Comparison of the geochemistry of lacustrine oil shales of Mississippian age from Nova Scotia and New Brunswick, Canada

Journal Pre-proof Comparison of the geochemistry of lacustrine oil shales of Mississippian age from Nova Scotia and New Brunswick, Canada

F. Goodarzi PII:

S0166-5162(19)31114-0

DOI:

https://doi.org/10.1016/j.coal.2020.103398

Reference:

COGEL 103398

To appear in:

International Journal of Coal Geology

Received date:

21 November 2019

Revised date:

12 January 2020

Accepted date:

14 January 2020

Please cite this article as: F. Goodarzi, Comparison of the geochemistry of lacustrine oil shales of Mississippian age from Nova Scotia and New Brunswick, Canada, International Journal of Coal Geology(2020), https://doi.org/10.1016/j.coal.2020.103398

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© 2020 Published by Elsevier.

Journal Pre-proof Comparison of the geochemistry of lacustrine oil shales of Mississippian age from Nova Scotia and New Brunswick, Canada. F. Goodarzi FG & Partners Ltd., Environmental and Energy Research Group, 219 Hawkside Mews NW, Calgary, AB, Canada, T3G 3J4. [email protected]

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ABSTRACT The bulk elemental concentration of selected Albert Formation oil shale deposits of Mississippian age from New Brunswick was analyzed using ICP-MS and Prompt Gamma. Results compared to that of the Big Marsh oil shale of similar age from Nova Scotia. Reflected white and fluorescence light was used to determine the characteristic organic matter, and RockEval analyses were used to determine the hydrocarbon potential of oil shale.

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Both Albert and Big Marsh oil shales were deposited in lacustrine environments, based on geological and sedimentological evidence. The Big Marsh oil shale has low and stable B content (28-54ppm), which stays almost constant and with the range for freshwater with depth. By contrast, the oil shales from the Albert Formation from New Brunswick have high and variable B content with depth (B: 97-337ppm), owning to variation in water chemistry and perhaps higher discharge and recharge for Albert oil shale. The Big Marsh deposit, in contrast, had stable discharge and recharge with higher aluminosilicate input and limited or no carbonate content.

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The rate of sedimentation, as determined by Na/K and Th/K ratios indicates that the Albert oil shales deposited at a slower rate as compared to the Big Marsh oil shales. The lower Th/U ratio for Albert oil shale as compared to the Big Marsh is likely due to lower input of weathered and recycled sedimentary terrestrial flux, and allochthonous U content, into the lacustrine setting during their deposition.

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Albert oil shales deposited in oxic-dysoxic conditions based on their Cr and V/Cr ratio, suggesting a well-oxygenated and uniform, warm temperature upper water level. Variation of Ca/Sr versus Ca/Mn ratios for the Albert oil shale, indicates low Mn/Ca and relatively high Sr/Ca ratio for most of the samples, due to low terrigenous influx and warmer water, which is supported by the mineralogy of the oil shales, which contain low quartz and clay minerals. The presence of higher authigenic U and Mn/Ca ratio for Albert oil shale indicates low terrestrial flux and, therefore Th as compared to Big Marsh oil shales. The Rare Earth element (REEs) content is higher for the Big Marsh oil shales owning to a higher input of aluminosilicate than the Albert oil shale as supported by variation of Y and La and that of Hydrogen index (HI) and Heavy Rare earth (HREEs). The Albert oil shale displays a positive Eu anomaly, typical of a high carbonate environment. By contrast, Big Marsh, which shows a negative Eu anomaly, which is typical of upper continental crust. Keywords: Oil shale; petrology; geochemistry; hydrocarbons; New Brunswick; Nova Scotia, Canada

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1. Introduction Canada has vast oil shale resources consisting of various oil shale types deposited in terrestriallacustrine and marine environments. Oil shale generally defined as an organic-rich, fine-grained sedimentary rock that yields substantial amounts of oil and combustible gas upon destructive distillation (Yen and Chilingar, 1976). Most of the organic matter in oil shale is insoluble in ordinary organic solvents and must be decomposed by heating to release hydrocarbon. Oil shale, in comparison to coal, has lower organic matter content and significant amounts of mineral matter (60–90 wt%) content. However, the organic matter in oil shale has higher hydrogen and lower oxygen content than that of lignite and bituminous coal.

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This paper discusses the organic petrology, geochemistry, and hydrocarbon potential of lacustrine Albert oil shales of Tournaisian age from New Brunswick, Canada. It compares to freshwater oil shale from the Big Marsh oil shale deposit of Nova Scotia.

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1.1.Boron as an indicator of the environment of deposition The concentration of boron in coal also has been used to estimate the paleosalinity of the depositional environment (Swaine, 1971; Bohor and Gluskoter, 1973). Bohor and Gluskoter (1973) noted that Illinois coals with less than 125-ppm boron deposited in freshwater environments. The coal layer at the base of the oil shale deposit in Emma Fiord, Devon Island, Arctic Canada has a boron content of 66 ppm (Goodarzi et al., 1987), which indicates a freshwater environment (Swaine 1971; Goodarzi, 1987 and 1995; Goodarzi and van der Flier Keller, 1988, 1989; Goodarzi and Swaine, 1994).

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Boron has been used to determine the environment of deposition of organic-rich deposits such as coal and oil shale (Goodarzi 1987, Goodarzi and Swaine 1994). Organic-rich sediment has been classified based on B content as freshwater-influenced organic-rich deposits, with up to 50 ppm B; mildly brackish-influenced organic-rich deposits, with 50-110 ppm B; and brackishinfluenced organic-rich deposits, with > 120 ppm B.

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The B content of organic-rich deposits is often related to the nature of the sedimentological setting of organic-rich deposits (primary enrichment, Goodarzi, 1995; Goodarzi and Swaine, 1994). If, however, the concentration of B in organic-rich deposits with a known freshwater environment of deposition (based on sedimentology, palynology, and paleontology) is high, then the activity of groundwater and the possibility of transportation of B from other sources such as country rocks should be examined (Beaton and Goodarzi, 1990; Goodarzi and Swaine, 1994). This enrichment of B in many cases is due to groundwater activity. (Goodarzi and Swaine, 1994). An elevated concentration of boron in coal/shale, however, may also be derived from hydrothermal fluids (Lyons et al., 1989), volcanic activity (Bouska and Pesek, 1983; Karayigit et al., 2000), and climatic variations (Bouska and Pesek, 1983). 2. Geological Setting The Late Carboniferous-Devonian Maritimes Basin formed as a significant depocentre during the Acadian Orogeny (Smith and Naylor, 1990). The large basin comprised of various smaller, northeast-trending, rift basins. Apart from the Albert oil shale deposits in the Moncton Subbasin,

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two large oil shale deposits found in the Stellarton Formation (Stellarton Basin, in Pictou coalfield) and the Big Marsh Member of the Rights River Formation (South Lake Creek Formation), in the Antigonish Basin) (Fig.1).

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Fig. 1. The Maritimes Basin of Atlantic Canada, (a) New Brunswick (Moncton Basin) and (b) Nova Scotia (Big Marsh deposit in the Antigonish Basin)(Hibbard et al., 2006). 2.1. Big Marsh Oil shale

The Horton Group in the Antigonish Basin (Fig. 1) includes some of the oldest sediments deposited in the Maritimes Basin, which are of the alluvial fan, lacustrine and coal swamp origin (Murray, 1960; Boehner et al., 1986; Martel and Gibling, 1987, Hamblin, 1989). The formation of interest regarding the highest oil shale potential is the Tournaisian-aged Rights River Formation. The Wilkie Brook Formation unconformably overlies it, which in turn is overlain by the evaporites and clastics of the Windsor Formation (Fig. 2) (Macauley and Bell, 1984). The Rights River Formation includes a red conglomerate interbedded with mudstones, sandstones, and oil shale and coal beds. The oil shale deposits occur in two major zones, Beaver settlement (average thickness 61.6 m) and Big Marsh (average thickness 117.5 m). The two lithologies associated with the oil shale, in order of abundance, are a) fissile, carbonaceous with abundant fish remains and low hydrocarbon content, b) massive, pyro-bituminous, and high hydrocarbon yield. The latter is the equivalent of the Albert Formation, an economically important formation in the Moncton Subbasin of New Brunswick (Macauley et al., 1984). The oil shale deposits in

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Moncton Subbasin are clay-rich, and some laterally pass into peat swamp, carbonaceous mudstone, and coal, such as those of in the Stellarton basin, indicating a stable lake shoreline and relative stability during the deposition of oil shale, and a balance in water discharge to the recharge, which indicates that the lake was open hydrologically with low ionic concentration, and no deposition of chemical sediment (Smith et al., 1991).

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Fig. 2. Stratigraphy of the (a) Albert Mines area in the Moncton Sub-basin and (b) Big Marsh area in the Antigonish Basin, compiled from Smith and Naylor (1990), Utting and Hamblin (1991), and Keighley (2008).

2.2. Albert oil shale The Late Devonian to Tournaisian Horton Group (Fig.1) comprises a 3 to 5 km thick succession within the Moncton Subbasin and is a fault-bounded asymmetric basin (Smith et al., 1991; St. Peter, 1993; Keighley, 2008). The interfingering of alluvial fan, coastal and lacustrine deposits within the Albert Formation reflects syn-sedimentary faulting along the basin margins with an input of coarse-grained, texturally immature sediments from a hinterland Pre-Carboniferous basement composed of granite, pyroclastics and metamorphosed sediments. Compression in late Tournaisian and subsequently in the Namurian resulted in the inversion of the basin with uplift, faulting, folding, and erosion of the Horton Group (St. Peter, 1993; Lynch, 1999). Tectonic activity during Late Devonian to Early Carboniferous time controlled the formation of the Moncton Subbasin, and the presence of active faults between the Caledonia Uplift and the subbasin is evident during Albert deposition (Smith et al., 1991). The tectonic influence on the Albert Formation is evident by presence of oil shale along the southeast margin of the subbasin at several stratigraphic levels in close association with alluvial fan conglomerates, which were

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deposited due to rapid subsidence of the south side and development of substantial relief in the basin margin and deeper lake conditions in an asymmetrical lake (Smith et al., 1991). The lakes may have been chemically stratified anoxic at depth and oxic on the surface and slightly saline with alkaline water. The presence of fish skeletons indicates a very reducing condition that prevented scavengers (Smith, 1985).

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Fig 3. Map showing oil shale and Albert Formation distribution around the study area (modified after Macauley et al., 1985). Note the location of boreholes marked with red stars.

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3. Analytical Procedure A total of 29 samples of Albert oil shale were collected from the core depositories in Nova Scotia and New Brunswick by Stereotypic Reservoir Consulting, Calgary in 2015, and, based on previous systematic sampling by exploration companies reports, such as Lynch (1999). Sampling primarily focused on oil shale beds with coarser-grained clastic and carbonate interbeds omitted, similar to sample procedures described by Macauley et al. (1985). Samples were collected from the centers of cores to avoid contamination. The locations of boreholes are in Big Marsh, Nova Scotia, and the different oil shale deposits in New Brunswick in this study shown in Figs. 3 and 4 and Table 1. Four samples also collected from surface exposures in the Albert Mines area (Table 1). 3.1. Optical microscopy Organic petrology, including fluorescence microscopy [spectral parameters: λ max, Green (GQ), Red/Green (R/GQ) and Blue/Green (B/GQ) quotients], were carried out on selected whole-rock polished samples that prepared according to ISO 7404-2 (2009). A Zeiss Axio Imager A2m

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reflected light microscope system used for reflectance measurements based on ISO 7404-5 (2009) and ASTM D7708-14 (2014).

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Albert Mines Pit 1 Albert Mines Pit 1 Albert Mines Pit 2 Albert Mines Pit 2

Location (NAD 83 UTM 20N) Easting Northing Surface Samples 2 samples 368599.4422 5082242.316 2 samples 368599.4422 5082242.316 2 samples 368614.7279 5082267.557 2 samples 368614.7279 5082267.557 Samples

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Figure 4. Locality map of surface exposures and wells in the Big Marsh area, Nova Scotia (modified from Macauley et al., 1985). The location of the Big Marsh 4 cored well is shown.

Taylor Village #2 Boudreau #1 Albert Mines ARCO Urney #1 Mapleton N #11

Core Samples 5 samples 5 samples 4 samples 5 samples 2 samples

Big Marsh BM #4

13 samples

379167.1367 376536.5701 368580.0183 317470.0185 341799.4361

5088840.318 5086545.858 5081934.998 5065768.309 5079110.213

583633

5072596

Table 1.Location of samples used in this study. The microscope equipped with white (halogen) and ultra-violet (HBO light sources. Random reflectance (%Ror) measurements were taken using an Epiplan-Neofluar oil immersion objective (50X magnification). All Ror measurements made on scarce vitrinite particles present in the oil

Journal Pre-proof shale sample. Fluorescence microscopy of organic matter was carried out using ultraviolet G 365 nm excitation with a 420 nm barrier filter. The Red/Green quotient (Q = relative intensity at 650 nm/relative intensity at 500 nm) of liptinite macerals determined under standard conditions (filters: excitation 450-490, beam splitter 510, barrier 520 nm).

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3.3. Rock-Eval Pyrolysis/TOC analysis A Rock-Eval 6 ® (Vinci Technologies, France) instrument (Lafargue et al., 1998) was used to determine total organic carbon (TOC, wt%), Tmax (°C) and the amount of hydrocarbon released (mg HC/g Rock) as measured under the S1 and S2 peaks. Care was taken not to saturate the FID detector. The detector has a limit set by the manufacturer, which, for Rock-Eval 6 is 125 mV (or S2>33 mg HC/g rock) (Behar et al., 2001). Similarly, samples with an FID response lower than 0.1 mV (or S2 < 0.3–0.5 mg HC/g rock) are considered to fall below the reliable linearity range for the FID. In the case of the Albert oil shales, when the pyrograms showed that the FID was saturated, the samples were re-analyzed using half the normal sample weight (e.g., 30 mg instead of the standard 60 mg used in Rock-Eval 6 analysis). The S2 kept to <33 mg HC/g rock in all cases. The amount of CO and CO2 released during pyrolysis, and then oxidation was measured to quantify the portion of oxygen-containing organic matter (S3 peak; mg CO2/g Rock) and refractory inert carbon (residual carbon; RC wt.%), respectively.

4. Results

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3.4.Elemental analyses ICP-MS was conducted on 27 samples at Acme Labs in Vancouver, Canada. Details of the ICPMS analysis: rock samples digested in HNO3, HClO4, and HF, dried, and dissolved in HCl. Concentrations of Al, Ti, Fe, Na, Mg, K, Ca, S, and P determined via mass spectrometry. Accuracy and precision of ICP- MS values were determined by use of the reference standard OREAS 45e, prepared from a lateritic soil from Western Australia, as well as duplicate analysis of random samples. ICP-MS parameters have an accuracy and precision which deviate by less than 5% from the reference standard values, except accuracy values for Ti, which deviate by less than 8%. Duplicate sample precision values show less than 5% error for most samples. For the investigation of REEs origin (REE, rare earth element), REE distribution patterns were obtained by concentration-normalized to the Post Archean Australian shale (PAAS) (Taylor and McLennan, 1985).

4.1.Petrology Organic matter in Albert oil shale consists mostly of the amorphous remains of filamentous algae and bacteria (Goodarzi etal, 2019a) that were deposited sub aqueously and formed regular layering (Fig. 5). The petrological composition of the Big Marsh oil shale depends on the distance of oil shale from the coast (Goodarzi et al., 2019b). The oil shale contains mostly of terrestrial organic matter such as sporinite and inertinite and filamentous algae in the coastal area, the filamentous algae, and amorphous bituminous matrix in the shallow zone and Botryocucous algae in the deep central zone (Fig. 6).

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Fig 5. Variation of the petrology of Albert oil shale from east to west (please see Figure 2 for the location of oil shale). The filamentous algae are immature and fluorescing greenish-yellow in Taylor village, and their maturity increase towards the west and becomes mature and fluorescing yellowish-orange in the Arco-Urney location (Fig.3).

Fig 6. Organic matter in three types of oil shales in the Big Marsh, Nova Scotia consists of (a) mostly terrestrial kerogen such as vitrinite, inertinite, and sporinite in the coastal area, (b) a mixture of terrestrial such sporinite and inertinite in shallow zone , and (c ) Botryococcus algae in deep zone. Fluorescence light and oil immersion. 4.2. Elemental Variation of the elemental composition of the oil shale samples is presented as a grouping of elements (Swaine, 1990), such as; major elements, elements of environmental concern, other elements, and rare earths (Tables 3-6). The boron content of the Albert oil shale is variable, but mostly high (97-337 ppm), indicating unstable water chemistry and higher salinity as compared with a freshwater lake, such as Big

Journal Pre-proof Marsh oil shale which has a low and stable B (28-54ppm), typical of a freshwater lake (Goodarzi, etal. 2019b), (Table 3, Fig. 7a). Variation of B and Ce, clearly divides the two oil shale deposits into Albert oil shale with high B and low Ce and Big Marsh, with Low B and high Ce (Fig. 7b), indicating a higher input of terrestrial flux that includes high REEs into a lacustrine setting. Boron (ppm) and Ca (wt%) have a similar trend of concentration with depth in the Albert oil shale (Fig. 8). In general, the concentration of Ca and Mg in the Albert oil shales is higher than in the Big Marsh oil shale (Fig.8b). Carbonate particles in the Albert oil shale described and classified (Figs 9-10) and their relation to the migrated bitumen into oil shale discussed (Goodarzi etal. 2019a).

Ca

Fe

K

Mg

Na

P

S

Ti

6.22 5.45 4.9 7.02 4.9

1.16 2.02 1.91 7.56 0.27

2.27 2.27 2.03 5.16 2.4

1.82 1.43 1.38 1.86 2.14

1.09 1.22 1.06 4.09 0.88

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1.32 1.515 1.417 0.489 1.286

0.051 0.273 0.283 0.037 0.042

0.43 1.36 0.71 0.34 0.43

0.363 0.279 0.263 0.27 0.421

5.39 5.43 7.51 5.98

3.48 9.7 1.16 4.19

2.7 2.76 2.82 3.65

1.64 1.28 2.06 2.15

0.77 0.81 1.07 2.36

0.647 0.898 0.685 0.514

0.05 0.081 0.072 0.021

0.06 0.22 0.15 0.18

0.329 0.247 0.393 0.259

6.06 5.58 5.05 7.46

5.95 5.34 3.53 3.77

3.01 3.14 3.23 3.37

2.32 1.44 1.54 1.98

2.24 1.7 1.79 2.79

0.737 2.206 3.325 1.569

0.05 1.492 0.053 0.05

0.12 0.31 0.6 0.73

0.314 0.278 0.314 0.395

12.17 2.32 5.36 4.43 0.33

4.08 3.18 4.64 3.61 4.38

1.47 2.3 1.8 1.37 2.46

4.16 1.02 2.01 2.09 1.19

0.312 0.993 0.668 0.981 1.032

0.046 0.062 0.048 0.619 0.04

3.07 0.16 0.43 0.73 0.7

0.191 0.417 0.34 0.29 0.343

5.85 5.73 5.29 5.57 5.43

2.16 4.08 4.34 4.14 2.86

2.87 3.97 5.13 3.94 4.21

1.54 2.36 1.98 2.26 2.52

0.8 1.1 2 1.08 1.49

4.289 1.268 0.873 1.194 0.911

0.046 0.048 0.035 0.05 0.039

0.99 0.53 0.23 0.42 0.34

0.321 0.294 0.248 0.314 0.306

5.8 8.24

3.69 1.72

3.44 4.51

2.4 3.1

1.39 1.52

2.499 0.967

0.049 0.061

0.06 0.04

0.354 0.355

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5.37 7.87 5.98 5.44 5.77

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Location Taylor Village TV-2-69 TV-2-88.8 TV-2-91 TV-2-104 TV-2-114.2 Albert Mine (AM) AM-1 AM-Pit 2 AM-2 AM-3 Albert Mine (AM-15A) AM-15A-342 AM-15A-345 AM-15A-659 AM-15A-745 Boudreau BOUD-1-111 BOUD-1-116 BOUD-1-123 BOUD-1-130 BOUD-1-141 Urney-Arco ARCO-1-325 ARCO-1-466 ARCO-1-548 ARCO-1-628 ARCO-1-708 Mapleton N-11 N-11-08-648 N-11-08-765

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The influence of migrated bitumen on the elemental composition of oil shales is examined using relations between HI a with U and Mo (Figs 11, 12)

Table 2. The concentration of major elements (wt%) in Albert oil shales and Mapleton shale for the location of boreholes, see figure 3. The Th/K and Na/K ratios used to determine the rate of deposition of Albert and Big Marsh oil shales (Fig.13)

Journal Pre-proof The ratio of V/Cr, Ni+V, and Cr/U with Cr (ppm) is used to show the differences between two oil shales, and to determine redox condition for the Albert oil shales as compared to the Big Marsh oil shales (Figs. 14, 15a-b).

As

Cd

Co

Cr

Cu

Mn

Mo

162 258 224 181 337

32.9 60.5 54.9 10.2 70.5

0.21 0.42 0.35 0.1 0.43

22.4 20.2 19.2 12.5 22.8

60 35 46 47 61

45.11 78.52 137 73.92 62.94

449 258 270 1323 157

17.95 49.96 54.06 2.87 34.27

164 107 173 123

99 13.1 116.5 35.6

0.19 0.19 0.12 0.21

12.1 12.2 11.6 14.6

54 38 66 44

44.05 37.2 82.08 39.47

194 930 248 608

6.71 2.92 8.89 9.29

95 72 36 131

16.3 68.9 53 14.5

0.19 15.2 0.35 16.4 0.29 14.1 0.2 18.8

48.88 60.91 62.12 83.55

764 5.97 32.5 16.34 <0.2 1019 676 19.61 36.8 26 0.9 1428 670 60.45 27 20.45 1.2 513 501 11.08 33.8 18.54 14.7 577

97 173 156 111 158

158 6.2 14.4 43.7 124.7

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43 47 42 57

0.15 10.4 14 13.9 23.5

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124.7 0.13 0.2 0.14 0.15

Ni

Pb

Se

Sr

Th

U

V

45.8 49.6 56.8 25 45.2

26.31 30.13 34.41 15.67 22.85

0.8 1.3 1.7 0.3 0.2

175 220 248 369 131

5.2 5.3 8.5 8.4 3.1

6.6 6.7 8.4 2.3 3

99 95 97 88 132

39 18.22 21.7 8.78 35.5 25.79 40.6 15.57

0.4 0.5 0.8 0.5

144 425 116 499

4.1 7.3 10.8 4.9

1.5 4 3.2 1.6

137 82 134 84

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Location Taylor Village TV-2-69 TV-2-88.8 TV-2-91 TV-2-104 TV-2-114.2 Albert Mine (AM) AM-1 AM-Pit 2 AM-2 AM-3 Albert Mine (AM-15A) AM-15A-342 AM-15A-345 AM-15A-659 AM-15A-745 Boudreau BOUD-1-111 BOUD-1-116 BOUD-1-123 BOUD-1-130 BOUD-1-141 Urney-Arco ARCO-1-325 ARCO-1-466 ARCO-1-548 ARCO-1-628 ARCO-1-708 Mapleton N-11 N-11-08-648 N-11-08-765

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Variation of Sr/Ca and Mn/Ca ratios, Mn/Ca, and Al used in estimating the temperature of the water and terrigenous input (Fig. 16). The concentration of REEs decreases from the Big Marsh to the Mapleton shale and is the lowest for the Albert oil shales. Variation of total LREES, HREEs, and their ratio also follow similar trends to that of (Fig. 18). The differences between Albert and Big Marsh oil shales become evident, in the variation of Y and La; HI and HREEs(Figs. 19, 20). The PAAS normalized REEs shows a positive Eu anomaly for the Albert shales and a negative Eu anomaly for those of the Big Marsh (Figs. 21).

23.5 60 1090 63.86 62 45.02 491 1.07 48 33.01 1253 4.11 39 38.7 900 9.09 60 63.86 195 16.92

7.6 2.7 6.5 4.6 5.7 3.8 7.5 3.8

88 93 92 110

16.92 24.5 31.9 30.9 51

51 77.78 0.7 10.45 0.3 158 15.69 0.5 272 14.98 0.7 423 77.78 0.7 90

4 7.2 6.2 6 4

2.4 3.1 2.8 4.5 2.4

108 111 95 87 108

25.16 24.59 11.81 22.43 26.4

278 282 227 277 211

8.6 4.9 5 6 3.6

3.3 2.6 2.7 2.7 2.3

80 121 106 127 118

287 123

7.7 11.1

2.4 2.8

125 119

38 296 312 276 272

43.7 26.9 6.3 25.5 18.6

0.17 0.17 0.18 0.19 0.22

18.1 18.6 12.7 18.5 22.4

57 74 65 78 86

46.82 39.58 35.43 39.55 49.75

350 871 1838 874 833

7.43 6.58 1.73 6.01 4.89

47.4 57.1 43.4 54.7 64.2

1.4 0.5 0.3 0.2 0.3

81 171

4.6 6.5

0.2 0.14

18.3 19.3

72 99

42.81 654 119.7 629

3.9 0.62

43 8.95 <0.2 61.8 11.57 <0.2

Table 3. The concentration of elements of environmental concern (ppm) in Albert oil shales and Mapleton shale for the location of boreholes, see figure 3.

5. Discussion 5.1.Organic petrology

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Big Marsh oil shale contains terrestrial organic matter (Goodarzi etal, 2019b) (Fig. 5). By contrast, the Albert oil shale contains mostly the amorphous remains of filamentous algae and bacteria that form regular layering and sub-aqueously deposited (Fig. 6c and e). The regular layering of algal remains in the Albert oil shale is found wrapped around carbonate particles, suggesting syngenetic deposition of carbonate particles and organic matter in a generally low energy depositional environment, which resulted in the stratification of organic matter (Goodarzi etal., 2019a). Albert oil shale was deposited in a freshwater lacustrine environment, also based on the presences of freshwater "nektonic biota" such as; palaeoniscoid fish, abundant algal remains, fine-grained sediment with thin lamination, continuity and regular thickness of some units, (Greiner, 1977; Picard and High, 1972; Pickerill and Carter, 1980; St. Peter, 1982; Pickerill et al., 1985; Smith, 1985, Smith et al., 1991, Goodarzi et al., 2019a).

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5.2.Environment of deposition Both the Nova Scotia and New Brunswick oil shales were deposited in a lacustrine environment based on geological setting, flora, and fauna (Smith et al., 1991; St. Peter, 1993). However, unlike the Big Marsh oil shales, which is a typical freshwater lacustrine (B:< 50ppm), with stable depositional environment with a regular rate of discharge to recharge (Goodarzi, 2019a). The Albert oil shale from New Brunswick has variable B content (97-337 ppm) (Figs 7a), possibly indicative of a higher rate of discharge to recharge, due to tectonic activity during deposition of the oil shale and chemical stratification (Smith et al., 1991, Goodarzi etal. 2019a), which is supported by the variation of B and Ce , which divides two oil shales into those from Nova Scotia with higher Ce and lower B content (B:28-49 ppm) indicating of influx of terrestrial sediment into a freshwater lake (Fig.7a).

Figure 7a. Variation of boron and cesium for from the Big Marsh and the Albert oil shales, Nova Scotia and New Brunswick.

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By contrast, the Albert oil shales have higher and variable B (72-337ppm) and lower Ce content, indicating lower input of terrestrial flux and variable water chemistry, as shown by higher contents of Mg and Ca than the Big Marsh oil shales (Fig. 7b).

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Figure 7b.Variation of Mg and Ca (%) for oil shales from the Big Marsh deposit and those from New Brunswick. The drill hole is as follows; Albert mine[AM] from the mine site, Albert mine drill hole (Am), Taylor Village (Tv), Boudreau (B), and Arco-Urney (Arc). The depth of each sample is note beside them is in meters. 5.2.1.Variation of boron with depth The boron content of oil shale with depth for the Big Marsh deposit and Albert oil shales shows four patterns: a. The oil shale in the Big Marsh deposit entirely deposited in a freshwater environment. b. The Albert oil shales in the area close to and west of the Albert mine faulted and fractured zones, such as Taylor Village and Boudreau (Figure 3c) influenced by a brackish environment (Table 3, Fig.8). c. The Albert oil shale in the Albert Mines drill hole, has variable B content, possibly indicating that the salinity of the lake water was not consistent through time and changed from slightly brackish, to freshwater and then to a brackish environment with increased depth (Table 3, Fig. 8). d. Interestingly in Arco-Urney boreholes (Fig.3), a distance of 55km from the Albert Mines faulted and fractured zone (Figure 3a), oil shale deposited under brackish water (B: 272-312ppm) between depths of 466m-708m. Then the lake water reverted to its original freshwater setting (B:

Journal Pre-proof 30 ppm) at shallower depths of 325m (Table 3, Fig. 8). This indicates changes in water discharge to recharge and dryer conditions.

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The above observations indicate that the Albert oil shale was deposited under variable lake water conditions and was dependent on: the rate of discharge/recharge, an increased discharge to recharge resulted in high ionic concentrations and carbonate formation and a brackish environment (Allen and Collinson, 1986; Smith et al., 1991, Goodarzi et al., 2019a). Variation of boron (ppm) and calcium (%) in Arco-Urney borehole indicates a change of water chemistry from brackish water with high B and Ca) to freshwater at the top with lower B and carbonate (Fig 8b).

Figure 8a. Variation of boron with depth for Big Marsh deposit, Nova Scotia and oil shales from Bordereau, Taylor Village, Alberta Mine, and Arco –Urney drill holes, New Brunswick.

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Fig 8b. Variation of boron (ppm) and calcium (%) in Arco-Urney borehole. 5.3. Carbonate

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Mineralogical composition of both the Big Marsh and Albert oil shales has been studied extensively and reported in Macauley and Bell (1984) and Smith et al., 1991). The average mineral composition of mineral of both Big Marsh/Albert oil shales is as follows (the first number is mineral content of the Big Marsh and second is that of the Albert oil shales): quartz (53/11 wt%), clay minerals (38/29 wt%), feldspar (5/17 wt%), carbonates (0/16 wt%) and small quantities of siderite, pyrite.

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Carbonates in the Albert oil shales formed due to the precipitation in early diagenesis in an alkaline environment (Smith et al., 1991, Goodarzi etal., 2019a). There are four kinds of carbonate particles found in the Albert oil shales (Fig.9) which are; (a) calcite and dolomite micrite, (b) angular syngenetic carbonate particles that are suspended in organic matrix; those enclosed and wrapped by organic matter and are not disturbed by the diagenetic mineral growth, (c) crystalline carbonate suspended in the matrix bituminite, and (d) sub angular-rounded carbonate particles that contain hydrocarbon (Goodarzi etal, 2019a). The rounded particles with fluid inclusions are epigenetic and were included in oil shale during early digenetic stage due to the tectonic uplift of the southern part of the basin during the early diagenetic stage of oil shale deposition. (Goodarzi et al., 2019a).

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Fig 9. Carbonates in Albert oil shale. (a) Carbonate micrite, (b) angular syngenetic carbonate (c) carbonate crystal in an organic matrix and (d) epigenetic rounded carbonate with hydrocarbon inclusions.

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5.4. Influence of migrated hydrocarbon on the elemental composition of oil shales The oil shales in the Albert Mines area (Fig. 3), are found in contact with migrated bitumen veins and contain carbonate particles (Fig. 10). There is a connection between some of the carbonate particles and oil migration (Goodarzi et al., 2019c).

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The bitumens were likely incorporated into Albert oil shale as a result of hydrocarbon migration during deposition of the oil shales, and both bitumens and carbonate particles included in some of the Albert oil shales and during deposition (Goodarzi etal. 2019a). There is evidence of the contribution of migrated hydrocarbons to the elemental composition of Albert oil shales, particularly in comparison with elements with organic affinities, such as Mo and U (Figs 11- 12). These two elements have higher concentratio ns in samples of oil shales containing migrated bitumen (Figs.11-12). Variation of U with HI, for Albert oil shale indicates that oil shales with migrated bitumen have higher U content (Fig. 11). Thorium is mostly allochthonous, whereas U is mostly authigenic (Luning and Kolonic, 2003). Generally, an anoxic condition produces sediments with high authigenic U and rich source rock (Lunig and Kolonic, 2003; Peters et al., 2005). The details of RockEval analyses for both the Big Marsh and the Albert oil shales reported by Goodarzi etal. (2019 a-b). The variation HI with Mo and U is used to show the influence of the hydrocarbon migration in Albert oil shales (Figs.11-12).

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Ba

Cs

Ga

292 241 241 368 274

3.9 4.5 4.5 8.8 5.5

19.3 15.39 15.39 18.25 21.24

335 296 70 491

4.4 5.3 9.4 2.8

18.59 12.94 20.91 15.39

457 514 306 430

2.3 4.4 2 9.6

17.43 1.66 25 764 7.99 14.47 2.12 116.2 676 7.12 15.29 1.8 126.3 670 7.86 18.85 2.5 144.5 501 11.94

62.1 77.2 48.1 103

65 416 625 270 313

6.7 6.1 3.1 6.2 9.2

12.58 24.16 17.55 14.23 17.54

5.99 11.27 9.94 7.68 8.19

199 376 298 364 337

1.4 5.5 2.3 5.3 4.3

18.95 22.21 18.64 20.94 22.12

2.4 29.1 350 9.5 2.21 103.1 871 9.64 1.92 83.8 1838 7.71 2.46 102.7 874 9.54 2.22 165.4 833 8.87

3.3 7.9

Li

Nb

Rb

Sb

Sc

Sr

2.79 77 2.53 56.3 2.53 56.3 2.72 73.4 3.09 120.5

449 258 258 1323 157

8.77 11.18 11.18 9.51 11.34

47.5 41.6 41.6 108.7 58.5

1.24 1.69 1.69 1.13 1.98

9.5 10.2 10.2 14.9 11.4

175 220 220 369 131

10.9 88.9 18.4 104.6 18.4 104.6 16.4 86.3 6.2 95.6

1.68 1.89 2.59 1.03

194 7.91 28.9 930 5.83 62 248 11.06 128.6 608 7.14 69.8

2.05 0.81 2.48 1.62

8.8 12.2 13.6 8.5

144 425 116 499

7.8 30.6 10.5 7.9

58.8 72.4 88.3 41.1

0.74 2.3 1.48 0.83

9.8 1019 17.2 13.5 1428 19.4 7.1 513 14.5 13.8 577 15.7

55.3 89.6 68.3 87.2

75.2 52.9 38.3 63.9 83

0.91 0.64 1.38 1.64 3.52

10.5 12.7 11.8 11.1 10.2

829 158 272 423 90

9.8 23.2 18.6 19.1 6.7

48.8 95.8 77.3 94.2 67.7

30.9 32 29 33.8 24.4

2.2 2.39 0.67 1.93 1.83

7.3 9.8 10.6 11.5 10

278 282 227 277 211

14 13.2 14.2 14.4 11.9

91.7 81.8 69.8 82.9 78.5

21.51 2.95 151.9 654 11.64 42.1 0.34 23.52 3.12 78.5 629 11.03 112.4 1.32

10.6 16.3

287 123

18.5 101.5 24.4 107

76 35.9 99.2 44.9

1090 491 1253 900 195

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1.29 54 3.04 73.9 2.27 65.5 2.22 83 2.04 204.5

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Location Taylor Village TV-2-69 TV-2-88.8 TV-2-91 TV-2-104 TV-2-114.2 Albert Mine (AM) AM-Pit 1 AM-Pit 1 AM-Pit 2 AM-Pit 2 Albert Mine (AM-15A) AM-15A-342 AM-15A-345 AM-15A-659 AM-15A-745 Boudreau BOUD-1-111 BOUD-1-116 BOUD-1-123 BOUD-1-130 BOUD-1-141 Urney-Arco ARCO-1-325 ARCO-1-466 ARCO-1-548 ARCO-1-628 ARCO-1-708 Mapleton N-11 N-11-08-648 N-11-08-765

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Table 4. The concentration of minor elements (ppm) in Albert oil shales and Mapleton shale, for the location of boreholes, see figure 3. The majority of samples from the Albert oil shale have U content of <4ppm, which is similar to that for the Mapleton shale (Fig. 11). However, samples contaminated with migrated bitumen have higher concentrations of U (Fig 11). Molybdenum will diffuse into sediments during early diagenesis under oxic conditions (Brumsack and Gieskes, 1983). In sedimentary rocks, Mo often has a strong positive correlation with TOC in organic-rich source rock, such as organic-rich mudstones. It is also used for the study of bottom water redox potential (Kremling, 1983; Dean etal. 1999; Wignall, 1994; Brumsack, 1989; Lyons, 2003; Werne etal, 2002). The association of Mo with TOC/ is due to direct coupling of dissolved Mo and marine organic matter (Helz etal. 1996). Variation of HI and Mo for the Albert and Th Big Marsh oil shales is very informative (Fig.12). All samples from the Big Marsh, most of the Albert oil shales and Mapleton shale, have Mo

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content of <10ppm, which indicates that the samples not contaminated by hydrocarbon migration ( (Fig.12). By contrast, there are three groups of the Albert oil shales that have variable Mo content (Fig12). Group 1 has Mo content of 15-25ppm and includes two samples from the Albert Mine drill hole and one sample from Taylor Village drill holes (Table 3). Group 2 consists of a heavily bitumen contaminated oil shale from the Albert mine area and has Mo content of 34ppm (Figs. 12 Table 3). Group 3 has Mo content of 50-65ppm and includes two samples from Taylor Village, one each from the Albert mine and Boudreau drill holes (Table 3, Fig.12), and includes oil shale with bitumen and also particles of carbonate with oil inclusion (Fig 9).

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Figure 10. Migrated bitumen and carbonate associated with the Albert oil shale, Albert mine location. (a) White light and (b) fluorescent light, oil immersion. Arrow indicates the concentration of carbonate associated with hydrocarbon migration (a), the direction of migrated hydrocarbon in the oil shale matrix is shown by arrows through fractures filled with bitumen.

5.4. Rate of sedimentation The Na/K ratio used as an indicator of the rate of sedimentation (Nicholls and Loring 1960; Spears, 1964; Goodarzi, 1987; Goodarzi and Cameron,1987; Goodarzi and Gentzis, 2019). An increase in Na/K ratio is related to the degradation of illite, resulting from the slow accumulation of sediments. Conversely, a reduced Na/K ratio is due to a rapid rate of sedimentation. Thorium is relatively immobile in sediments during weathering and transport (Adams and Weaver, 1958; McLennan and Taylor, 1980; Schmoker, 1981; McLennan et al., 1993; Condie, 1993; Fralick and Kronberg, 1997).

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Fig. 11. Variation of hydrogen index (HI) and uranium for the Albert oil shales and Mapleton shale. The location of the samples shown in Fig. 3. The drill hole is as follows Albert mine (Am), Taylor village (Tv), Boudreau (B), and Albert mine surface sample are AmM. The depth of each sample is noted beside them in meters.

Fig. 12. Variation of Hydrogen index and Mo for Albert oil shales and Mapleton shale. Variation of hydrogen index (HI) and molybdenum for the Albert, the Big Marsh oil shales, and Mapleton shale. The location of the samples shown in Fig. 3. The drill holes are as follows; Albert mine (Am), Taylor village (Tv), Boudreau (B), and Albert mine surface sample is AmM. The depth of each sample is noted beside them in meters.

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Weathering and sedimentary recycling results in the loss of U and increases the Th/U ratio in sedimentary rocks (McLennan et al., 1993). In general higher values of Th/U indicate a higher rate of sedimentation and the allochthonous origin of U. The Th/K ratio is associated with the detrital clay mineral content (Hassan and Hossin, 1975; Herron, 1986). The Th/K values also controlled by transportation mechanisms, topography, source area, climate, and proximity to shore (Hesselbo, 1996). The oil shale from Big Marsh experienced a faster rate of sedimentation as indicated by high Th/K and low Na/K ratios, which is typical of a freshwater lake. By contrast, the rate of sedimentation for Albert oil shale was irregular and slower than the Big Marsh (Fig.15) and samples containing migrated bitumen have the low rate of sedimentation, possibly due to high discharge /recharge of lake during tectonic activity, which resulted in migration and input of bitumen into the lake (Goodarzi etal., 2019a)

Figure 13. Rate of sedimentation of oil shales from Big Marsh, Nova Scotia, and Albert, New Brunswick. Albert mine (Am), Arco-Urney (Arco), and Taylor Village (TV) refer to boreholes (Fig. 3) and samples that contain migrated bitumen. The depth of each sample noted beside them in meters. 5.5. Paleo-redox The ratios of V/Cr, V/Mo, U/Mo, Re/Mo can be used to determine paleo-redox conditions (Rimmer, 2004). Redox sensitive trace elements provide information about the position of the sedimentary redox boundary at the time of deposition. The bottom water oxygen levels in marine settings were evaluated by their elemental composition such as As, Co, Cr, Mo, Ni, Pb, V, and U (Calvert and Pedersen, 1993; Jones and Manning, 1994; Wignall, 1994; Crusius et al., 1996;

Journal Pre-proof Dean et al., 1997, 1999; Morford et al., 2001; Pailler et al., 2002; Kremling 1983; Jacobs et al., 1985; Tribovillard et al., 2006). 14 Big Marsh oil shale Albert oil shale Suboxic-anoxic

12

8

Oxic

2 0 0

20

40

60

80

100

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Cr (ppm)

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Fig 14. Variation of V/Cr ratio with Cr (ppm) for oil shales from Big Marsh deposits, Nova Scotia, and Albert, New Brunswick, Canada.

Fig 15a. Variation of V/Cr ratio with chromium for the Albert and the Big Marsh oil shales. The location of the samples shown in Fig. 3. The drill hole is as follows Albert mine (Am), Taylor Village (Tv), Boudreau (B), and Arco-Urney (Arc). The depth of each sample noted beside them in meters.

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The (V/Cr)/Cr systematic is a good indicator of paleo-redox conditions (Jones and Manning, 1994; Rimmer, 2004; Goodarzi etal 2019b). Variation of Cr to V+Ni as used in the present study indicates that Albert oil shales were mostly deposited in a suboxic (Cr: 10-20 ppm) and few in dysoxic (Cr:> 40) conditions, which is in agreement with high carbonate content and a chemically stratified lake, possibly a shallower lake (Fig. 16). By contrast, the Big Marsh oil shale was deposited in a deeper lake with regular rate recharge/discharge and mostly deposited under dysoxic to a suboxic-dysoxic condition (Goodarzi etal., 2019b). Variation Ni+V and C/U and Cr is very informative, indicating that: (a) most of the Albert oil shales were deposited in shallow-dysoxic conditions similar to that of Big Marsh oil shales (Goodarzi etal. 2019b), and (b) The oil shales with high migrated hydrocarbon (bitumen) inclusions, which were deposited separately, possibly due to input of migrating brine and an increase in water depth (Fig 17a -b).

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Fig.15b. Variation of Cr/U ratio with Cr (ppm) for oil shales from Big Marsh deposits, Nova Scotia, and Albert, New Brunswick, Canada. 5.6. Paleo-temperature The Sr and Mn concentrations were used to determine the paleo-temperature and salinity/brackishness of the depositional environment (Lea, 2003, Hosseininejad Mohebati, 2016; Goodarzi etal, 2019b). The high Sr/Ca ratio is an indication of high temperature, and a high Ca/Mn ratio indicates cooler temperature and higher input of terrigenous sediment (Hosseininejad Mohebati, 2016, Goodarzi eta. , 2019b). Variation of Sr/Ca versus Mn/Ca ratios for oil shales from Albert and Big Marsh oil shales (Fig.15), indicates that the oil shales from Big Marsh have low Mn/Ca ratio and high Al content and were deposited in colder water with high terrigenous influx, possibly due to high rain and flooding (Stoll et al., 2002, Hosseininejad Mohebati, 2016, Goodarzi etal., 2019b). By contrast, the Albert oil shale, with higher Sr/Ca, were deposited under possibly warmer and dryer conditions with low terrigenous influx (Fig. 16).

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Fig. 16. Variation of Mn/Ca and Sr/Ca ratios for oil shales from Big Marsh, Nova Scotia, and Albert deposit, New Brunswick.

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5.4. Rare Earth Elements (REEs)

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There are not much data available on the concentration of REEs in oil shales, particularly for Canadian oil shales (Goodarzi etal. 2019b). In organic-rich deposit, such as coal, REEs are mostly associated with the inorganic components, such as clay and other minerals (Pollock etal., 2000; Eskenazy, 1987a-b; van der-Flier-Keller, 1993; Hower et al., 2016; Seredin and Dai, 2012; Dai et al., 2016a, b). In some cases, rare earth elements (particularly heavy REEs) can also have an association with organic matter in coal (Eskenazy, 1987a; Seredin and Dai, 2012). The Albert oil shales contain a high percentage of carbonate (Smith, 1991, Goodarzi etal., 2019a) and higher boron and lower aluminosilicate and REEs content (Fig. 15, Table 6a). Albert Lake was starved of aluminosilicate but was saline with a higher rate of discharged to recharge, causing high ionic concentrations and the formation of carbonate (Allen and Collinson, 1986; Smith et al., 1991, Goodarzi etal., 2019a, c). In contrast, Big Marsh oil shales have no carbonate (Macaulay, 1988) and formed in a hydrologically open system with a water discharge that was nearly equal to recharge and a low ionic concentration that did not allow deposition of carbonate. These differences between the two lakes reflected in the concentration of the REEs (Fig 17).

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Ba

Cs

Ga

292 241 241 368 274

3.9 4.5 4.5 8.8 5.5

19.3 15.39 15.39 18.25 21.24

335 296 70 491

4.4 5.3 9.4 2.8

18.59 12.94 20.91 15.39

457 514 306 430

2.3 4.4 2 9.6

17.43 1.66 25 764 7.99 14.47 2.12 116.2 676 7.12 15.29 1.8 126.3 670 7.86 18.85 2.5 144.5 501 11.94

62.1 77.2 48.1 103

65 416 625 270 313

6.7 6.1 3.1 6.2 9.2

12.58 24.16 17.55 14.23 17.54

5.99 11.27 9.94 7.68 8.19

199 376 298 364 337

1.4 5.5 2.3 5.3 4.3

18.95 22.21 18.64 20.94 22.12

2.4 29.1 350 9.5 2.21 103.1 871 9.64 1.92 83.8 1838 7.71 2.46 102.7 874 9.54 2.22 165.4 833 8.87

3.3 7.9

Li

Nb

Rb

Sb

Sc

Sr

2.79 77 2.53 56.3 2.53 56.3 2.72 73.4 3.09 120.5

449 258 258 1323 157

8.77 11.18 11.18 9.51 11.34

47.5 41.6 41.6 108.7 58.5

1.24 1.69 1.69 1.13 1.98

9.5 10.2 10.2 14.9 11.4

175 220 220 369 131

10.9 88.9 18.4 104.6 18.4 104.6 16.4 86.3 6.2 95.6

1.68 1.89 2.59 1.03

194 7.91 28.9 930 5.83 62 248 11.06 128.6 608 7.14 69.8

2.05 0.81 2.48 1.62

8.8 12.2 13.6 8.5

144 425 116 499

7.8 30.6 10.5 7.9

58.8 72.4 88.3 41.1

0.74 2.3 1.48 0.83

9.8 1019 17.2 13.5 1428 19.4 7.1 513 14.5 13.8 577 15.7

55.3 89.6 68.3 87.2

75.2 52.9 38.3 63.9 83

0.91 0.64 1.38 1.64 3.52

10.5 12.7 11.8 11.1 10.2

829 158 272 423 90

9.8 23.2 18.6 19.1 6.7

48.8 95.8 77.3 94.2 67.7

30.9 32 29 33.8 24.4

2.2 2.39 0.67 1.93 1.83

7.3 9.8 10.6 11.5 10

278 282 227 277 211

14 13.2 14.2 14.4 11.9

91.7 81.8 69.8 82.9 78.5

21.51 2.95 151.9 654 11.64 42.1 0.34 23.52 3.12 78.5 629 11.03 112.4 1.32

10.6 16.3

287 123

18.5 101.5 24.4 107

76 35.9 99.2 44.9

1090 491 1253 900 195

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1.29 54 3.04 73.9 2.27 65.5 2.22 83 2.04 204.5

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Location Taylor Village TV-2-69 TV-2-88.8 TV-2-91 TV-2-104 TV-2-114.2 Albert Mine (AM) AM-1 AM-Pit 2 AM-2 AM-3 Albert Mine (AM-15A) AM-15A-342 AM-15A-345 AM-15A-659 AM-15A-745 Boudreau BOUD-1-111 BOUD-1-116 BOUD-1-123 BOUD-1-130 BOUD-1-141 Urney-Arco ARCO-1-325 ARCO-1-466 ARCO-1-548 ARCO-1-628 ARCO-1-708 Mapleton N-11 N-11-08-648 N-11-08-765

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Table 5. The concentration of minor elements (ppm) in Albert oil shales and Mapleton shale.

The concentration of both light REEs (La-Sm) and heavy REEs (Eu-Lu) is higher in the Big Marsh oil shale, than the Mapleton shale and Albert oil shale deposit (Fig 17, Table 6b), indicating greater input of aluminosilicate containing REEs in the Big Marsh than those in the Albert oil shales carbonate-rich brackish settings (Fig.17). Further, the variation of Y and La also clearly divides the two oil shales into Big Marsh with high aluminosilicate and Y, and Albert with high carbonate, low aluminosilicate, and Y, (Fig.18). The most significant difference in two oil shales is in their HREEs content, which is higher in freshwater Big Marsh with almost no carbonate and high aluminosilicate than the chemically stratified Albert oil shale with high carbonate oil shale (Fig 19).

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Ce 294.4 550.0 83.6 41.8 39.0

Pr 30.9 65.1 10.5 5.2 4.7

Nd 108.2 255.9 40.6 20.3 17.8

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La 153.2 237.4 34.7 17.3 19.0

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Big Marsh, coastal Big Marsh, shallow Big Marsh, deep Mapleton Albert oil shales

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Table 6a. Concentration of Rare Earth elements (ppm) in Albert oil shales and Mapleton shale. Sm 18.4 55.0 9.2 4.6 3.8

Eu 2.5 7.4 1.3 0.7 0.8

Gd 14.5 52.2 8.8 4.4 3.3

Tb 2.0 8.0 1.5 0.7 0.5

Dy 10.4 47.1 8.7 4.4 3.2

Ho 1.9 10.2 1.8 0.9 0.6

Er 5.3 26.7 5.1 2.6 1.8

Tm 0.8 4.2 0.8 0.4 0.3

Yb 5.5 27.7 5.1 2.6 1.9

Table 6b. Average concentration of Rare Earth elements (ppm) in Big Marsh and Albert oil shales and Mapleton shale.

Lu 0.7 0.8 0.9 0.5 0.3

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Concentration (ppm)

350

REEs

LREEs

HRREs

300 250 200 Albert oil shales

150 100

Big Marsh

Mapleton

Taylor Village Albert Mine Albert Mine (DH)

Boudreau

Urney-Arco

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Fig. 17. Variation of total REES, LRREs, and HREEs for oil shales from Big Marsh, Nova Scotia, and Albert, New Brunswick.

Figure 18. Variation of La and Y (ppm) for oil shale from in Big Marsh and Albert deposits clearly divides the two oil shales based on the depositional environment.

5.4.1. The normalized pattern of REEs The PAAS normalized pattern of REEs for both lacustrine oil shales are very informative (Figs 20).

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For organic-rich sediments such as coal and oil shale, the Eu anomaly is an inherited phenomena, since, the redox transformation resulting in Eu anomaly requires both extremely reducing conditions and high-temperature (Sverjensky, 1984; Bau, 1991, Dai, et al., 2016a), which is typical of magmatic processes (Rard, 1985) and is not found during subaquatic deposition of coal and oil shale low temperature (Rrad, 1985; Bau, 1991, Dai, et al., 2016a).

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Fig 19. Variation of Hydrogen Index with heavy rare earths (ppm) for oil shales from Big Marsh, Nova Scotia and Albert deposits, New Brunswick. 5.4.1. The normalized pattern of REEs

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The PAAS normalized pattern of REEs for both lacustrine oil shales are very informative (Figs 20). The positive Eu anomaly in coal from Sydney basin, Nova Scotia Canada was related to the presence of Ca-rich minerals such as plagioclase feldspars in coal (volcanoclastic origin) due to an isomorphous replacement of Ca2+ with Eu2+ (Birk and White, 1991). An excellent example of Eu anomaly for coal-bearing strata is reported by Dai et al. (2014b) for a floor of Coal No.2 and No3 in Xinde Mine, Yunnan, China. Dai et al. (2014a) found that some Chinese coals exhibiting positive Eu anomalies are influenced by volcanogenic hydrothermal solutions (these coals containing high pyrite content and high concentrations of Hg-As assemblage) or influenced by the input of terrigenous materials of high-Ti mafic basalts (Dai et al. 2014a, 2014b). In general, the Eu anomaly in organic-rich sedimentary rock is due to input country rock ( igneous source rocks) during deposition (Taylor and McLennan, 1985; Eskenazy, 1987a; Qi et al., 2007; Yossifova et al., 2011; Dai et al., 2015b and 2016a). The normalized patterns for Albert oil shale that was influenced by brackish water with high carbonate from New Brunswick display a slight positive Eu anomaly (Fig. 20a). The positive Eu

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anomaly in oil shales influenced by brackish water, possibly due to the diagenetic remobilization of Eu under reducing condition (Elderfield, 1988). It was also reported in highly weathered muds of Amazon deep fan of Pleistocene age (MacRae et al, 1992) and in K/T boundary ejecta layer in Agost and Caravaca, SE Spain, developed due to the diagenetic process, which resulted in extensive pyrite formation and high concentration of autogenetic U (Martinez-Ruiz, 1999).

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Fig 20. (a) The pattern of PAAS normalized average REES for (a) Albert oils shales from New Brunswick and (b) compared with Big Marsh oil shale Nova Scotia.

6. Conclusions



 

Acknowledgment

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The Albert oil shale deposits from New Brunswick were deposited in a freshwater lacustrine environment, with variable water chemistry due to the influenced variation in the rate of discharge to recharge. The high rate of discharge to recharge resulted in aluminosilicate starvation, and formation of higher carbonate content, in contrast to the Big Marsh oil shale, a deposit that appears to have a regular rate of discharge/recharge and higher aluminosilicate and no carbonate. The carbonate particles, which often contain oil inclusions in some of the Albert oil shale samples, were included in the lake during the early diagenetic stage, as evident by wrapping of the organic matrix around in particular. The Big Marsh oil shale has a much higher concentration of REEs due to higher input of aluminosilicate than those in Albert oil shale, which were aluminosilicate starved. The differences between the two oil shales are the occurrence of a negative Eu anomaly, typical of upper continental crust, in the Big Marsh oil shale from Nova Scotia, and a positive Eu anomaly in the Albert oil shale.

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In contrast, the Big Marsh oil shales deposited freshwater lacustrine environment display a negative Eu anomaly (Fig. 20b), which is typical of the upper continental crust (Taylor and Mclemman, 1985) and similar to the coal from the Guxu Coalfield, Sichuan Province, China, which contained terrigenous felsic- intermediate rocks (Dai et al., 2016a).

Journal Pre-proof Authors thank the ecoENERGY Innovation Initiative, Department of Natural Resources Canada, Foundation for their partnership in this project. Ms. H. Stewart and Mr. S. Hinds of the Department of Energy and Mines, New Brunswick, thanks for their assistance and providing valuable geological information. Professor P. Pedersen, Department of the Earth Sciences University of Calgary, is thanked for arranging the sample collection. Dr. Hamed Sani, Geological Survey of Canada, Calgary, is thanked for providing the RockEval analyses. The ICP-MS was analysis conducted at Acme Labs in Vancouver, Canada. Author thanks Dr. R. MacQueen, Geological Survey of Canada Calgary for valuable suggestions and reviewing this paper. References

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Location (NAD 83 UTM 20N) Easting Northing Surface Samples Albert Mines Pit 1 2 samples 368599.4422 5082242.316 Albert Mines Pit 1 2 samples 368599.4422 5082242.316 Albert Mines Pit 2 2 samples 368614.7279 5082267.557 Albert Mines river samples 2 samples 368614.7279 5082267.557 Location Name

Samples

Big Marsh BM #4

13 samples

379167.1367 376536.5701 368580.0183 317470.0185 341799.4361

5088840.318 5086545.858 5081934.998 5065768.309 5079110.213

583633

5072596

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Taylor Village #2 Boudreau #1 Albert Mines ARCO Urney #1 Mapleton N #11

Core Samples 5 samples 5 samples 4 samples 5 samples 3 samples

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Table 1.Location of samples used in this study.

Fe

K

Mg

Na

P

S

Ti

6.22 5.45 4.9 7.02 4.9

1.16 2.02 1.91 7.56 0.27

2.27 2.27 2.03 5.16 2.4

1.82 1.43 1.38 1.86 2.14

1.09 1.22 1.06 4.09 0.88

1.32 1.515 1.417 0.489 1.286

0.051 0.273 0.283 0.037 0.042

0.43 1.36 0.71 0.34 0.43

0.363 0.279 0.263 0.27 0.421

5.39 5.43 7.51 5.98

3.48 9.7 1.16 4.19

2.7 2.76 2.82 3.65

1.64 1.28 2.06 2.15

0.77 0.81 1.07 2.36

0.647 0.898 0.685 0.514

0.05 0.081 0.072 0.021

0.06 0.22 0.15 0.18

0.329 0.247 0.393 0.259

6.06 5.58 5.05 7.46

5.95 5.34 3.53 3.77

3.01 3.14 3.23 3.37

2.32 1.44 1.54 1.98

2.24 1.7 1.79 2.79

0.737 2.206 3.325 1.569

0.05 1.492 0.053 0.05

0.12 0.31 0.6 0.73

0.314 0.278 0.314 0.395

5.37 7.87 5.98 5.44 5.77

12.17 2.32 5.36 4.43 0.33

4.08 3.18 4.64 3.61 4.38

1.47 2.3 1.8 1.37 2.46

4.16 1.02 2.01 2.09 1.19

0.312 0.993 0.668 0.981 1.032

0.046 0.062 0.048 0.619 0.04

3.07 0.16 0.43 0.73 0.7

0.191 0.417 0.34 0.29 0.343

5.85 5.73 5.29 5.57 5.43

2.16 4.08 4.34 4.14 2.86

2.87 3.97 5.13 3.94 4.21

1.54 2.36 1.98 2.26 2.52

0.8 1.1 2 1.08 1.49

4.289 1.268 0.873 1.194 0.911

0.046 0.048 0.035 0.05 0.039

0.99 0.53 0.23 0.42 0.34

0.321 0.294 0.248 0.314 0.306

3.69 1.72

3.44 4.51

2.4 3.1

1.39 1.52

2.499 0.967

0.049 0.061

0.06 0.04

0.354 0.355

5.8 8.24

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Ca

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N-11-08-648 N-11-08-765

Al

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Location Taylor Village TV-2-69 TV-2-88.8 TV-2-91 TV-2-104 TV-2-114.2 Albert Mine (AM) AM-1 AM-Pit 2 AM-2 AM-3 Albert Mine (AM-15A) AM-15A-342 AM-15A-345 AM-15A-659 AM-15A-745 Boudreau BOUD-1-111 BOUD-1-116 BOUD-1-123 BOUD-1-130 BOUD-1-141 Urney-Arco ARCO-1-325 ARCO-1-466 ARCO-1-548 ARCO-1-628 ARCO-1-708

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Table 2. The concentration of major elements (wt%) in Albert oil shales and Mapleton shale for the location of boreholes, see figure 3.

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Cd

Co

Cr

Cu

Mn

Mo

Ni

Pb

Se

Sr

Th

U

V

162 258 224 181 337

32.9 60.5 54.9 10.2 70.5

0.21 0.42 0.35 0.1 0.43

22.4 20.2 19.2 12.5 22.8

60 35 46 47 61

45.11 78.52 137 73.92 62.94

449 258 270 1323 157

17.95 49.96 54.06 2.87 34.27

45.8 49.6 56.8 25 45.2

26.31 30.13 34.41 15.67 22.85

0.8 1.3 1.7 0.3 0.2

175 220 248 369 131

5.2 5.3 8.5 8.4 3.1

6.6 6.7 8.4 2.3 3

99 95 97 88 132

164 107 173 123

99 13.1 116.5 35.6

0.19 0.19 0.12 0.21

12.1 12.2 11.6 14.6

54 38 66 44

44.05 37.2 82.08 39.47

194 930 248 608

6.71 2.92 8.89 9.29

39 18.22 21.7 8.78 35.5 25.79 40.6 15.57

0.4 0.5 0.8 0.5

144 425 116 499

4.1 7.3 10.8 4.9

1.5 4 3.2 1.6

137 82 134 84

95 72 36 131

16.3 68.9 53 14.5

0.19 15.2 0.35 16.4 0.29 14.1 0.2 18.8

43 47 42 57

48.88 60.91 62.12 83.55

764 5.97 32.5 16.34 <0.2 1019 676 19.61 36.8 26 0.9 1428 670 60.45 27 20.45 1.2 513 501 11.08 33.8 18.54 14.7 577

97 173 156 111 158

158 6.2 14.4 43.7 124.7

124.7 0.13 0.2 0.14 0.15

0.15 10.4 14 13.9 23.5

38 296 312 276 272

43.7 26.9 6.3 25.5 18.6

0.17 0.17 0.18 0.19 0.22

18.1 18.6 12.7 18.5 22.4

81 171

4.6 6.5

0.2 0.14

18.3 19.3

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23.5 60 1090 63.86 62 45.02 491 1.07 48 33.01 1253 4.11 39 38.7 900 9.09 60 63.86 195 16.92

7.6 2.7 6.5 4.6 5.7 3.8 7.5 3.8

88 93 92 110

16.92 24.5 31.9 30.9 51

51 77.78 0.7 10.45 0.3 158 15.69 0.5 272 14.98 0.7 423 77.78 0.7 90

4 7.2 6.2 6 4

2.4 3.1 2.8 4.5 2.4

108 111 95 87 108

57 74 65 78 86

46.82 39.58 35.43 39.55 49.75

350 871 1838 874 833

7.43 6.58 1.73 6.01 4.89

47.4 57.1 43.4 54.7 64.2

25.16 24.59 11.81 22.43 26.4

1.4 0.5 0.3 0.2 0.3

278 282 227 277 211

8.6 4.9 5 6 3.6

3.3 2.6 2.7 2.7 2.3

80 121 106 127 118

72 99

42.81 654 119.7 629

3.9 0.62

43 8.95 61.8 11.57

0.2 0.2

287 123

7.7 11.1

2.4 2.8

125 119

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Location Taylor Village TV-2-69 TV-2-88.8 TV-2-91 TV-2-104 TV-2-114.2 Albert Mine (AM) AM-1 AM-Pit 2 AM-2 AM-3 Albert Mine (AM-15A) AM-15A-342 AM-15A-345 AM-15A-659 AM-15A-745 Boudreau BOUD-1-111 BOUD-1-116 BOUD-1-123 BOUD-1-130 BOUD-1-141 Urney-Arco ARCO-1-325 ARCO-1-466 ARCO-1-548 ARCO-1-628 ARCO-1-708 Mapleton N-11 N-11-08-648 N-11-08-765

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Table 3. The concentration of elements of environmental concern (ppm) in Albert oil shales and Mapleton shale for the location of boreholes, see figure 3.

Journal Pre-proof Ba

Cs

Ga

292 241 241 368 274

3.9 4.5 4.5 8.8 5.5

19.3 15.39 15.39 18.25 21.24

335 296 70 491

4.4 5.3 9.4 2.8

18.59 12.94 20.91 15.39

457 514 306 430

2.3 4.4 2 9.6

17.43 1.66 25 764 7.99 14.47 2.12 116.2 676 7.12 15.29 1.8 126.3 670 7.86 18.85 2.5 144.5 501 11.94

65 416 625 270 313

6.7 6.1 3.1 6.2 9.2

12.58 24.16 17.55 14.23 17.54

1.29 54 3.04 73.9 2.27 65.5 2.22 83 2.04 204.5

199 376 298 364 337

1.4 5.5 2.3 5.3 4.3

18.95 22.21 18.64 20.94 22.12

3.3 7.9

Li

Nb

Rb

Sb

Sc

Sr

2.79 77 2.53 56.3 2.53 56.3 2.72 73.4 3.09 120.5

449 258 258 1323 157

8.77 11.18 11.18 9.51 11.34

47.5 41.6 41.6 108.7 58.5

1.24 1.69 1.69 1.13 1.98

9.5 10.2 10.2 14.9 11.4

175 220 220 369 131

10.9 88.9 18.4 104.6 18.4 104.6 16.4 86.3 6.2 95.6

1.68 1.89 2.59 1.03

194 7.91 28.9 930 5.83 62 248 11.06 128.6 608 7.14 69.8

2.05 0.81 2.48 1.62

8.8 12.2 13.6 8.5

144 425 116 499

7.8 30.6 10.5 7.9

58.8 72.4 88.3 41.1

62.1 77.2 48.1 103

0.74 2.3 1.48 0.83

9.8 1019 17.2 13.5 1428 19.4 7.1 513 14.5 13.8 577 15.7

55.3 89.6 68.3 87.2

5.99 11.27 9.94 7.68 8.19

75.2 52.9 38.3 63.9 83

0.91 0.64 1.38 1.64 3.52

10.5 12.7 11.8 11.1 10.2

829 158 272 423 90

9.8 23.2 18.6 19.1 6.7

48.8 95.8 77.3 94.2 67.7

2.4 29.1 350 9.5 2.21 103.1 871 9.64 1.92 83.8 1838 7.71 2.46 102.7 874 9.54 2.22 165.4 833 8.87

30.9 32 29 33.8 24.4

2.2 2.39 0.67 1.93 1.83

7.3 9.8 10.6 11.5 10

278 282 227 277 211

14 13.2 14.2 14.4 11.9

91.7 81.8 69.8 82.9 78.5

21.51 2.95 151.9 654 11.64 42.1 0.34 23.52 3.12 78.5 629 11.03 112.4 1.32

10.6 16.3

287 123

18.5 101.5 24.4 107

76 35.9 99.2 44.9

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Hf

-p

1090 491 1253 900 195

re

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357 301

Mn

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Location Taylor Village TV-2-69 TV-2-88.8 TV-2-91 TV-2-104 TV-2-114.2 Albert Mine (AM) AM-1 AM-Pit 2 AM-2 AM-3 Albert Mine (AM-15A) AM-15A-342 AM-15A-345 AM-15A-659 AM-15A-745 Boudreau BOUD-1-111 BOUD-1-116 BOUD-1-123 BOUD-1-130 BOUD-1-141 Urney-Arco ARCO-1-325 ARCO-1-466 ARCO-1-548 ARCO-1-628 ARCO-1-708 Mapleton N-11 N-11-08-648 N-11-08-765

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Table 4. The concentration of minor elements (ppm) in Albert oil shales and Mapleton shale, for the location of boreholes, see figure 3.

Journal Pre-proof Locations

La

Ce

Pr

Nd

Sm

Eu

Gd

Tb

Dy

Ho

Er

Tm

Yb

Lu

Y

Taylor Village 12.7

27.91

3.4

13

2.9

0.6

2.4

0.4

2.5

0.5

1.5

0.2

1.6

0.3

10.9

30.8

53.21

6.1

23.6

4.9

1

4.2

0.6

4.3

0.8

2.4

0.4

2.6

0.4

TV-2-91 TV-2-104

16.1 30.8

38.5 58.19

4.8 6.6

17 26.1

3.9 4.8

0.9 1

3.5 3.9

0.6 0.5

3.9 3.7

0.8 0.7

2.2 1.9

0.3 0.3

2.2 2.1

0.3 0.3

TV-2-114.2 Albert Mine (AM) AM-1 AM-Pit 2

5.1

12.5

1.8

6.7

1.8

0.4

1.6

0.4

1.9

0.4

1.2

0.2

1.3

0.2

21.9 18.4 16.4 6.2

10.1 26.2

20.1 55.48

2.5 7.3

9.4 28.4

1.9 6.6

0.4 1.5

1.5 6.5

0.3 1.1

1.6 6.3

0.4 1.2

1.1 3.2

0.2 0.4

1.4 2.6

0.2 0.4

AM-2 AM-3 Albert Mine (AM-15A) AM-15A-342

23.4 16.8

43.71 32.96

5.1 3.8

20 14

3.6 2.7

0.7 0.5

2.9 2.1

0.3 0.3

2.7 1.9

0.5 0.3

1.5 1.1

0.2 0.2

1.7 1.1

0.2 0.2

25.8

53.71

6.6

23.2

4.8

1

4.4

0.6

3.5

0.7

1.9

0.3

1.9

0.3

AM-15A-345 AM-15A-659 AM-15A-745 Boudreau

23.2 21.8 22.9

48.48 43.98 47.3

5.3 5.3 5.8

19.7 18.9 22.1

3.9 3.9 4.2

0.9 0.9 0.9

3.6 3.5 3.7

0.6 0.5 0.5

3.3 3 3.2

0.7 0.6 0.6

2 1.5 1.8

0.3 0.2 0.3

1.9 1.5 2.1

0.3 0.2 0.3

BOUD-1-111 BOUD-1-116 BOUD-1-123 BOUD-1-130

21.5 22.9 24.3 23.5

38.17 48.76 50.46 44.41

4.2 6.3 6.3 5.2

15.4 24.3 23.5 19.3

2.7 5.3 4.9 3.9

0.6 1.1 1.2 0.9

2.3 4.8 4.3 3.6

0.2 0.8 0.7 0.5

2 4.7 4.1 3.3

0.4 1 0.7 0.7

1.3 2.8 2.3 2.1

0.2 0.4 0.3 0.3

1.5 2.8 2 1.9

0.2 0.5 0.3 0.3

BOUD-1-141 Urney-Arco ARCO-1-325 ARCO-1-466 ARCO-1-548

9.8

22.38

2.9

10.8

2.2

0.5

1.6

1.7

0.4

1.1

0.2

1.2

0.2

17.4 10.5 18

39.91 24.64 38.13

5 3.1 4.6

18.6 12 17.9

4.3 2.8 4.1

0.9 0.6 0.9

ARCO-1-628 ARCO-1-708

12.6 10.4

30.01 24.98

3.8 3.1

14.6 11.9

3.6 2.9

22.2 32

49.09 72.22

6.3 9.4

22.1 33.9

N-11-08-648 N-11-08-765

5.2 7.1

ro

-p

0.2

1.1 1.5

7.8 30.6 10.5 7.9 17.2 19.4 14.5 15.7 9.8 23.2 18.6 19.1 6.7

3.7 2.7 3.4

0.5 0.4 0.6

3 2.8 3.4

0.6 0.6 0.7

1.7 1.8 1.9

0.2 0.3 0.3

1.6 1.8 1.8

0.3 0.3 0.3

3.2 2.8

0.6 0.5

3.2 2.7

0.7 0.6

1.8 1.7

0.3 0.3

2.2 1.8

0.3 0.3

14 13.2 14.2 14.4 11.9

4.6 6.2

0.8 1

4.4 5.2

0.8 1

2.3 2.8

0.3 0.4

2.3 2.9

0.3 0.4

18.5 24.4

re 0.7 0.7

lP

Mapleton N-11

of

TV-2-69 TV-2-88.8

La 153.2 237.4 34.7 17.3 19.0

Ce 294.4 550.0 83.6 41.8 39.0

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Big Marsh, coastal Big Marsh, shallow Big Marsh, deep Mapleton Albert oil shales

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na

Table 5. Concentration of Rare Earth elements (ppm) in Albert oil shales and Mapleton shale, for the location of boreholes, see figure 3.

Pr 30.9 65.1 10.5 5.2 4.7

Nd 108.2 255.9 40.6 20.3 17.8

Sm 18.4 55.0 9.2 4.6 3.8

Eu 2.5 7.4 1.3 0.7 0.8

Gd 14.5 52.2 8.8 4.4 3.3

Tb 2.0 8.0 1.5 0.7 0.5

Dy 10.4 47.1 8.7 4.4 3.2

Ho 1.9 10.2 1.8 0.9 0.6

Er 5.3 26.7 5.1 2.6 1.8

Tm 0.8 4.2 0.8 0.4 0.3

Yb 5.5 27.7 5.1 2.6 1.9

Lu 0.7 0.8 0.9 0.5 0.3

Table 6. Average concentration of Rare Earth elements (ppm) in Big Marsh and Albert oil shales and Mapleton shale

Journal Pre-proof Declaration of interests ☒ The authors declare that they have no known competing financial interests or personal relationships that could have appeared to influence the work reported in this paper.

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☐The authors declare the following financial interests/personal relationships which may be considered as potential competing interests:

Journal Pre-proof

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Albert oil shales were deposited in a lacustrine environment based on geological setting and under oxic-dysoxic conditions. The Albert oil shale has variable B content (97-337 ppm), possibly indicative of a higher rate of discharge to recharge, due to tectonic activity during deposition of the oil shale and chemical stratification. The Albert oil shale displays a positive Eu anomaly, typical of a high carbonate environment, compared to similar lacustrine oil shle , such as Big Marsh, which shows a negative Eu anomaly, which is typical of upper continental crust.