIAN

245 286

PENN

Lisburne Group

320

roup

MISS

tt G ndico

E

Nonmarine Marine shelf

Fig. 1.

. . .. .. . . . . . . . . . . . . . .. . . . .. . . .

. . .. .. . . . . . . . . . . . . . .. . . . .. . . . . . .

Carbonates Metasedimentary

Marine slope & basin

Granite

Condensed marine shale

Hiatus or erosion

FRANKLINEAN

PRE-MISS

360

Figure

-153oW

-152oW

-151oW

-150oW

-149oW

-148oW

71o00’N

Ba

rro wA rch

D1

-147oW

Alaska

Beaufort Sea

M1

PH01-09 N1

SP1a,b 70o30’N

NS13 F5a

KC4

207 208

CO1

National Petroleum Reserve in Alaska

Prudhoe Bay Unit Kuparuk River Unit

0

N

Fig. 2.

20 km

MB13b

AL02-3

Rock extracts

Shaly Shublik

Oil samples

Calcareous Shublik

Published oil data

70o00’N

Figure C23

Calcareous Shublik oil sample (KC4)

m/z 191

Hopanes m/z 191

R

R C24 C20

H31

Tm

C21 C25

C22

C19

TET

Relative abundance

Tricyclic terpanes

C30 H

C29Tm

C26

I.S.

C28

C29

C29Ts

C30

Ts

C30*

Tricyclic terpanes

H33

H34

H35

C30 H

C23

Shaly Shublik oil sample (NS13)

C24 Relative abundance

H32 G

I.S.

C21 C26

TsT

m

TET

C22

C29Tm C29Ts C30*

Time direction Shaly Shublik m/z 191

C23 C24

C21 C22

Calcareous Shublik C30 H

m/z 191

C23

Oil sample SP1a

I.S.

C29 Tm

C21

C22

C29 TmC30 H Oil sample M1

C24

Oil sample N1

Oil sample F5a

Rock extract PH07

Oil extract PH04

Rock extract 207

Rock extract PH09

Rock extract 208

Rock extract PH08

Rock extract PH01

Postmature Shublik I.S. Rock extract 13AL31

Oil samples CO1

I.S.

Fig. 3.

Figure

A

M1 KC4 PH04 F5a PH09 PH08 PH01

B PC2 Hue-HRZ

Calcareous Shublik D1*

Calcareous Shublik

PH04

M1

PH09

KC4 PH01

MB13b*

PC1

PH08 F5a

Kingak Pebble shale Canning

PC3

MB13b* PH07 N1

D1* SP1a NS13 N1 PH07 208 207

207 208

SP1a

Shaly Shublik

NS13

Shaly Shublik

SP1a

D

NS13 N1

Hue-HRZ

PC2

PC3

KC4

PH04

Kingak

Shaly Shublik

PC1

M1

Pebble shale

F5a

Calcareous Shublik

Canning

207 PH09

PH07

PH01

Cluster distance

C M1 KC4 PH04 PH01 PH09 F5a N1 SP1a NS13 208 207 PH08 PH07

PH08

Legend - Oils (calcareous) - Phoenix-1 extracts (calcareous) - Phoenix-1 extract (shaly) - Oils (shaly) - Prudhoe Bay extracts - Data from Wang et al. (2014)

Cluster distance

Fig. 4.

208

Figure

1- + 2- Methyladamantanes (ppm)

A 200

PH09

ing Crack 160

120

KC4

PH08

N13

e

e-dep Sourc

MB13b*

SP1a

PH01 PH07

80

M1

40

207 208

0

Evaporation due to storage

Example error bars

PH04 0

5

CO1 Oils (calcareous) Phoenix-1 extracts (calcareous) Phoenix-1 extract (shaly) Oils (shaly) Prudhoe Bay extracts

F5a

D*

N1

ine

l trend t n e nd

10

15

20

25

30

35

3- + 4- Methyldiamantanes (ppm) B

250 200 150 PH04

100 50

207 208

0 0

Shaly Shublik baseline C0 = 4. 5 ppm

Biomarkers (ppm)

300

N1 N13

Low maturity No cracking PH08

D* SP1a

5

PH01 Low maturity mixed with cracked oil/gas

Maturity

C29 ααα 20R Stigmastane

350

Calcareous Shublik baseline C0 = 7.4 ppm

Example error bars

High maturity with different degree of cracking (0 - 80%; Table 5) MB13b* F5a 10

M1

PH07

Cracking

KC4 15

20

25

30

3- + 4- Methyldiamantanes (ppm) Fig. 5.

PH09

CO1 35

Tetramantanes

Pentamantanes

Triamantane

used for normalization

Figure

Relative Concentration, Log scale

1

T1

T2

T3

P1

P2

P3

P4

CHXT

Clay <1% Carbonate = 97.8%

0.1 03

AL

3b

1 N1 MB

0.01

AL Shaly Shublik oils Shaly Shublik rock extract Calcareous Shublik oils Calcareous Shublik rock extract Example error bar

0.001

Fig. 6.

02 SP1b

Clay = 7.7% Carbonate = 58.1%

D1 M1 F5a CO1 SP1a KC4 NS13

Figure

Carbon Isotope Ratio, δ13C ‰

-20

1,2,5,7-Tetramethyl

1,3,4-Trimethyl (trans)

1,3,4-Trimethyl (cis)

1,2-Dimethyl

1,3,6-Trimethyl

1,4-Dimethyl (trans)

Adamantanes 1,4-Dimethyl (cis)

2-Methyl

1,3,5-Trimethyl

1,3-Dimethyl

1-Methyl

Adamantane

R

KC4

-21 -22 -23 -24 -25

CO1 AL02 NS13 AL03 D1*

KC4

-26

AL03 CO1 AL02 NS13

-27 -28 Shaly Shublik oils Shaly Shublik rock extract Calcareous Shublik oils Calcareous Shublik rock extract

-29 -30 -31

Example error bar

Fig. 7.

D1*

Figure

C28 0.9

0.1

0.8

0.2

0.7

0.3

0.6

0.4

Marine Shale

C28 = 0.5 C28 + C29

0.5 0.4 0.3

Nonmarine 0.6 Shale

Marine Carbonate

0.7

0.2

0.8

0.1

C27

0.9

Marine > 350 Ma 0.9

0.8

0.7

0.6

0.5

- Oils (calcareous) - Phoenix-1 extracts (calcareous) - Phoenix-1 extract (shaly) - Oils (shaly) - Prudhoe Bay extracts

0.4

0.3

0.1

C29

0.6

0.4

0.3

PH09 KC4 M1

0.5

Fig. 8.

0.2

F5a PH01 PH08

CO1 PH04 0.4

0.7

Figure

Steranes

Diasteranes

X

X

C28 0.9

C28 0.1

0.8

0.9 0.2

0.7

X = H, CH3, C2H5

0.8 0.3

0.6

0.6

0.4

0.6

0.2 0.1

0.5

0.4

0.3

0.2

0.1

0.7

0.2 0.9

0.6

0.6

0.3 0.8

0.7

0.8

0.1

C29 C27

0.9

0.9

0.8

0.7

0.6

0.4

0.5

0.4 0.7

0.8

0.4

0.5

0.3

0.9

0.3

0.6

0.5

0.4

0.2

0.7

X = H, CH3, C2H5

0.5

C27

0.1

0.6

0.5

0.4

0.3

0.2

0.6

0.4

PH09 PH08 0.3

N1 NS13

0.4

SP1a PH07

0.7

0.3

N1 NS13 SP1a

0.3

0.5

- Oils (calcareous) - Phoenix-1 extracts (calcareous) - Phoenix-1 extract (shaly) - Oils (shaly) - Prudhoe Bay extracts

Fig. 9.

PH09

0.7 PH07

0.4

0.1

C29

Figure

1

0.9

Ts/(Ts+Tm)

0.8

- Oils (calcareous) - Phoenix-1 extracts (calcareous) - Phoenix-1 extract (shaly) - Oils (shaly) - Prudhoe Bay extracts

Anoxic Shale 207

0.7 0.6 0.5

Anoxic Carbonate

0.4

PH01

ity tur a M

208

N1

pH Effect

NS13 SP1a Eh Effect

0.3

PH08 PH09

F5a KC4

PH04

PH07

M1 0.3

0.4

Diasteranes/(Dia + regular) C27 steranes

Fig. 10.

Suboxic Strata 0.5

C24/C23tricyclic terpanes

Figure

1.2

PH07

Shaly Shublik

1.0

0.8

- Oils (calcareous) - Phoenix-1 extracts (calcareous) - Phoenix-1 extract (shaly) - Oils (shaly) - Prudhoe Bay extracts

207 208

0.6

SP1a

N1

NS13 PH08 CO1

0.2

Fig. 11.

F5a

KC4 M1

Calcareous Shublik

PH01

0.4

PH09

0.3

C29/(C29 + C30) hopanes

PH04

0.4

Figure

40

% of Total C31 to C35

36 32 28

Calcareous Shublik oils Shaly Shublik oils M1 F5a KC4 N1 N13 SP1a

24 20

SP1a N13 KC4 M1 F5a N1

16 12 C31

Fig. 12.

C32

C33

C34

Homohopanes (22S + SSR)

C35

Figure

A

SP1a

Homohopane Index

0.084

Shaly Shublik

0.08 0.076

N13

0.072

KC4

0.068

Calcareous Shublik

0.064

N1 F5a

0.056 0.025

0.03

B C24/C23 tricyclic terpanes

1.0

0.035

0.04

0.045

- Shaly Shublik oils

Shaly Shublik

0.8

N1

0.6

0.4

F5a KC4

Calcareous Shublik 0.4

C24 tetra- /C26tricyclic terpanes

C 1.0

M1

0.5

0.6

0.7

C22/C21 tricyclic terpanes

0.8

M1

0.9

Calcareous Shublik

F5a

0.8

KC4

0.6 N1

Shaly Shublik

0.4

0.04

D

NS13

SP1a

0.2

Diasteranes/(dia + regular) steranes

0.055

- Calcareous Shublik oils

SP1a NS13

0.05

Gammacerane Index

0.2

0.08

0.12

Diahopane index

0.16

0.2

1.0 NS13 SP1a 0.8

Shaly Shublik N1

0.6 F5a

Calcareous Shublik

0.4

KC4 M1

0.2 0.24

Fig. 13.

M1

Mixed

0.06

0.28

0.32

0.36

C29/(C29 + C30) hopanes

0.4

0.44

Highlights 

Biomarker-based oil-source rock correlation confirms the presence of two geneticallydistinct Shublik organofacies and related oil families.



Both groups were deposited under a similar redox condition (anoxic to suboxic) with dominantly marine algal input but in either 1) a clay-rich or 2) a clay-poor depositional setting.



Chemometric evaluation of multivariate biomarker data reveals mixtures with variable degrees of mixing between end members.



Analysis of diamondoids confirms mixed oil types and establishes diamondoid signatures of source rock end-members.

32