A Rock-Eval Evaluation of the Bakken Formation in Southern Saskatchewan

T.E. Aderoju 1 and S.L. Bend 1

Aderoju, T.E. and Bend, S.L. (2013): A Rock-Eval evaluation of the Bakken Formation in southern Saskatchewan; in Summary of Investigations 2013, Volume 1, Saskatchewan Geological Survey, Sask. Ministry of the Economy, Misc. Rep. 2013-4.1, Paper A-2, 14p.

Abstract This paper presents preliminary results from an ongoing study of the Bakken petroleum system within the northern part of the Williston Basin, particularly with respect to geochemical characterization of the Upper and Lower members of the Bakken Formation. The study utilizes high-resolution core sampling within the Upper and Lower Bakken; results from Rock-Eval analysis of these samples show a significant degree of depth-related (temporal) and basin-wide variability in total organic carbon, S2, hydrogen index, and Tmax. Generally, the shales of the Upper and Lower Bakken would typically be classified as immature to marginally mature based on the standard interpretation of Tmax, whereas the temporal variation in S2 and hydrogen index suggests the presence of a Type II kerogen, although significant variability in organic matter composition indicate that this is an oversimplification of generation potential. The degree of geochemical variation for the Upper and Lower Bakken in Saskatchewan is therefore summarized based on several source-rock screening parameters.

Keywords: hydrocarbons, Bakken Formation, Rock-Eval, total organic carbon, hydrogen index, organic matter.

1. Introduction The Williston Basin is a prolific petroleum province that contains a number of producing intervals (Dow, 1974; Williams, 1974; Osadetz et al., 1992). Of those producing intervals, the Bakken Formation has received an increasing degree of industry and research focus in recent years. Since 2005, production from the Bakken Formation in southeastern Saskatchewan has increased from 177 m3/day (1,113 bbls/day) in January 2005 to 11 000 m3/day (69,190 bbls/day) in December 2011, mostly due to the widespread application of horizontal drilling and sand-fracture completions (Yang, 2012). The Bakken Formation is generally subdivided into Lower, Middle, and Upper members (Figure 1) based upon lithological characteristics (Christopher, 1961; LeFever et al., 1991; Meissner, 1991). The Upper and Lower Bakken members are composed of non-calcareous, fissile, pyritic organic-rich shale and exhibit an apparent degree of lithological uniformity throughout the Williston Basin. The Middle Bakken member occurs as fine-grained dolomitic sandstone and dolomitic siltstone units that form the main hydrocarbon reservoir within the Bakken in southeastern Saskatchewan (Martiniuk, 1988; LeFever et al., 1991; Kreis et al., 2006; Kohlruss and Nickel, 2009).

Middle Bakken oil is a light to medium crude oil with an average specific gravity of 0.835 (38° API). Numerous reports and studies also show that the Bakken oil exhibits significant variation in composition and physical properties; for example, reported specific gravity ranges from 0.888 to 0.825 (27.8 to 40° API) (Kreis and Costa, 2005; Kreis et al., 2006; Chen et al., 2009) and sulphur content ranges from less than 1.0 wt. % to over 3.5 wt. % within southern Saskatchewan (Chen et al., 2009). The origin of the oil produced from the Middle Bakken in southeastern Saskatchewan remains a subject of significant debate (e.g., Jiang et al., 2001; Chen et al., 2009), driven by the perceived low level of thermal maturity of the Bakken shales in southern Saskatchewan (Osadetz et al., 1992; Osadetz and Snowdon, 1995; Jiang et al., 2001; Chen et al., 2009), the proposed mixing of oils generated from Bakken and younger Mississippian source rocks within Middle Bakken reservoirs (Jiang and Li, 2002a, 2002b; Chen et al., 2009), or suggestions that the only zone of active oil generation occurs within North Dakota (LeFever et al., 1991; Price and LeFever, 1994).

Numerous studies comment upon the high source potential of both the Upper and Lower Bakken shale, based upon estimations of total organic carbon (TOC) content derived from petrophysical wire-line logs (e.g., Schmoker and Hester, 1983; Webster, 1984) or the direct analysis of TOC (e.g., Dow, 1974; Osadetz and Snowdon, 1995).

1 Petroleum Geochemistry Unit, Department of Geology, University of Regina, 3737 Wascana Parkway, Regina, SK S4S 6M3.

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Using Rock-Eval pyrolysis, Osadetz et al. (1992) and Osadetz and Snowdon (1995) reported that the Upper and Lower Bakken shales were dominated by marine-derived amorphous kerogen, characterized as Type II-kerogen, with an associated hydrogen index (HI) of 615 mg hydrocarbon/g TOC. The occurrence of Type I-kerogen was also reported, identified as the maceral Tasmanites (Christopher, 1961; Stasiuk et al., 1990), with a small amount of degraded organic material and a non-fluorescing Type III “bituminite” (Stasiuk et al., 1990), which suggested the existence of a more geochemically complex kerogen within the Upper and Lower Bakken, or that the organic matter within the Upper and Lower Bakken exhibits a degree of variability.

Based on assessments of thermal maturity, Osadetz et al. (1992) and Osadetz and Snowdon (1995) suggest that the Bakken Formation is immature to marginally mature within southern Saskatchewan. Nordeng and LeFever (2009), however, note an apparent anomaly within North Dakota in that those areas associated with the greatest oil production are also those areas in which the Upper and Lower Bakken appear ‘sub-mature.’ Jiang et al. (2001) also note that the Upper and Lower Bakken appear to have a lower level of thermal maturity compared to the overlying Lodgepole Formation. Jiang et al. (2001) comment that the process responsible for the disparity in the observed pattern of thermal maturity was unclear, since depth of burial is generally associated with increasing thermal stress (e.g., Tissot and Welte, 1984; Hunt, 1996; Peters et al., 2005).

Considering the very high level of total organic carbon and the oil-generating potential of the Bakken Formation in general, the problem remains as to why, in the Williston Basin and in southern Saskatchewan in particular, the Upper and Lower Bakken appear to have contributed so little to known accumulations of petroleum.

This project is part of a large integrated assessment of the Phanerozoic fluid and petroleum systems of the southern Saskatchewan portion of the Williston Basin conducted at the universities of Alberta and Regina. Using high-resolution core sampling, this particular sub-study seeks to examine, evaluate, and document the

possible temporal and spatial geochemical variations in organic matter and source potential of the Upper and Lower Bakken within the northern portion of the Williston Basin. This paper, therefore, summarizes preliminary results derived from the Rock-Eval pyrolysis and extract analysis of the organic matter within the Upper and Lower Bakken in southern Saskatchewan.

2. Methodology a) Sampling and Analytical Procedures Drill core from 29 wells (Table 1, Figure 2) was selected for analysis based upon core availability, core recovery, the location of wells, and the association with areas of proven hydrocarbon generation. High-density sampling was achieved by obtaining 20 to 25 g of sample from up to 30 sample sites throughout the Upper and Lower Bakken cored intervals in each well. Weathered material was initially removed from each sample. The cleaned samples were subsequently pulverized for 10 seconds using a Tema mill to less than 105 µm, homogenized, and split into a number of sub-samples for analysis.

Figure 1 – Reference well CPG Kisbey 11/01-17-008-06W2M (08B385) illustrating stratigraphy, lithologies, and gamma-ray (orange) and spontaneous potential (SP) (blue) geophysical log responses for the Late Devonian to Early Mississippian Bakken Formation and overlying and underlying strata in southern Saskatchewan. Location of this well is shown in Figure 2. Note that whereas Big Valley is absent in this well (Nickel, 2010, Figure 3), in many wells to the west and northwest, the Lower Bakken conformably overlies the Big Valley Formation, which lies unconformably on the Torquay Formation (Nickel, 2010). SSTVD represents the subsea true vertical depth, with depth in metres.

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Samples were analyzed for source potential using a Vinci Technologies Rock-Eval 6 analyser to quantify the amount, the type, and degree of thermal maturity of organic matter present within each sample of core without the limiting effects of contamination or data scatter commonly associated with the analysis of drill cuttings. Specifically developed and designed for petroleum exploration, Rock-Eval pyrolysis is a rapid form of bulk analysis that is used to assess the hydrocarbon-generating potential of source rocks and has become an industry standard. The analytical procedure for Rock-Eval pyrolysis is well documented in the literature (e.g., Espitalié et al., 1977; Tissot and Welte, 1984; Peters et al., 2005). Each analysis derives a number of parameters that form the basis of most geochemical assessments of source potential and subsequent interpretation. Figure 3 illustrates the method of analysis, associated pyrolysis and oxidation curves, and both derived and calculated parameters. Derived parameters include: 1) S1, the peak associated with the thermal distillation of indigenous hydrocarbon; 2) S2, the peak associated with the pyrolytic decomposition of kerogen; 3) S3CO and S3CO2, the amount of CO and CO2 from organic matter released during pyrolysis; and 4) S4CO and S4CO2, the amount of CO and CO2 from organic matter released during oxidation.

Table 1 – Details of well locations shown on Figure 2.

Well Name Location Well Licence No. on Figure 2

Cabri Crown No 1 01/01-23-020-19W3M 52D027 1

Christie Quintana Melaval 11/02-14-008-04W3M 51G001 2

Placid SiftoTugaske 01/02-10-023-02W3M 66F153 3

Imperial Constance 01/08-36-003-29W2M 58D013 4

Cve Willow Bunch 41/11-33-005-28W2M 08L040 5

Mobil Oil Willow Bunch No 5 2 01/02-05-005-27W2M 56B045 6

Mobil Oil Sohio Burn Lake No 27 14 01/14-27-008-26W2M 55K059 7

HB Radville 01/06-07-005-18W2M 63H054 8

Canera Tatagwa 41/05-26-006-16W2M 84K247 9

IOE CDR Jewel 01/08-20-004-14W2M 67A066 10

Postell Weyburn 01/16-35-006-14W2M 84I243 11

Socony Weyburn No 1 01/08-11-008-14W2M 53D017 12

Valleyview et al Weyburn 01/06-09-007-13W2M 85A089 13

CNRL et al Goodwater 41/09-13-005-13W2M 81K044 14

Nal et al Torquay 41/15-31-003-11W2M 81D003 15

Longview Midale 01/07-14-007-11W2M 85A046 16

Shell Bryant 91/13-34-004-09W2M 76J002 17

Pilot Huntoon N V1U 11/15-15-007-09W2M 95I189 18

Canera et al N Handsworth 01/15-25-010-08W2M 65G163 19

Innova Freestone 11/16-28-008-07W2M 07A091 20

CNRL et al Roche Percee 01/12-27-001-06W2M 80L031 21

PHEC Wordsworth 31/11-12-007-04W2M 08E260 22

TW Pan-am Whitebear Cr 11/05-15-010-02W2M 58G015 23

Star Parkman 11/16-10-010-01W2M 83E176 24

CCEC Edenvale North 01/06-24-006-33W1M 06I015 25

Transwest Rocanville 01/05-04-016-31W1M 86H080 26

CPEC et al Welwyn 01/01-16-015-31W1M 85F292 27

Spectrum et al Ingoldsby East 21/06-16-004-30W1M 05L114 28

Petrostar Winmore 11/01-32-001-30W1M 93H082 29

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Figure 2 – Map of the study area showing the locations of cored wells that were sampled. Numbers are keyed to Table 1. The green star indicates the location of reference well 11/01-17-008-06W2M (Figure 1).

Figure 3 – The mode of analysis and respective pyrolysis or oxidation curves for a Rock-Eval 6 analyser, and the calculated parameters and derived indices that are used to assess source potential. The mode of analysis is shown on the left with the associated peaks (centre); the derived indices and calculated parameters are tabulated on the right.

Assessments of total extract in the shales of the Upper and Lower Bakken were obtained by the Soxhlet/Soxtec extraction method of solvent extraction, using an azeotropic mixture of dichloromethane and methanol (93:7 v/v) to remove the extractable organic matter (i.e., bitumen) present within each sample. Each aliquot of extract was subsequently fractionated using column liquid chromatography to separate the extractable organic matter into hydrocarbon (saturate and aromatic) and non-hydrocarbon (e.g., nitrogen-, sulphur-, and oxygen-bearing

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compounds) fractions using light petroleum ether, petroleum ether/dichloromethane (30:70 v/v), and dichloromethane/methanol (50:50 v/v), respectively, as solvent for the elution of each fraction.

3. Results and Discussion

a) Rock-Eval Analysis of the Upper and Lower Bakken For those wells analyzed, the total organic carbon (TOC) content, in wt. %, for the Upper and Lower Bakken is not constant throughout the cored intervals, but rather exhibits an extreme degree of variability with depth (Figure 4). Furthermore, there appears to be a constant trend in which the Upper Bakken contains a higher TOC content than the Lower Bakken. In the study area, the highest TOC content recorded for the Upper Bakken was 33 wt. %, with an average of 25 wt. %, whereas the highest value recorded for the Lower Bakken was 20 wt. % TOC, with an average of 19 wt. %. However, as noted above, there is a significant variation in TOC with depth for any given well. For example, within the Upper Bakken in well 01/5-4-16-31W1M (86H080), the TOC ranges from 2 to 23 wt. % and in well 01/15-25-10-8W2M (65G163), within the Lower Bakken, the TOC ranges from 4 to 16 wt. % (Figure 4).

Figure 4 – The depth-related variation in total organic carbon for samples from six wells (west to east): A) Christie Quintana Melaval 11/02-14-008-04W3M (51G001); B) Valleyview et al Weyburn 01/06-09-007-13W2M (85A089); C) Pilot Huntoon N V1U 11/15-15-007-09W2M (95I189); D) Canera et al N Handsworth 01/15-25-010-08W2M (65G163); E) PHEC Wordsworth 31/11-12-007-04W2M (08E260); and F) Transwest Rocanville 01/05-04-016-31W1M (86H080). See Figure 2 and Table 1 for well locations.

The example TOC profiles in Figure 4 illustrate the degree of variability in TOC within a given cored section. Such significant variations call to question the use of a single data point when seeking to characterize the quantity of total organic matter within either the Upper or Lower Bakken in a given well, or the reliance upon wire-line logs in assessing TOC. To illustrate this point, TOC isopleth maps for both the Upper and Lower Bakken (Figures 5A and 5B, respectively) were generated, as a work-in-progress; these maps show the spatial variation in TOC across the study area. Because TOC content varies with depth for a given well, each isopleth data point also shows the degree of variation as a plus/minus value (e.g., 01/6-9-7-13W2M (85A089); ±11 wt. %) for both the Upper and Lower Bakken.

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Figure 5 – The spatial variation in total organic carbon (TOC), in wt. %, within the study area for A) the Upper Bakken and B) the Lower Bakken. For both figures, TOC is based on the arithmetic average of summed values for each well profile. The degree of variance in TOC for each well is indicated as a plus/minus (±) value at each data point. Note that, in A), the high TOC values indicated by the contours between approximately Range 15W2 and Range 25W2 are an artefact related to the response by the software used in generating the map to the paucity of data in this area. See Figure 2 and Table 1 for well locations.

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Although this work is still ‘in progress’, some interesting patterns appear to be emerging, in that the degree of variation in the Lower Bakken is least in wells 01/5-4-16-31W1M (86H080) and 11/05-15-010-02W2M (58G015) along the eastern depositional margin of the Lower Bakken (see Figure 4 in Kohlruss and Nickel, 2009), with variations of ±1 wt. % and ±0.6 wt. %, respectively (Figure 5B); whereas the degree of variation for the Upper Bakken is the greatest (±15 wt. %) in well 01/5-4-16-31W1M (86H080) (Figure 5A). This pattern is also reflected in well 11/02-14-008-04W3M (51G001), in which the variance in the Lower Bakken is ±3 wt. %, whereas in the Upper Bakken the variance is ±13 wt. %. Reasons for such patterns are not yet apparent; however, this preliminary analysis shows that the possibility exists for an under- or over-estimation of the TOC content for a given location when the analysis relies upon either an average estimation or a single analysis of TOC for either the Upper or Lower Bakken.

Figure 6 shows the variation in S1 (mg/g), S2 (mg/g), HI, and TOC (wt. %) throughout the Lower and Upper Bakken in well 01/07-14-007-11W2M (85A046). There was no core recovered from the uppermost part of the Upper Bakken in this particular well. Within the Lower Bakken, the S2 varies from approximately 20 mg/g to over 100 mg/g, with a mean value around 80 mg/g over an interval of 5.5 m, whereas values for the Upper Bakken range from 85 mg/g to over 125 mg/g. Values for the HI plot around 500 mg HC/g TOC, with most values exceeding 550 mg HC/g TOC.

Figure 6 – The depth-wise relationship between Rock-Eval parameters S1, S2, hydrogen index (HI), and total organic carbon (TOC) in a single well (Longview Midale 01/07-14-007-11W2M (85A046)). Note the similarity between S1, S2, and TOC with depth throughout both Upper and Lower members, in which the Upper Bakken has a higher average and greater range in S1, S2, and TOC than the Lower Bakken. See Figure 2 and Table 1 for well location.

The TOC content, as derived by Rock-Eval 6, shows a close relationship to S1 and S2, since both parameters—along with the S3 and S4 peaks—are used to calculate the Rock-Eval 6–derived TOC (see Figure 3). However, what is unexpected is that the TOC values for the Upper and Lower Bakken are controlled by the presence and magnitude of both the S1 and S2 peaks.

To illustrate this point, cross-plots of S1 versus TOC and S2 versus TOC (Figures 7A and 7B) show a strong direct relationship between measured and derived parameters, yielding a correlation of R2=0.95 and R2=0.98, respectively. Such high correlations no doubt reflect the low values derived for S3 and S4, since the organic matter within the Upper and Lower Bakken typically plots as Type II and Type II/I, both of which have a relatively high HI (Figure 8) and a correspondingly low oxygen index (OI). Both the Lower and Upper Bakken have exceptionally high S2 values and corresponding high TOC values. In comparison, the Monterey shale in California is associated with a TOC that ranges from 0.75 to 17.35 wt. % and the Green River shale in the Uinta Basin in Utah has a TOC of approximately 25 wt. % (Ruble et al., 2001). On the basis of TOC alone, both Upper and Lower Bakken satisfy the criteria of Cook and Sherwood (1991) as an oil shale; if one takes into consideration the dominance of bituminite (Wrolson and Bend, 2013) within both Upper and Lower Bakken, then the criteria of Hutton (1987) for an oil shale are also met.

The non-linearity in HI versus TOC (Figure 7C) may be partly inherent, since TOC influences both axes (i.e., HI=S2/TOC x 100) although it was noted that TOC is a quantitative assessment of the amount of organic matter within a given horizon, whereas HI is an expression of generative potential of kerogen. Dean et al. (1986) used HI versus TOC to infer bottom-water oxygen conditions and the amount of terrestrial organic matter input in different depositional environments. The observed level-off of samples at HI value of ~550 mg HC/g TOC may reflect the preservation state of the depositional environment, which at that point influences the TOC, showing an increment in TOC, but with no further influence on HI. The minimum value in TOC, S2, and HI towards the top of the Lower Bakken reflects changing conditions within the depositional basin.

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Figure 7 – Cross-plots of: A) S1, B) S2, and C) hydrogen index (HI) versus total organic carbon (TOC), for the Upper and Lower Bakken within a single well (Longview Midale 01/07-14-007-11W2M (85A046)). See Figure 2 and Table 1 for well location.

The genetic potential and quality of a given source rock is typically portrayed by a cross-plot of HI versus OI, as a modern variant of the van Krevelen diagram (Figure 8). Most data points for this study cluster with an HI of ~550 mg HC/g TOC, with a minor spread in data around HI ~300 to 500 mg HC/g TOC, suggesting that the Upper and Lower Bakken is composed of mostly Type II kerogen with minor amounts of Type I/II and Type III, suggesting the dominance of oil-prone organic matter using conventional standard values (e.g., Tissot and Welte, 1984; Peters et al., 2005).

In addition to the van Krevelen diagram, a series of preliminary depth versus HI plots were generated for five example wells from across the study area (Figure 9). For two wells at the western and eastern margins of the study area (01/01-23-020-19W3M (52D027) and 01/05-04-016-31W1M (86H080), respectively), HI values are <200 mg HC/g TOC for the upper half of the Upper Bakken (Figures 9A and 9E); however, the lower half of the Upper Bakken in well 01/05-04-016-31W1M (86H080) (Figure 9E) has the highest HI value (>400 mg HC/g TOC) within the Bakken for that well. The lower section of the Upper Bakken in well 01/01-23-020-19W3M (52D027) (Figure 9A) was unavailable for analysis due to missing core. These two wells show a different pattern within the Lower Bakken, with a fairly consistent HI that is typically over 450 mg HC/g TOC in well 01/01-23-020-19W3M (Figure 9A) compared to the lower values below 100 mg HC/g TOC in well 01/05-04-016-31W1M (Figure 9E). Towards the base of the Lower Bakken, core was unavailable for both wells.

In well 11/02-14-008-04W3M (Figure 9B), within the south-central part of the study area, both the Upper and Lower Bakken show a more consistent and invariant pattern with respect to HI, with values typically falling around 550 mg HC/g TOC. In contrast, within the southeastern part of the study area, no consistent pattern was observed for HI throughout the Upper Bakken in wells 01/15-25-010-8W2M and 01/05-04-016-31W1M (Figures 9D and 9E, respectively), but in the Lower Bakken, two wells (41/05-26-006-16W2M and 01/15-25-010-8W2M; Figures 9C and 9D, respectively) do echo some degree of similarity, showing an overall increase in HI with increasing depth.

Figure 8 – Organic matter type as defined by modified van Krevelen diagram (hydrogen index (HI) versus oxygen index). Note that most data points cluster with an HI of ~550 mg HC/g TOC, with a minor spread in data around HI ~300 to 500 mg HC/g TOC, suggesting that the Upper and Lower Bakken is composed of mostly Type II kerogen with minor amounts of Type I/II and Type III.

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The degree of thermal maturation for most of the samples analyzed to date, as indicated by Rock-Eval Tmax, suggests that the organic matter within the Upper and Lower Bakken is immature to marginally mature, when using the conventional standard Tmax oil-window parameters for samples consisting of Type II kerogen (Tissot and Welte, 1984; Peters et al., 2005). The highest Tmax value recorded for the Upper Bakken within this data set is 435°C, and the highest Tmax value recorded for the Lower Bakken was 440°C, both occurring in well 01/12-27-1-6W2M (80L031) near Estevan.

Figure 9 – The depth-wise relationship in hydrogen index (HI) for five selected wells across the study area, from west to east: A) Cabri Crown No 1 01/01-23-020-19W3M (52D027); B) Christie Quintana Melaval 11/02-14-008-04W3M (51G001); C) Canera Tatagwa 41/05-26-006-16W2M (84K247); D) Canera et al N Handsworth 01/15-25-010-8W2M (65G163); and E) Transwest Rocanville 01/05-04-016-31W1M (86H080). See Figure 2 and Table 1 for well locations.

There is also a spatial variation in Tmax within both the Upper and Lower Bakken across southern Saskatchewan. Tmax isotherm maps for the Upper and Lower Bakken (Figures 10A and 10B, respectively), based upon calculated average values for each well, reflect variations in measured thermal maturity. However, because slight depth-wise variations exist for each well profile, the range in data is expressed as a ±°C value for each data point. The range of variation within the Upper Bakken is ±4°C or less, except for two wells in Tp 15 and 16, Rge 31W1M with variances of ±15°C and ±17°C, respectively (Figure 10A). Lower Bakken values show the greatest degree of variance in well 01/14-27-008-26W2M (55K059) west of Weyburn (±13°C), and in well 01/01-23-020-19W3M (52D027) northwest of Swift Current (±12°C). In the remaining wells with Lower Bakken samples, the range of variation is ±7°C or less. Generally, maturity increases proximal to the U.S.A./Canada border south of Estevan, although the overall spatial pattern of Tmax appears to differ between the Upper and Lower Bakken.

Wells associated with a pronounced variation in Tmax are also those same wells that exhibit a significant variation in TOC, perhaps reflecting a mineral dilution effect or the influence of other factors, such as the presence of indigenous bitumen or variations in sulphur content, as reported elsewhere (Orr, 1986; Peters, 1986); this is an area of ongoing and future work.

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Figure 10 – Spatial variation in the average Rock-Eval Tmax in the analyzed wells for A) the Upper Bakken and B) the Lower Bakken, with the range of variation indicated for each well. The shape of the margins of the contour maps are limited by the spatial distribution of analyzed wells. Note that, in A), the contours indicated between approximately Range 17W2 and Range 26W2 are artefacts related to the response by the software package used in generating the map to the paucity of data in this area. See Figure 2 and Table 1 for well locations.

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b) Source Extract Composition Extractable organic matter (EOM) is the amount of soluble organic matter, in mg/g, that can be removed from fine-grained sediment, by an organic solvent, during source rock extraction under standardized conditions (e.g., Peters et al., 2005). EOM is sometimes referred to as extractable bitumen since the EOM contains both hydrocarbon and non-hydrocarbon. Figure 11 illustrates the statistical relationship between the S1 values obtained from Rock-Eval analysis and the amount of EOM for 27 samples from both the Upper and Lower Bakken members.

A correlation coefficient of R2=0.7 suggests a positive correlation, although S1 does not always directly correspond to the amount of EOM present within a given sample, and the amount of EOM usually exceeds the amount of hydrocarbon (S1) within a given sample. However, an observed correlation of 0.7 is interesting since S1 is derived by the temperature-driven thermolysis of labile-organic compounds within the C1 to C32 range (Peters, 1986), whereas EOM is a function of the solubility of organic compounds using an organic solvent mixture refluxed through the sample. It is widely believed that S1 consists of hydrocarbons within the C1 to C32 range (Tarafa et al., 1983), whereas EOM typically contains organic compounds removed by organic solvent, as shown in the depth profile for well 01/07-14-007-11W2M (85A046) (Figure 12).

Figure 12 – A) Variation in the extractable organic matter with depth, and B) variation in the proportion of saturate, aromatic, and nitrogen-, sulphur-, and oxygen-bearing (NSO) fractions in source extract with depth for the Upper and Lower Bakken (normalized to 100%) for samples from well 01/07-14-007-11W2M (85A046); depth is given in metres. The corresponding S1, S2, and TOC profiles are shown in Figure 6. See Figure 2 and Table 1 for well location.

Figure 11 – A cross-plot of extractable organic matter versus Rock-Eval S1, showing a correlation coefficient of R2=0.7.

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Since S1, S2, HI, and TOC show a depth-wise variation throughout the Upper and Lower Bakken members (Figures 4 and 6), it should be anticipated that EOM would follow the same pattern. Figure 12A shows the depth-wise profile of EOM throughout the Upper and Lower Bakken of well 01/07-14-007-11W2M (85A046). As observed in Figure 12A, the greatest amount of EOM occurs within the Upper Bakken, and the depth-wise variation in EOM generally corresponds to the depth-wise pattern identified for S1, S2, and TOC in Figure 6. The fractionation of the EOM into hydrocarbon (both saturate and aromatic) and non-hydrocarbon (nitrogen-, sulphur-, and oxygen-bearing compounds, or NSO) fractions (Figure 12B) shows the abundance of NSO compounds relative to the saturate and aromatic fractions throughout the Upper and Lower Bakken. The relative proportion of high molecular weight NSO compounds relative to saturate and aromatic fractions is probably a function of thermal maturity, and also a reflection of the molecular composition of indigenous kerogen within the Bakken (Tissot and Welte, 1984); work on this topic is also ongoing.

4. Conclusions The geochemical characterization of the Upper and Lower Bakken members within southern Saskatchewan indicates a high hydrocarbon potential, based upon Rock-Eval screening of uncontaminated core samples.

Analyses also show that a significant variation in S1, S2, HI, and TOC exists both depth-wise in individual wells within the Upper and Lower members of the Bakken Formation, and in wells across the study area. Such variations observed within a single well query the use of a single data point to characterize source potential for a given stratigraphic unit within any well. In the wells with cores that were analyzed in this study, the Upper Bakken shows a higher TOC and S2 content compared to the Lower Bakken. Preliminary maps based on calculated average values of TOC show an increase in TOC to the south with increased depth of Bakken strata, with relatively low TOC values towards the western and northeastern margins of the study area; the maps indicate the degree of variance in TOC per well across the study area (Figure 5).

Depth-wise variations in the various Rock-Eval parameters obtained throughout the Upper and Lower Bakken suggest significant variation of kerogen type within the two members, even though each shale unit appears to possess a high degree of lithological uniformity.

Both the Upper and Lower Bakken possess a very high source potential due to the presence of exceptionally high TOC, S2, and HI values. However, most of the shale units appear as marginally mature to immature as inferred from the Tmax value (<435°C) using conventional ‘oil window’ parameters for a Type II kerogen.

The amount of extractable organic matter reveals the presence of free hydrocarbon within both the Upper and Lower Bakken, which is also in agreement with derived Rock-Eval S1 values. Fractional analysis of the EOM indicates the presence of a high proportion of NSO compounds compared to saturate and aromatic hydrocarbon fractions in most analyzed samples.

Based on the TOC criteria of Cook and Sherwood (1991) and the criteria of Hutton (1987), both the Upper and Lower Bakken satisfy the definition of an oil shale.

5. Acknowledgements This project would not be possible without funding from the Saskatchewan Ministry of the Economy and the Petroleum Technology Research Centre. We also thank the International Performance Assessment Centre for the Geologic Storage of Carbon Dioxide for use of the Rock-Eval 6 analyser.

6. References Chen, Z., Osadetz, K.G., Jiang, C., and Li, M. (2009): Spatial variation of Bakken or Lodgepole oils in the Canadian

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