Relationships between porosity, organic matter, and mineral matter in mature organic-rich marine mudstones of the Belle Fourche and Second White Specks formations in Alberta, Canada

Marine and Petroleum Geology 54 (2014) 65e81 Contents lists available at ScienceDirect Marine and Petroleum Geology journal homepage: www.elsevier.com/locate/marpetgeo Research paper Relationships between porosity, organic matter, and mineral matter in mature organic-rich marine mudstones of the Belle Fourche and Second White Specks formations in Alberta, Canada Agnieszka Furmann a, *, Maria Mastalerz b, Arndt Schimmelmann a, Per Kent Pedersen c, David Bish a a b c Department of Geological Sciences, Indiana University, Bloomington, IN 47405, USA Indiana Geological Survey, Indiana University, Bloomington, IN 47405, USA Department of Geoscience, University of Calgary, Calgary, AB T2N 1N4, Canada a r t i c l e i n f o a b s t r a c t Article history: Received 18 June 2013 Received in revised form 6 February 2014 Accepted 26 February 2014 Available online 7 March 2014 This study presents approaches for evaluating hybrid source rock/reservoirs within tight-rock petroleum systems. The emerging hybrid source rock/reservoir shale play in the Upper Cretaceous Second White Specks and Belle Fourche formations in central Alberta, Canada is used as an example to evaluate organic and inorganic compositions and their relationships to pore characteristics. Nineteen samples from a 77.5 m-long core were analyzed using organic petrography, organic geochemistry, several methods of pore characterization, and X-ray powder diffraction (XRD). The lower part of the studied section includes quartzand clay-rich mudrocks of the Belle Fourche Formation with low carbonate content, whereas the upper portion contains calcareous mudrocks of the Second White Specks Formation. Strata are mineralogically composed of quartz plus albite (18e56 wt. %), carbonates (calcite, dolomite, ankerite; 1e65 wt. %), clays (illite, kaolinite, chlorite; 15e46 wt. %), and pyrite (2e12 wt. %). Petrographic examinations document that organic matter represents marine Type II kerogen partly biodegraded with limited terrestrial input. Vitrinite reflectance Ro (0.74e0.87%), Tmax values (438e446  C) and biomarkers indicate mid-maturity within the oil window. The relatively poor remaining hydrocarbon potential, expressed as an S2 value between 2.1 and 6.5 mg HC/g rock, may result from an estimated 60e83% of the original kerogen having been converted to hydrocarbons, with the bulk having migrated to adjacent sandstone reservoirs. However, the presentday remaining total organic carbon TOCpd content remains relatively high (1.7e3.6 wt. %), compared with the estimated original TOCo of 2.4e5.0 wt. %. The calculated transformation ratio of 60e83% suggests that the remaining 17e40 wt. % of kerogen is able to generate more hydrocarbons. The studied section is a tight reservoir with an average Swanson permeability of 3.37$10 5 mD (measured on two samples) and total porosity between 1.7 and 5.0 vol. % (3 vol. % on average). The upper part of the sandy Belle Fourche Formation, with slightly elevated porosity values (3.5e5 vol. %), likely represents the interval with the best reservoir properties in the studied core interval. Total pore volume ranges between 0.0065 and 0.0200 cm3/ g (measured by a combination of helium pycnometry and mercury immersion). Mesopores (2e50 nm B) are the most abundant pores and occupy 34e67% of total porosity or a volume of 0.0030e0.0081 cm3/g. In comparison, micropores (<2 nm B) cover a wide range from 6 to 60% (volume 0.0007e0.0053 cm3/g), and macropores (>50 nm B) reach up to 57% with the exception of some samples failing to indicate the presence of this pore fraction (volume 0.0000e0.0107 cm3/g). Macroporosity is mostly responsible for variations in total porosity, as suggested by macroporosity’s strongest correlation with total porosity within the section. The relatively narrow ranges of TOC and minerals contents among measured samples limit our ability to further deconvolute factors that influence changes in total porosity and pore size distribution. Ó 2014 Elsevier Ltd. All rights reserved. Keywords: Unconventional reservoir Thermal maturity Organic matter Porosity Second White Specks Formation Belle Fourche Formation Alberta * Corresponding author. Department of Geological Sciences, 1001 East 10th Street, Indiana University, Bloomington, IN 47405-1405, USA. Tel.: þ1 812 236 4962. E-mail address: afurmann@indiana.edu (A. Furmann). http://dx.doi.org/10.1016/j.marpetgeo.2014.02.020 0264-8172/Ó 2014 Elsevier Ltd. All rights reserved. 66 A. Furmann et al. / Marine and Petroleum Geology 54 (2014) 65e81 1. Introduction Recent success in extraction of hydrocarbons from tight unconventional-type reservoirs has triggered a dramatic increase in research on self-sourced systems, like hybrid source rock/reservoir mudstone plays. An unconventional oil/gas mudstone play (generally called a shale play) commonly consists of a sedimentary succession across a large geographic area with the following characteristics: dominantly clay- to silt-sized particles, high contents of silica and/or carbonates, high organic matter (OM) content, thermally mature, hydrocarbon-filled porosity, and low to very low permeability. Such plays require multistage fracture stimulation in horizontal wells to achieve economic production (Caputo, 2011). An evaluation of the unconventional hydrocarbon resource potential of source rock/reservoir formations must take advantage of multidisciplinary approaches involving porosity, OM, and mineral matter. This study uses the specific example of mature organic-rich marine mudstones within the Second White Specks petroleum system in Alberta to highlight strengths and shortcomings of various parameters, e.g., the vertical variation in porosity and pore types and facies-related controls on pore characteristics. A combination of analytical methodologies encompassing organic petrology, geochemistry, mineralogy, and porosimetry expands our understanding of organic-rich petroleum systems. The Second White Specks Formation located within the Western Canada Sedimentary Basin (Fig. 1) is one of the emerging hybrid source rock/reservoir plays in North America that has attracted the attention of recent explorations (Clarkson and Pedersen, 2011; Kwan and Mooney, 2010). The Second White Specks and Belle Fourche formations were deposited within the Cretaceous Western Interior Seaway (a foreland basin) of North America (Bloch et al., 1999). Changes in the depositional paleoenvironment within the Seaway were responsible for lateral and vertical changes in the geochemistry and mineralogy within and between the formations. In turn, burial and compaction of sediment as well as diagenetic processes related to hydrocarbon generation influenced the poor preservation of porosity and permeability, making this play challenging in terms of exploration and production (Greff and Cheadle, 2012). Extensive research has been done on the Second White Specks Fm.’s stratigraphy, lithology, and OM characteristics (i.e. organic petrography and Rock-Eval pyrolysis) from British Columbia, Alberta, Saskatchewan, and Manitoba (e.g., Bloch et al., 1993, 2002; Kovac and Last, 1991; Macauley, 1984a,b; Schröder-Adams et al., 1996; Stasiuk and Goodarzi, 1988; Tyagi et al., 2007). Significantly less is known about the porosity systems. Bloch (1995) recognized that shales from the lower Colorado Group (including the Second White Specks, the Belle Fourche, and the Fish Scale formations; Fig. 2) were of economic interest as the shale reservoirs. However, at that time conventional wisdom considered the Second White Specks Fm. to be mostly a source rock that had expelled large volumes of hydrocarbons to adjacent sandstone reservoirs, e.g., the overlying Cardium Fm. (Mossop and Shetsen, 1994). Although several prolific wells have been completed in the Second White Specks Fm., many unsuccessful attempts to establish multi-well pools discouraged further drilling. Historically this formation has been mainly characterized as a natural fracture-controlled reservoir with high lateral heterogeneity in its primary intrinsic porosity o o 120 W W6 110 W o 60 N W5 T115 T104 ALBERTA T92 Western Canada Sedimentary Basin BRITISH COL ing as ty e r inc aturi m T69 T58 x Edmonton T46 07-19-45-6W5 AN SASKATCHEW UMBIA T81 T35 Immature Mature Overmature x T23 Calgary T12 N 0 100 200 km 49oN Figure 1. Extent of the Second White Specks Fm. in Alberta, Canada, within the Western Canada Sedimentary Basin (map after Creaney and Allan, 1990). Maturity within the Second White Specks Fm. increases westward (after Kwan and Mooney, 2010). The black square represents the well location (T45 e township; W5 e range). A. Furmann et al. / Marine and Petroleum Geology 54 (2014) 65e81 67 Second White Specks Formation Well 07-19-45-6W5 Core depth: 1793.5-1871 m Core length: 77.5 m Formation depth: 1754->1890 m Formation thickness: >120 m Core depth (m) 1790 1800 1810 1830 1840 Age Fish Scales 99 Ma Sample depth (m) 1 2 1794.50 1798.40 3 1805.60 5 6 7 1810.25 1813.70 1818.75 11 1826.55 12 13 1833.30 1834.50 14 15 16 1840.90 1846.40 1848.90 17 1855.20 18 19 1860.10 1863.10 20 1869.80 8 1821.70 9 1822.60 10 1823.70 0 1850 1860 1870 Period Sample number 1820 Belle Fourche Formation Colorado Group 93 Ma Cenomanian Upper Cretaceous Turonian Top of Second White Specks Formation 25 ? 50 m 0 GR (GAPI) 200 Red Bentonite from Tyagi et al. (2007) and Greff and Cheadle (2012) boundary proposed in this study based on mineralogy and petrography Figure 2. Position of core in well 07-19-45-6W5 within the Belle Fourche and Second White Specks formations (well location is shown in Fig. 1). The boundary between the Belle Fourche and Fish Scales formations is not well defined. Numbers and depths of 19 collected samples are given to the right of the core that is indicated by a black vertical bar. Sample #4 was not included in this study. The well gamma-ray log (GR) in GAPI units (Gamma-ray, American Petroleum Institute; Hoppie et al., 1994) is shown on the right and the smoothed core gamma-ray log is depicted on the left (does not correspond to the given GAPI scale). Both GRs show a reasonably good match. Stratigraphy adapted from Mossop and Shetson (1994), Tyagi et al. (2007) and Greff and Cheadle (2012). distribution (Greff and Cheadle, 2012). Only recently this formation is being re-evaluated as a promising tight oil reservoir (characterized by very low matrix permeability) and also as one of the emerging tight oil/shale plays in North America. Assessment of unconventional formations, and hybrid source rock/reservoir plays in particular, requires parallel applications of several methodologies. Tight oil reservoirs are often highly heterogeneous strata within the oil window maturity and therefore require careful analyses of both OM and mineral matter, including the effects of kerogen transformation on porosity generation and preservation. Therefore, a set of organic geochemical techniques combined with mineralogical and porosimetry analyses had been applied to understand the pore types and their affiliations within these complex systems of the Second White Specks and Belle Fourche formations. 2. Methodology 2.1. Sample material Nineteen mudstone samples were collected at the ERCB Core Research Centre in Calgary, Canada, from well 07-19-45-6W5 (Fig. 2) that had been drilled in 1979 by the ‘Canadian Hunter’ company. Although long-term storage could possibly influence rock chemical properties, the core has value as a representative core for the two studied formations. The 77.5 m long core (depth 1793.5 me 1871.0 m) covers the middle and upper part of the late Cenomanian Belle Fourche Fm. and the lower part of the overlying middle Cretaceous (early Turonian) Second White Specks Fm. (Fig. 2). Sample weights ranged from 20 to 110 g. The top of the core occurred w39.5 m below the top of the Second White Specks Fm. (1754.0 m), whereas the bottom of the core is w19 m above the base of the Fish Scales Fm. Although it is difficult to pick the boundary between the Belle Fourche and the Fish Scales formations, lithologic and stratigraphic evidence strongly suggests that the core ends within the Belle Fourche Fm. without reaching the Fish Scales Fm. Samples represent dark to black pyritic mudstones with abundant silty and/or calcareous laminations, occasional ripples, calcareous shells of bivalves, fish bones and fish scales. The examined sections of the Belle Fourche and Second White Specks formations consist of several mudstone facies. Each facies comprises several microfacies as shown in the core photos in Figure 3. Samples for analyses were collected from dominant mudstone facies. Siltstone, sandstone and shell laminae were not sampled as they comprise a very small portion of the section and are typically tightly cemented with very low porosity. However, smaller fragments of these laminae might be present in several samples used for X-ray powder diffraction (XRD) analyses, e.g., the high carbonate content in samples #5 and 15 is likely due to abundant shell 68 A. Furmann et al. / Marine and Petroleum Geology 54 (2014) 65e81 Figure 3. Core photos representing mudstone facies in samples from well 07-19-45-06W5. (A) Dark mudstone with frequent thin ripple siltstone laminae. Abundant shell fragments of various sizes and rare siltstone borrows. Sample #3, 3.32 wt. % TOC, 1.7 vol. % porosity. (B) Dark mudstone interbedded with abundant planar and ripple siltstone laminae. Note the steep scoured base of the sandstone bed, with abundant fish bones within the basal part of the scour fill. Sample #5, 1.74 wt. % TOC, 2.5 vol. % porosity. (C) Silty mudstone with dark mudstone and siltstone laminae and scattered small shell fragments. Sample #7, 2.04 wt. % TOC, 3.2 vol. % porosity. (D) Dark mudstone with rare discontinuous siltstone laminae and shell fragments. Note the graded beds in central part of the photo. Sample #12, 2.01 wt. % TOC, 4.1 vol. % porosity. (E) Calcareous dark mudstone with abundant siltstone laminae and small to large shell fragments (pointed by arrows). Sample #15, 3.62 wt. % TOC, 2.9 vol. % porosity. (F) Gray silty, calcareous mudstone with discontinuous ripple siltstone laminae. Note the bioturbated character of several beds. Sample #18, 2.58 wt. % TOC, 2.2 vol. % porosity. fragments (Fig. 3B and E). The stratigraphy is based on Mossop and Shetson (1994) and Tyagi et al. (2007). However, the boundary between the Second White Specks and Belle Fourche formations was placed here based on clear changes in mineralogical and organic petrographic characteristics. Therefore, we propose this boundary to occur a few meters below the one proposed by Tyagi et al. (2007) and Greff and Cheadle (2012) based on the occurrence of red bentonite (Fig. 2). 2.2. Characterization of organic matter Maceral compositions were characterized with a Leitz Orthoplan microscope using both white and fluorescent light. The relative abundances of maceral groups were assessed visually for all samples, and several samples (#1, 5, 15, and 18) were selected for 500-point count analyses. Vitrinite reflectance Ro (%) values were measured on a Zeiss Photoscope. The recycled nature of most vitrinite particles made it difficult to find indigenous particles and thus limited reliable Ro measurements (maximally 25 points). The Rock-Eval 2 analyzer was used to characterize the hydrocarbon potential (i.e. Tmax, hydrogen index HI, oxygen index OI, etc.). Total organic carbon (TOC) concentration data relied on a LECO 600 Carbon Analyzer. In addition, TOC, total carbon (TC), and total sulfur (TS) were quantified on powdered samples with an Eltra CS-2000 instrument. The transformation ratio TRHI (i.e. the conversion of kerogen to hydrocarbons) for the mature section, the original Hydrogen Index HIo, and original TOCo for the immature equivalent of these rocks were calculated according to Jarvie et al. (2007). A. Furmann et al. / Marine and Petroleum Geology 54 (2014) 65e81 Biomarkers in OM (bitumen) were Soxhlet-extracted from about 15 g dry, crushed shale using a 9:1 (v:v) mixture of dichloromethane (CH2Cl2, 270 mL) and methanol (CH3OH, 30 mL) for 72 h, followed by evaporation in a TURBOVAP, weighing of the residual bitumen, re-dissolution in 100 mL hexane, ultrasonication for 5 min, and filtering through a pasteur pipette (i.d. 5 mm) filled with 2 cm baked glass-wool to retain precipitated asphaltenes. The filtered extract was collected in a 250 mL beaker, and additional 50 mL of hexane were used to rinse any remaining extract from the round-bottom flask through the filtering pipette into the beaker. Elemental sulfur was removed from asphaltene-free extracts by reaction with freshly reduced, solvent-rinsed copper powder. The extract was separated chromatographically into fractions on a glass column (i.d. 5 mm, w12 cm length) containing w6e7 cm of deactivated silica gel (5 wt. % water) using an elution sequence of (i) hexane (8 mL), (ii) hexane/CH2Cl2 (8 mL; 1:1 v:v), and (iii) CH2Cl2/ CH3OH (6 mL; 1:1 v:v). The three resulting fractions are called aliphatic (F1), aromatic (F2), and polar (F3), respectively. Each fraction was collected into a 3 dram vial (11 mL volume) from where solvents were evaporated under a stream of purified N2 at room temperature. The aliphatic fraction F1 was re-dissolved in hexane, transferred into GC vials, and analyzed by gas chromatography e mass spectrometry (GCeMS) to identify and quantify individual components. GCeMS employed an Agilent 6890N series gas chromatograph equipped with a split/splitless injector and connected to an Agilent 5973 quadrupole mass spectrometer. Each fraction was injected with the split ratio of 30 into an Agilent DB-5MS fused silica capillary column (30 m  0.25 mm i.d., 0.25 mm film thickness) that was held isothermally at 60  C for 1.5 min, then programmed in two steps from 60  C to 130  C at 20  C/min, and from 120  C to 320  C at 3  C/min, and finally held isothermally at 320  C for 20 min. The MS source was operated at 250  C in EI-mode with ionization energy of 70 eV. Data were acquired and processed using ChemStation software. Mass-chromatography of diagnostic ions assisted in the identification of homologous series of n-alkanes (m/ z ¼ 85; Robinson et al., 1991), acyclic isoprenoids (m/z ¼ 57, 183; Petrov et al., 1990), steranes and diasteranes (m/z ¼ 217; Grantham and Wakefield, 1988), and hopanoids (m/z ¼ 191; Hoffmann et al., 1984). 2.3. Mineral composition Mudstone samples were powdered to <5 mm B in deionized water in a McCrone micronizer with quartz grinding elements and oven-dried at 110  C overnight. A Bruker D8 Advance X-ray diffractometer with a Sol-X solid-state detector and a Cu X-ray tube operated at 40 kV and 30 mA was utilized to identify and quantify mineral phases. Mudstone powders were placed into a large frontpacked mount (LFPM) and scanned from 2 to 70 using a count time of 2 s per 0.02 step. Multicomponent concentrations were quantified by Rietveld refinements with TOPAS software. Thinsection microscopy was performed in support of XRD interpretation. The brittleness index was calculated according to Jarvie et al. (2007) and Wang and Gale (2009) based on quantified mineralogy. 2.4. Surface area, mesopore volume, and micropore volume Approximately 2.0e2.5 g of each mudstone sample with grain sizes between 2.83 mm and 4.76 mm (i.e. 7e4 mesh or 0.111e0.187 inch) were analyzed for their surface areas, as well as for volumes and widths of mesopores and micropores. Selected samples (based on increasing TOC content) with grain sizes of about 0.250 mm (i.e., 60 mesh) were chosen for additional analyses of micropore volumes. Pore size parameters were determined with a Micromeritics ASAP 2020 Surface Area and Porosity Analyzer. The adsorption of 69 N2 and CO2 gases on mudstone was used to quantify mesopore (2e 50 nm B, accessible to both gases) and micropore volumes (<2 nm B, accessible to CO2 only). Sample weights between 1 and 2 g are commonly used for coal and shale porosity studies (e.g., Chalmers and Bustin, 2007; Chalmers et al., 2012; Mastalerz et al., 2012). The classification of pore sizes follows that of the International Union of Pure and Applied Chemistry (Orr, 1977). Before exposure to either N2 or CO2, each mudstone sample was heated to w110  C in vacuum for w14 h to desorb gases and remove adsorbed moisture and volatiles. N2 gas adsorption in mudstone occurs at the temperature of liquid N2, whereas CO2 adsorption proceeds at 0  C. These measurements provided adsorption isotherms, calculated surface areas, pore volumes, and pore distributions based on multiple adsorption theories, i.e. Langmuir, BrunauereEmmetteTeller (BET), BarretteJoynereHalenda (BJH), DubinineRadushkevich (De R), and DubinineAstakhov (DeA), among others (Webb and Orr, 1997; Clarkson and Bustin, 1999). A detailed description of relevant theories and techniques can be found in Gregg and Sing (1982). 2.5. Total porosity and pore throat diameter Total porosity (vol. %), pore volume (Vp; cm3), grain volume (Vg; cm ), and grain density (rgrain) were obtained using helium (He) pycnometry on samples analyzed by the Core Laboratories facility (Houston, Texas). Total porosity was calculated from bulk (Vbulk) and grain (Vgrain) volumes. The total pore volume (Vt, cm3/g) was calculated as Vt ¼ (1/rbulk) (1/rgrain), where rbulk was calculated from sample weight and the bulk volume (Vbulk) from mercury (Hg) immersion, and rgrain was measured via He pycnometry (Cui et al., 2009) on bulk samples. During Hg immersion the bulk rock sample was submerged into Hg to obtain the total volume, without applied pressure. The total pore volume Vt was used to calculate the macropore volume, by subtracting the sum of the mesopore volume (cm3/g, measured by low-pressure N2 gas adsorption) and the micropore volume (cm3/g, measured by low-pressure CO2 gas adsorption) from the total pore volume (Vt, cm3/g). The distribution of pore throat diameter and Swanson permeability (mD; Swanson, 1981) were measured via mercury injection capillary pressure (MICP) by the Core Laboratories facility (Houston, Texas) on two samples only (#9, 11) using a Micromeritics Autopore 9320 highpressure Hg injection device. Apparent Hg injection volumes were corrected using a conformance factor determined for each sample from an evaluation of the apparent injection volume versus injection pressure. As an extremely non-wetting material, Hg must be forced with pressure to conform around and into surface features. The conformance value is the volume of Hg pressed into surface roughness and around sample edges after the penetrometer chamber is initially filled with Hg. This conformance volume is subtracted from all subsequent apparent injection volumes. 3 3. Results 3.1. Organic petrography and vitrinite reflectance The liptinite maceral group, including alginite (from phytoplankton), liptodetrinite (small fragments of likely algal origin), and amorphous organic matter (AOM), accounts for 70e95% by volume of OM on a mineral-free basis. Vitrinite (dominantly reworked) and inertinite are only a minor addition to the total maceral composition. Secondary OM is represented by solid bitumen that characteristically fills small (1e2 mm) pores in isolated (elongated, lensoidal or round) fine-grained zones rich in minerals (max. diameter 300  100 mm; Fig. 4A and B). Solid bitumen also occurs in association with carbonate minerals along grain contacts and is 70 A. Furmann et al. / Marine and Petroleum Geology 54 (2014) 65e81 occasionally micrinized. Mineral matter identified microscopically under reflected light includes carbonates, clay minerals, and mostly framboidal pyrite, although euhedral and massive forms of pyrite are also present. The composition of OM is relatively similar among the samples from the Belle Fourche and Second White Specks formations (Fig. 4). Quantitative maceral analysis of OM revealed 70e95 vol. % liptinite macerals (including alginite, AOM and liptodetrinite; Fig. 4). Solid bitumen typically ranges from 5 to 20 vol. % with the exception of sample #5 which contains 90 vol. %. In general, samples #15e20 in the lower part of the section contain more solid bitumen (13e20 vol. %) than samples #1e14 (4e10 vol. %). Vitrinite and inertinite together typically account for 1e2 vol. % and reach their maximum of 9 vol. % in sample #20. Vitrinite reflectance Ro values show a range between 0.74 and 0.87% (Table 1, Fig. 5). 3.2. Organic geochemistry and Rock-Eval pyrolysis Carbon (TOC and TC) and sulfur (TS) contents measured on bulk powdered rock samples via Eltra CS-2000 and data from Rock-Eval pyrolysis are summarized in Table 1 and displayed in Figures 6 and 7. The present day TOCpd concentrations range between 1.74 and 3.62 wt. %. The calculated corresponding original TOCo content (Jarvie et al., 2007) for equivalent immature rocks is 2.39e4.97 wt. % (Table 2). The representativeness of the examined section is indicated by the same general trend of TOC data of our 19 samples compared with the much more densely sampled data set of Greff and Cheadle (2012; Fig. 6). The C/S ratio, calculated as the elemental ratio of total organic carbon and total sulfur (TOC/TS), is between 0.56 and 1.57 (Table 1). The present-day HIpd (97e194 mg HC/g TOC; Table 2) is significantly lower compared with the original HIo (331e426 mg HC/g TOC) as a result of hydrogen depletion in kerogen during the partial transformation of kerogen into hydrocarbons. There is a weak positive correlation between TOC content and the hydrocarbon potential (based on Rock-Eval’s S2 values; R2 ¼ 0.60 by linear regression), but our data yield no significant correlation between TOC and HI. Only a very weak correlation with R2 ¼ 0.20 (linear regression) exists for the upper portion of the section (samples #1e14, Fig. 6) where HI generally follows TOC values. Figure 4. Photomicrographs of thick sections (pellets) in reflected (A, B, C) and fluorescent (D, E, F) light under optical microscope with oil immersion of polished mudstone samples from well 07-19-45-6W5. SB: solid bitumen in isolated zone; Py: pyrite; V: vitrinite; CT: carbonates; Fm: foraminifera; Ld: liptodetrinite; Ag: alginite. Table 1 Total organic carbon (TOC), total carbon (TC) and total sulfur (TS) contents, Rock-Eval pyrolysis results, mineral composition, and porosity data for samples from well 07-19-45-6W5. TC 1 2 3 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 4.88 4.27 6.05 9.85 5.62 8.25 5.27 4.93 3.64 2.71 2.74 2.94 3.39 8.00 5.94 4.01 3.97 3.47 3.05 Average: Range: 1794.5 1798.4 1805.6 1810.3 1813.7 1818.8 1821.7 1822.6 1823.7 1826.6 1833.3 1834.5 1840.9 1846.4 1848.9 1855.2 1860.1 1863.1 1869.8 2.98 2.68 3.32 1.74 3.37 2.04 3.54 2.60 3.18 2.22 2.01 2.48 2.78 3.62 3.35 3.15 2.58 3.27 3.41 TS 2.51 2.01 2.57 1.11 2.44 1.45 2.70 3.98 2.99 2.85 2.77 2.87 2.62 3.24 3.16 2.78 4.61 2.70 4.52 C/S ratio 1.19 1.34 1.29 1.57 1.38 1.41 1.31 0.65 1.06 0.78 0.73 0.87 1.06 1.12 1.06 1.13 0.56 1.21 0.75 Ro (%) 0.74 0.79 0.77 0.8 0.8 0.78 0.78 0.85 0.76 0.78 0.78 0.75 0.78 0.83 0.78 0.75 0.87 0.78 0.76 OI S1 Tmax ( C) HI (mg HC/ (mg CO2/ (mg HC/ g TOC) g TOC) g rock) S2 439 442 440 444 442 441 442 439 438 441 441 439 439 442 444 445 446 441 440 4.35 3.21 4.85 2.09 5.07 2.99 4.59 3.39 3.73 2.30 2.39 2.89 3.56 3.51 6.51 3.69 4.22 5.14 3.86 146 120 146 120 151 146 130 130 117 104 119 116 128 97 194 117 164 157 113 22 24 23 48 24 39 22 28 19 30 37 32 33 19 24 19 30 22 21 2.86 4.89 2.84 1.08 0.79 441.32 132.45 27.10 1.74e3.62 2.71e9.85 1.11e4.61 0.56e1.57 0.74e0.87 438e446 97e194 19e48 1.83 1.56 1.78 1.03 2.14 1.61 1.82 1.74 1.70 1.40 1.31 1.46 1.80 1.67 2.66 1.76 1.98 1.99 2.17 S3 Quartz Albite Calcite Dolomite Ankerite Illite (wt. %) 0.65 0.64 0.76 0.83 0.80 0.79 0.77 0.73 0.60 0.66 0.74 0.80 0.92 0.70 0.81 0.61 0.76 0.73 0.71 34 34 32 14 34 22 36 33 34 35 38 36 36 22 30 34 35 44 36 11 11 8 4 10 4 4 9 10 10 10 15 14 8 12 12 9 12 12 12 12 21 21 13 13 9 4 0 0 2 1 2 25 14 4 10 1 0 1.76 3.81 0.74 33 10 9 1.03e2.66 2.09e6.51 0.60e0.92 14e44 4e15 0e25 Kaolinite Chlorite Pyrite Porosity (vol. %) 3 3 3 44 3 36 4 12 3 2 1 1 1 0 0 0 4 1 0 0 0 1 0 1 0 0 9 1 1 0 0 0 0 0 0 0 0 0 28 31 24 12 28 18 34 21 36 36 34 33 33 29 32 35 25 27 27 4 5 5 2 6 3 6 6 8 7 7 5 5 8 6 7 6 6 10 6 0e44 1 0e9 29 6 12e36 2e10 3 1 1 1 1 1 2 2 3 3 4 5 4 2 1 3 4 4 3 4 3 5 2 4 3 5 5 5 5 4 4 4 5 5 4 7 5 12 2.1 2.5 1.7 2.5 4.4 3.2 2.7 2.5 5.0 3.0 4.1 4.3 3.5 2.9 2.6 3.3 2.2 2.9 2.0 2 1e5 5 3.0 2e12 1.7e5.0 A. Furmann et al. / Marine and Petroleum Geology 54 (2014) 65e81 Sample Depth TOC number (m) (wt. %) TOC e total organic carbon (wt. %); TC e total carbon (wt. %); TS e total sulfur (wt. %); C/S e total organic carbon (TOC) to total sulfur (TS) ratio; Ro e measured vitrinite reflectance (%); Tmax etemperature ( C) at the maximum of the S2 peak; HI e Hydrogen Index ¼ [(S2  100)/TOC] (mg HC/g rock); OI e Oxygen Index ¼ [(S3  100)/TOC] (mg CO2/g rock); S1 e volatile hydrocarbon (HC) content (mg HC/g rock); S2 e remaining HC generative potential (mg HC/g rock); S3 e carbon dioxide content (mg CO2/g rock). Sample #4 was not included. 71 Age Belle Fourche Formation Upper Cretaceous Period Cenomanian 93 Ma Colorado Group Second White Specks Formation A. Furmann et al. / Marine and Petroleum Geology 54 (2014) 65e81 Turonian 72 Sample Depth name (m) Ro (%) Maceral composition (vol. %) 0 10 20 30 40 50 1 1794.50 0.74 5 2 1798.40 0.79 3 3 1805.60 0.77 5 1810.25 0.80 6 1813.70 0.80 73 7 1818.75 0.78 76 8 1821.70 0.78 81 5 5 60 70 80 90 100 79 10 5 81 10 4 83 10 5 90 15 8 15 5 10 5 9 1822.60 0.85 3 10 1823.70 0.76 5 80 8 5 11 1826.55 0.78 8 75 10 5 12 1833.30 0.78 10 70 13 1834.50 0.75 14 1840.90 0.78 15 1846.40 0.83 16 1848.90 0.78 17 1855.20 0.75 18 1860.10 0.87 19 1863.10 0.78 20 1869.80 0.76 Alginite 15 63 8 20 10 AOM Other liptinite 10 10 15 15 49 10 20 64 10 4 17 64 8 63 3 10 20 63 5 10 15 64 8 8 15 65 5 6 10 73 Vitrinite + inertinite 5 9 5 13 20 Solid bitumen Figure 5. Maceral composition (vol. %) and measured vitrinite reflectance Ro (%) for 19 samples from well 07-19-45-6W5. Alginite, amorphous organic matter (AOM), and other liptinites belong to the liptinite group. Vitrinite and inertinite jointly represent terrigenous material in mudstone samples. Solid bitumen is present as secondary, residual organic matter after oil generation and partial expulsion. Selected biomarker distributions from samples #16 and 18 from the lower portion of the Belle Fourche Fm. include n-alkanes (m/ z ¼ 85), acyclic isoprenoids (m/z ¼ 183), and diasteranes (m/z ¼ 217) (Fig. 7). Geochemical indices for these samples are listed in Table 3. Analyses of the aliphatic F1 hydrocarbon fractions provided the following observations: (i) n-alkanes are present primarily in the C12eC40 range and exhibit a slight predominance of homologues with even carbon numbers (CPI > 1; Table 3) and greater abundances of homologues in the range from C12 to C26 (S1/S2 > 4; Table 3); (ii) acyclic isoprenoids occur in a range from C15 to C30 with a dominance of pristane (Pr, IP-C19) and phytane (Ph, IP-C20); (iii) diasteranes range from C27 to C30 with enhanced abundance of C28 diasterane (Table 3). Only trace amounts of hopanoids (m/ z ¼ 191) were detected with predominance of Tm (17a (H)-22, 29, 30-trisnorhopane). Therefore, the ratio of hopanes to steranes would be extremely low. 3.3. Mineralogy The mineral composition (by wt. %) and its changes over depth for samples from well 07-19-45-6W5 are presented in Table 1 and Figure 6, respectively. The shales are composed of clay minerals (illite, kaolinite, chlorite), quartz, feldspar (albite), carbonates (calcite, dolomite, ankerite), and pyrite. The selection of samples represents all identified lithofacies across the section (Fig. 3). The upper part of the core within the Second White Specks Fm. (depth range 1794e1823 m; samples #1e9) is generally more calcareous than the underlying Belle Fourche Fm., and includes two carbonate- rich horizons (mainly as carbonate cement) represented by samples #5 and 7. The lower part within the Belle Fourche Fm. (depth range 1823e1870 m; samples #10e20) is characteristically quartz- rich and clay-rich with low carbonate content (Bloch et al., 1999, 2002). Exceptions are samples #15 and 18 with higher contents of carbonates. Carbonate in sample #15 predominantly represents large shell fragments and abundant microfossils that are visible in the core, whereas carbonate in sample #18 reflects carbonate cement within sandy material as observed in thin-sections. The ternary mineral distribution diagram (Fig. 9A) reveals a general dominance of clay minerals mixed with quartz and albite. 3.4. Porosity Porosity measurements and investigations of pore-size distribution play important roles in the study of unconventional resources and contribute to a better understanding of storage and migration pathways of hydrocarbons within fine-grained rocks (O’Brien et al., 1996, 2002; Kuila and Prasad, 2011; Ross and Bustin, 2009; Slatt and O’Brien, 2011). Total porosity quantified via He porosimetry varies between 1.7 and 5.0 vol. % (Table 1) in our samples over depth (Fig. 6). Gas adsorption measurements with CO2 and N2 gases under low pressures yielded micro- and mesopore volumes (cm3/g) and surface areas (m2/g) (Table 4). The examples of adsorptionedesorption isotherms of N2 (Fig. 10A) all show hysteresis that is characteristic of Type IV isotherms (as per IUPAC classification; Sing, 1985). Samples #11 and 12 (Fig. 10A) indicate greater abundances of mesopores (more open hysteresis A. Furmann et al. / Marine and Petroleum Geology 54 (2014) 65e81 73 Figure 6. Geochemical parameters, mineralogy, and total porosity over depth for 19 samples from well 07-19-45-6W5. The gamma-ray log (GR) in GAPI units (Gamma-ray, American Petroleum Institute; Hoppie et al., 1994) is plotted on the left side. TOC data added from Greff and Cheadle (2012). Hydrogen Index (HI, mg HC/g TOC) A 1000 B TYPE I 1000 900 900 800 800 700 700 TYPE II 600 600 Immature Mature Oil TYPE I Window oil prone usually lacustrine Condensate - Wet Gas Zone micropore volumes. Macropores with diameters >100 nm cannot be measured with CO2 or N2 low-pressure gas adsorption techniques, and therefore macropore volumes were calculated via subtraction of the sum of micro- and mesopore volumes from total pore volumes. The ternary diagram of pore types distribution (Fig. 9B) shows a general dominance of micro- and mesopores over loop) and micropores (greater volume of gas adsorbed at P/ Po < 0.01) compared with samples #7 and 20. A greater gas volume uptake at P/Po near 1.0 indicates greater total porosity (Kuila and Prasad, 2011) in agreement with our porosimetry measurements. A comparison of samples #7 and 10 relative to samples #5 and 20 (Fig. 10B) shows that stronger CO2 adsorption relates to enhanced Postmature Dry Gas Window TYPE II oil prone usually marine Oil 500 500 400 400 Mixed TYPE II-III oil-gas-prone 300 300 200 Gas TYPE III 100 200 100 TYPE III gas-prone TYPE IV inert 0 0 10 20 30 40 50 60 70 80 90 100 Oxygen Index (OI, mg CO2 /g TOC) 0 400 425 450 475 500 Tmax( C) Figure 7. Modified van Krevelen diagrams showing the relationships (A) between the hydrogen index HI and the oxygen index OI of kerogen types; and (B) between the hydrogen indices and Tmax values of kerogen types. Rock-Eval data from 19 mudstone samples from well 07-19-45-6W5 are plotted. A. Furmann et al. / Marine and Petroleum Geology 54 (2014) 65e81 Table 3 Biomarker ratios and geochemical indicators for rock extracts. 25 45 C40 16 18 C36 C38 C32 35 C34 C24 C28 15 C30 m/z = 85 C12 55 65 Time (min) 35 30 B m/z = 217 C30S C27R C27S C28R1 C28R2 C28S C29R1 C29R2 C30R C29S Intensity 5 Sample no. Pr/Ph S1/S2 CPI R22 index Diasteranes (vol. %)a A C26 C22 Ph C20 C17/ Pr C18 C14 74 Time (min) 40 macropores in terms of vol. %. The resultant micro-, meso-, and macropore volumes and corresponding percentages of the total pore volumes are illustrated in Figure 11. Most pores in our set of mudstone samples are mesopores (2e50 nm B) and on average represent 49 vol. % (range 34e67 vol. %) of the total pore volume. Less abundant micropores (<2 nm B) account for 34 vol. % on average (range 6e60 vol. %) of the total pore volume. Macropores average around 17 vol. % and account for as much as 57 vol. % of the total pore volume in sample #7, but were undetectable in some other samples. A comparison of ternary distribution diagrams illustrating micro-, meso, and macropore volumes as percentages of Table 2 Transformation ratio TRHI of kerogen into hydrocarbons based on the original hydrogen index HIo (calculated) and present day HIpd (measured by Rock-Eval) and original TOCo calculated from present day TOCpd obtained from measurements on Eltra CS-2000. All calculations are based on algorithms provided by Jarvie et al. (2007). TRHI (%) HIo HIpd 4.6 4.9 1.4 1.0 1.3 1.0 C28 C29 21 22 47 43 32 35 MPI 1 MPI 2 0.47 0.49 0.57 0.57 Pr/Ph e pristane/phytane (ten Haven et al., 1987). P P S1 =S2 ¼ ðn C12 n C26 Þ ðn C27 n C40 Þ: CPI e carbon preference index, based on n-alkanes: P CPI ¼ 0:5  ½ ðn C25 n C33 Þodd Š þ P P ½ ðn C23 n C31 Þodd Š=½ ðn C26 n C34 Þeven Š: R22 index (based on n-alkanes; ten Haven et al., 1988) R22 ¼ 2  n-C22/(n-C21 þ nC23). MPI e methylphenanthrene indices (thermal maturity indicators; Radke and Welte, 1981): MPI 1 ¼ 1:5ð2 MP þ 3 MPÞ=ðP þ 1 MP þ 9 MPÞ; MPI 2 ¼ 3ð2 MPÞ=ðP þ 1 MP þ 9 MPÞ; where P ¼ phenanthrene and 1-MP, 2MP, 3-MP, and 9-MP are the 1-, 2-, 3-, and 9-methylphenanthrenes, respectively. a A proportion of diasteranes represented by the volumetric percent calculated based on the sum of the peak area within a certain group of homologues from C27 to C29. 45 Figure 8. Mass chromatograms showing distributions of n-alkanes (m/z ¼ 85) and acyclic isoprenoids (m/z ¼ 183) presented in (A), and diasteranes (m/z ¼ 217) in (B) for sample #16 from the lower portion of the Belle Fourche Fm. Sample number 1.6 1.7 C27 TOCo (mg HC/g TOC) (wt. %) TOCpd 1 2 3 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 75 80 75 79 73 71 78 76 80 83 78 79 77 81 60 75 65 68 73 424 426 424 405 408 376 421 395 421 421 399 399 399 379 376 357 361 375 331 146 120 146 120 151 146 130 130 117 104 119 116 128 97 194 117 164 157 113 4.06 3.72 4.60 2.39 4.60 2.60 4.97 3.46 4.46 3.05 2.65 3.32 3.74 4.95 4.33 4.10 3.25 4.27 4.36 2.98 2.68 3.32 1.74 3.37 2.04 3.54 2.60 3.18 2.22 2.01 2.48 2.78 3.62 3.35 3.15 2.58 3.27 3.41 Average: Range: 75 60e83 394 331e426 132 97e194 3.84 2.39e4.97 2.86 1.74e3.62 total porosity (Fig. 9B) and mineral compositions (Fig. 9A) suggests associations between pore sizes and mineral composition. Macropore volumes correlate better with total pore volumes (R2 ¼ 0.74) than with micro- or mesopore volumes (Fig. 12) and seem to be mostly responsible for changes in total porosity. No positive correlation was observed for the entire set of samples between TOC and total pore volume, as well as for TOC and micropore volume based on porosity measurements on samples ground to 4e7 mesh and 60 mesh grain size (Fig. 13). Pore-throat size distributions determined by MICP were measured on samples #9 and 11 (Fig. 14). MICP results indicated that both samples contain mesopores, but only sample #9 showed evidence for macropores. The combination of He porosimetry and low-pressure gas adsorption techniques did not indicate the presence of macropores in sample #11 because the sum of microand mesopore volumes (derived from low-pressure gas adsorption) exceeded the total pore volume measured by He porosimetry. Similar situations for samples #3, 5, 8, 9, 18, and 20 suggest that micro- and mesopores alone account for total pore volumes, which implies the near-absence of macroporosity. This apparent discrepancy is rooted in the application of different methodologies (MICP, low-pressure gas adsorption, and He porosimetry) to jointly assess rock porosity in spite of imperfect compatibility of methods. The MICP-derived permeability measurements on samples #9 and 11 show values of 3.42$10 5 and 3.32$10 5 mD (Fig. 14), respectively, confirming the tight, low-permeability character of the rocks. Mudstones containing quartz plus feldspar above a threshold of 65 wt. % commonly express higher permeability on the order of 10 3 mD than samples below the threshold with permeability between 1$10 3 and 6.5$10 7 mD (Chalmers and Bustin, 2012). The bulk quartz plus albite content (either represented by grains, cements, micro- to macrofossils, etc.) in our samples is typically <56 wt. % in agreement with observed low permeability. 4. Discussion 4.1. Characterization of the hybrid source rock/reservoir formations The present day TOCpd concentrations between 1.74 and 3.62 wt. % indicate good to excellent organic richness (Peters, 1986). Organic matter in all mudstone samples is classified as marine kerogen Type II based on the prevalence of liptinites and limited input of terrestrial material. Although we cannot directly determine A. Furmann et al. / Marine and Petroleum Geology 54 (2014) 65e81 A B Quartz + Albite 90 80 80 19 40 (12,13,14) 20 (1,2,6) 18 50 9 8 60 3 16 40 15 30 20 70 30 60 10 90 20 50 (10,11,17) 7 20 Micropores 10 70 75 30 60 20 40 3 50 15 5 16 8 9 60 2 11 12 18 19 70 6 17 1 14 13 50 40 70 30 80 5 20 90 10 10 10 80 90 7 90 80 70 60 Carbonates 50 40 (wt. %) 30 20 90 10 Clays 80 70 Macropores 60 50 40 (vol. %) 30 20 10 Mesopores Figure 9. Ternary distribution diagrams illustrating (A) mineral composition (wt. %) and (B) pore size distribution (vol. %) for 19 samples from well 07-19-45-6W5. Open circles represent data for samples from the Second White Specks Fm.; filled circles e data from the Belle Fourche Fm. the origin of the AOM, the presence of marine alginite and marine planktonic microorganisms (foraminifera; Caldwell et al., 1978; Strong, 1972) strongly suggests that the AOM is also composed of marine OM and likely represents microbially reworked algal material. The predominance of short-chain n-alkanes (S1/S2 > 4; Table 3 and Fig. 7A) indicates a mainly phytoplanktonic source of OM in samples #16 and 18 (Blumer et al., 1971). The greater cumulative abundance of C28-diasterane homologues compared with the sum of C27- and C29-diasterane homologues indicate a marine paleoenvironment with a highly productive photic zone (Grantham and Wakefield, 1988; Schwark and Empt, 2006). Marine settings are also indicated by the presence of C30-diasterane homologues producing ions with mass 414 (Moldowan, 1984, Fig. 7B). The Pr/Ph ratio of about 1.65 suggests oxic water column conditions during deposition (ten Haven et al., 1987), but we note that a similar range of Pr/Ph ratios from Eocene organic-rich shales in the Beibuwan Basin was interpreted in terms of a less oxic to dysoxic depositional environment (Huang et al., 2013). The R22 index below 1.5 (Table 3) does not indicate hypersaline conditions (ten Haven et al., 1988). The C/S ratio (TOC/TS) in a range 0.56e1.57 is considered to be indicative of a marine depositional paleoenvironment as well, based on a concept provided by Berner and Raiswell (1984), where the C/S ratio is used as a general proxy for distinguishing ancient marine from freshwater sedimentary rocks. The plots of modified van Krevelen diagrams in Figure 7 are consistent with petrographic observations (Figs. 4 and 5) and also characterize OM as primarily marine with partial biodegradation. The relatively narrow range of C/S ratios (0.65e1.57; Table 1) for samples #1e9 within the Second Table 4 Pore volumes (V, cm3/g) and surface area (SA, m2/g) measured by gas adsorption for 19 samples from well 07-19-45-6W5. Total and macropore volumes were calculated as described in methods Section 2.5. Sample number He porosimetry CO2 gas adsorption N2 gas adsorption Total pore volume Vt cm3/g LMV micropores cm3/g MSA micropores m2/g BJH AV mesopores cm3/g BET SA mesopores m2/g Calculated V macropores cm3/g 1 2 3 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 0.0082 0.0098 0.0065 0.0096 0.0176 0.0122 0.0108 0.0093 0.0200 0.0113 0.0161 0.0171 0.0141 0.0116 0.0105 0.0134 0.0090 0.0118 0.0075 0.0024 0.0034 0.0035 0.0043 0.0047 0.0007 0.0047 0.0037 0.0022 0.0037 0.0051 0.0042 0.0036 0.0053 0.0045 0.0041 0.0029 0.0038 0.0045 7.3 5.3 4.9 2.7 5.4 9.8 6.3 4.1 9.8 7.8 7.9 8.1 6.7 5.5 5.8 6.6 5.4 5.4 3.2 0.0055 0.0051 0.0030 0.0052 0.0059 0.0045 0.0061 0.0056 0.0071 0.0076 0.0081 0.0073 0.0069 0.0040 0.0045 0.0071 0.0060 0.0056 0.0030 1.9 1.8 2.3 1.6 1.8 1.1 2.3 1.8 2.4 2.9 2.8 2.7 2.2 2.1 1.5 2.4 2.6 1.6 0.8 0.0004 0.0013 0.0000 0.0000 0.0070 0.0069 0.0000 0.0000 0.0107 0.0000 0.0029 0.0056 0.0037 0.0023 0.0014 0.0022 0.0000 0.0024 0.0000 Average: Range: 0.0119 0.0065e0.0200 0.0038 0.0007e0.0053 6.2 2.7e9.8 0.0057 0.0030e0.0081 2.0 0.8e2.9 0.0025 0.0000e0.0107 Vt e total pore volume; LMV e DubinineAstakhov: limiting micropore volume; MSA e DubinineRadushkevich: micropore surface area; BJH AV e BarreteJoynereHalenda adsorption cumulative volume of pores between 2.0 and 50.0 nm width; BET SA e Brunauer, Emmett and Teller surface area; calculated V (volume) macropores e explained in methods Section 2.5. A B 6 Surface area: #11 (2.88 m /g) #12 (2.76 m /g) #7 (1.11 m /g) #20 (0.83 m /g) 5 4 3 2 1 0 0 0.2 0.4 0.6 0.8 1.0 Quantity of CO2 Adsorbed (cm³/g STP) A. Furmann et al. / Marine and Petroleum Geology 54 (2014) 65e81 Quantity of N2 Adsorbed (cm³/g STP) 76 0.7 Micropore surface area: #10 (9.84 m2/g) #7 (9.74 m2/g) #20 (3.24 m2/g) #5 (2.69 m2/g) 0.6 0.5 0.4 0.3 0.2 0.1 0 0 0.005 Relative Pressure (P/Po) 0.010 0.015 0.020 0.025 0.030 Relative Pressure (P/Po) Figure 10. (A) Adsorptionedesorption isotherms of N2 at the temperature of liquid N2 (77.3 K), and (B) adsorption isotherms of CO2 gas for two samples with the lowest and two samples with the highest surface areas for mesopores (based on the Brunauer, Emmett and Teller formula) and micropores (DubinineRadushkevich formula), respectively. STP ¼ standard temperature and pressure. variance of Tmax among samples (Fig. 6) may be related to differences in proportions of individual macerals, whereas variations of Ro (Fig. 5) may be related to mineralogical differences, to depositionally induced maturation of vitrinite (Goodarzi et al., 1993; Hutton and Cook, 1980; Jones et al., 1971), and to analytical uncertainty due to the limited number of vitrinite particles and number of Ro measurements available. The absence of a strong correlation between Tmax and Ro suggests the influence of different factors causing variations in the two maturity parameters. Biomarkers such as methylphenanthrene indices MPI 1 and MPI 2 (Table 3) are established thermal maturity indicators and suggest the same level of maturity (Radke and Welte, 1981). Tabulated Rock-Eval data that had been previously measured on Percentages of total porosity 0 20 40 60 80 Pore volume (cm3/g) 100 0.0000 1794.50 1 2 1798.40 2 3 1805.60 3 5 1810.25 5 6 1813.70 6 7 1818.75 7 8 1821.70 8 9 1822.60 9 10 1823.70 10 11 1826.55 11 12 1833.30 13 1834.50 14 1840.90 15 1846.40 16 1848.90 16 17 1855.20 17 18 1860.10 18 19 1863.10 19 20 1869.80 20 macropores (0-57 vol. %) 1 mesopores (34-67 vol. %) Belle Fourche Formation Period Age Sample Depth number (m) micropores (6-60 vol. %) Turonian Colorado Group Second White Specks Formation 93 Ma Cenomanian Upper Cretaceous White Specks Fm. and the strong positive correlation between TOC and TS contents (R2 ¼ 0.96) in these samples suggest incorporation of sulfur into reactive OM (Zaback et al., 1993) during an oceanic anoxic event (Arthur and Schlanger, 1979; Arthur et al., 1987; Jenkyns, 1980; Schlanger and Jenkyns, 1976; Schlanger et al., 1987) with elevated productivity (Pedersen and Calvert, 1990) at the CenomanianeTuronian boundary. Overall, geochemical and petrographic classification of OM as kerogen Type II corresponds well with previous interpretations of the depositional paleoenvironment of the Second White Specks Fm. (Bloch et al., 1999, 2002). The Rock-Eval thermal maturity indicator Tmax (438e446  C) and vitrinite reflectance values (Ro 0.74e0.87%) indicate the midmature OM within the oil window for the entire section. The 0.0050 0.0100 0.0150 0.0200 12 13 14 15 LMV micropores BJH AV mesopores Calculated V macropores Figure 11. Pore size distribution of micro-, meso-, and macropores (vol. %) over depth in mudstone samples from well 07-19-45-6W5. LMV e DubinineAstakhov: limiting micropore volume; BJH AV e BarreteJoynereHalenda adsorption cumulative volume of pores between 2.0 and 50.0 nm width; calculated V (volume) macropores e explained in methods Section 2.5. Note the general larger pore volume (particularly of macropores) in the Belle Fourche Fm. relative to the Second White Specks Fm. Total pore volume V t (cm 3/g) 0.012 0.010 R² = 0.74 0.008 LMV micropores BJH AV mesopores 0.006 Calculated V macropores R² = 0.45 0.004 Linear (BJH AV mesopores) 0.002 Linear (Calculated V macropores) Total pore volume Vt (cm3/g) A. Furmann et al. / Marine and Petroleum Geology 54 (2014) 65e81 0.0250 77 A 0.0200 0.0150 0.0100 0.0050 0.0000 0.000 0.000 0 0.005 0.010 0.015 0.020 1 0.025 4 3 4 3 4 Micropore volume (cm 3/g) B 0.006 0.005 0.004 0.003 4-7 mesh grain size 0.002 0.001 0.000 0 1 2 TOC (wt. %) 0.014 Micropore volume (cm3/g) fresh core samples (Alberta Geological Survey Open File Reports, 2008e11) show the same HI range as measured in our study (w100e200). In contrast, the former OI range of 4e9 is much lower compared with our new OI range of w20e50. It is possible that oxidation of the core during long-term storage since drilling in 1979 has caused the increase in oxygen index, or the earlier measurements were in error. Regardless of the reason, the new OI data plot closer to the range typical for kerogen Type III (Fig. 8). The Second White Specks Fm. has generated and expelled hydrocarbons into adjacent reservoirs in the geologic past. Consequently, Rock-Eval S2 peaks are small (2.09e6.51 mg HC/g rock) and classify the hydrocarbon potential as mostly poor to good. A weak correlation between TOC and HI is consistent with an expulsion of hydrocarbons from source rocks. Once inside the oil window, primary cracking converted 60e83 wt. % of the kerogen into hydrocarbons (Table 2). Most hydrocarbons were subsequently expelled as oil and early gas, whereas the residual, least mobile hydrocarbon fraction was trapped in open spaces as solid bitumen forming a secondary maceral (Jacob, 1989; Landis and Castaño, 1995). The relatively abundant solid bitumen in our samples (5e20 vol. %, Fig. 5) agrees with earlier suggestions that oil generation in the Second White Specks Fm. may have occurred west of 115 longitude in southern Alberta (Bloch et al., 1999; Creaney and Allan, 1992; Macauley, 1984a), including the area around well 07-19-456W5 (Fig. 1). The residual 17e40 wt. % of kerogen is the basis for the remaining hydrocarbon potential. The MICP-derived permeability data (3.37$10 5 mD on average) confirm the tight, low-permeability character of the rocks and underscore the necessity of hydraulic fracturing during hydrocarbon production. The brittleness index for the Second White Specks Fm. averaged 47% with a range of 39e61%. The Belle Fourche Fm. averaged slightly lower at 42% with a range from 25 to 46%. These values indicate good brittleness for both formations. Total pore volumes and macropore-sized porosity are larger for the Belle Fourche Fm. compared with the Second White Specks Fm. (Table 4 and Fig. 11). The average macropore volume for the Belle Fourche Fm. was 0.0028 cm3/g, whereas the Second White Specks Fm. measured only 0.0019 cm3/g. These differences in pore volumes suggest that the upper part of the Belle Fourche Fm. (samples #10e 14 on Fig. 11) is potentially a better hydrocarbon reservoir due to larger porosity. The larger proportion of macropores likely enhances permeability in quartz- and clay-rich sediments (Medina et al., 2011). 3 0.007 Pore volume (cm 3/g) Figure 12. Cross plot of total pore volume and volumes of micro-, meso-, and macropores for 19 mudstone samples from well 07-19-45-6W5. LMV e DubinineAstakhov: limiting micropore volume; BJH AV e BarreteJoynereHalenda adsorption cumulative volume of pores between 2.0 and 50.0 nm width; calculated V (volume) macropores e explained in methods Section 2.5. All correlations are represented by linear regressions. 2 TOC (wt.%) C 0.012 0.010 0.008 0.006 60 mesh grain size 0.004 0.002 0.000 0 1 2 TOC (wt. %) Figure 13. Cross plot of TOC content (wt. %) with (A) total pore volume (Vt; cm3/g); (B) micropore volume (cm3/g) measured on 4e7 mesh grain size; and (C) micropore volume (cm3/g) measured on 60 mesh grain size samples. 4.2. Impact of organic matter and mineral composition on porosity Changes in thermal maturation of OM have been suggested as a cause for development of porosity in mudstones due to the conversion of OM to gaseous and liquid hydrocarbons (e.g., Curtis et al., 2012; Jarvie et al., 2007; Loucks et al., 2009; Mastalerz et al., 2013; Modica and Lapierre, 2012). However, the constant level of thermal maturity across the studied profile (Table 1) excludes maturity as an important factor. Vertical changes in porosity along the section are likely due to variations in organic and mineral composition. Although some studies have documented enhanced total porosity with increasing OM content (Haynes and Naidu, 1998; Mastalerz et al., 2012; Ross and Bustin, 2009), such a relationship is not observed for our suite of samples due to the narrow range of TOC contents. Also, no positive correlations were observed for TOC content versus micropore volume measured on 4e7 mesh and 60 mesh grain fractions (Fig. 13). Reducing the grain size from 4e7 mesh to 60 mesh doubled the pore volume as a greater surface was exposed to the penetrating CO2 gas. Mudstones with a strong 78 A. Furmann et al. / Marine and Petroleum Geology 54 (2014) 65e81 Meso Macro Incremental Pore Space (fraction) 0.15 3.32 .10-5 mD 0.10 sample #9 3.42 .10-5 mD sample #11 0.05 0.00 1 10 100 1000 10000 100000 1000000 Pore Size (nm) Figure 14. MICP-derived pore size distributions and Swanson permeability for sample #9 from the Second White Specks Fm. and sample #11 from the Belle Fourche Fm. (1822.60 m and 1826.55 m depth, respectively) in well 07-19-45-6W5. correlations mainly to the relatively homogenous mineral composition. The situation is exacerbated by the narrow ranges of mineral concentrations among samples for each mineral group. Additionally, all samples contain solid bitumen (Fig. 5) as a testimony to primary cracking of kerogen to oil. The presence of solid bitumen causes porosity reduction (Bernard et al., 2012; Loucks et al., 2009; Vandenbroucke and Largeau, 2007) and is especially visible in samples #15e20 of the Belle Fourche Fm. (Fig. 6). The presence of solid bitumen/pyrobitumen has a variable effect on different pore size fractions (from 1 to 50 nm; Bernard et al., 2012). A future study of rocks from the Second White Specks and Belle Fourche formations should specifically include samples from different maturity zones with a wider range of TOC values and more diverse mineral compositions to help analytically deconvolute the roles of various parameters on porosity during thermal maturation. 5. Conclusions correlation between OM content and micropore volume are usually richer in OM than the sediments studied here. Perhaps OM must exceed a certain concentration threshold or represent a wider range in order to contribute significantly to the total porosity (Chalmers and Bustin, 2007; Clarkson et al., 2013; Ross and Bustin, 2009; Stra˛ po c et al., 2010). The lack of correlation between TOC and meso- or macropore volume suggests that the OM contribution to mesopores and macropores is either very low, or that other factors (e.g., mineral pores or matrix porosity) obscure the OM influence on porosity. Combining the TOC and clay mineral contents did not result in a strong positive correlation with the micropore volume either (R2 w 0.24). Based on the fact that in this study neither maturity nor OM content is main factors influencing porosity, we concluded that the mineral composition must exert main control over porosity changes and pore size distribution. Scanning electron microscopy (SEM) has been widely used to document the presence of intraparticle and interparticle pores within and among minerals (e.g., Loucks et al., 2012; Slatt and O’Brien, 2011; Tian et al., 2013). Numerous studies have stressed the importance of clay minerals for mudstone porosity (Javadpour, 2009; Loucks et al., 2009; Kuila and Prasad, 2011; Chalmers and Bustin, 2012) and microporosity (Mastalerz et al., 2012). However, a cross-plot of total porosity and the contents of mineral groups (i.e. quartz þ albite, clays, and carbonates) for our set of samples does not yield strong correlations, in spite of a tendency of slightly increasing total porosity with increasing concentrations of clay minerals, quartz and albite (Fig. 15). We attribute our sample set’s inability to yield significant Mineral content (wt. %) 70 60 Quartz+Albite 50 R² = 0.03 Clays 40 Carbonates R² = 0.15 30 Linear (Quartz+Albite) 20 Linear (Clays) 10 0 0 1 2 3 4 5 6 Total porosity (vol. %) Figure 15. Cross plot of total porosity (vol. %) and mineral content (wt. %) for 19 samples from well 07-19-45-6W5. All correlations are represented by linear regressions. Representative mudstones across a depth interval from 1793.5 m to 1871.0 m (77.5 m thick) from the Upper Cretaceous Second White Specks and Belle Fourche formations in central Alberta were analyzed to evaluate their potential as emerging hybrid source rock/reservoir formations. Organic petrography, bulk geochemistry, biomarkers, mineralogy, and porosimetry provide insights into the depositional paleoenvironment, mineralogical heterogeneity, maturity, and remaining hydrocarbon potential. The two lithologically different units of dark gray to black pyritic mudstones exhibit different carbonate contents, abundant silty and/or calcareous laminations, and occasional ripples, calcareous shells of bivalves, fish bones, and fish scales. Organic matter is dominantly kerogen Type II of marine origin with limited contributions of terrigenous organic components (mainly 1e2% by volume on a mineral matter-free basis). This petrographic result agrees with characteristics obtained from RockEval data and highlights the importance of combining both techniques when evaluating reservoir and source rock characteristics of organic-rich mudstones. The liptinite maceral group, including alginite, liptodetrinite, and amorphous organic matter, accounts for 70e95 vol. % of total organic matter on a mineral matter-free basis. Abundant solid bitumen in some horizons (e.g., samples #5, 15e20) and the estimated 60e83% transformation ratio of kerogen to hydrocarbons indicate primary cracking of kerogen into oil followed by limited expulsion. High transformation ratios explain the relatively poor remaining hydrocarbon potential of 2.09e6.51 mg HC/ g rock. Rock-Eval data indicate good to excellent organic richness based on present-day TOCpd content between 1.74 and 3.62 wt. %. Both Rock-Eval (Tmax 438e446  C) and petrographic-derived (Ro 0.74e 0.87%) thermal maturity parameters indicate a mid-mature character of the source rock across the entire section, which is comparable with a position within the oil window. The potential for the presence of in-situ liquid hydrocarbons in these formations is suggested by the relatively high content of marine organic matter, oil window maturity, low permeability (3.37$10 5 mD on average), a total porosity from 2 to 5 vol. % (average 3 vol. %), and a total pore volume between 0.0065 and 0.0200 cm3/g. The upper Belle Fourche Fm. has better reservoir properties compared to the calcareous mudstones of the Second White Specks Fm. due to larger porosity and more abundant macropores (>50 nm B). The calculated brittleness index in the Belle Fourche Fm. (42% on average) is only slightly lower than in the Second White Specks Fm. (47% on average) and indicates good brittleness across the entire section (Jarvie et al., 2007). The slightly elevated brittleness of the Second White Specks Fm. may be due to its higher carbonate content. A. Furmann et al. / Marine and Petroleum Geology 54 (2014) 65e81 The total pore volume shows a stronger correlation with macroporosity (R2 ¼ 0.74) than with micro- and mesoporosity suggesting that macropores are mostly responsible for changes in total porosity within the section. However, the volumetric contribution mainly relies on meso- and micropores (49 vol. % and 34 vol. % on average, respectively), ahead of macropores (average around 17 vol. %). The absence of strong correlations between porosity (pore volume) and organic matter content or mineral composition among the samples of the studied core is being attributed to the lack of strong variances in (i) TOC contents (i.e. relatively low concentrations and narrow range of TOC values), (ii) organic matter type (i.e. uniform kerogen Type II), and (iii) constant thermal maturity (i.e. in the oil window), and perhaps (iv) relatively narrow ranges of mineral contents within designated mineral groups of studied rock samples. Therefore, the complex controls on porosity and pore size distribution are difficult to deconvolute in the set of samples expressing limited compositional variance. To resolve these issues, a future study of rocks from the Second White Specks and Belle Fourche formations should specifically include samples spanning wider ranges of maturity, OM characteristics, and mineral composition to improve our understanding of the influences of maturity, OM characteristics, and mineral contribution on the development of porosity. Acknowledgments Funding for this research was provided by the Tight Oil Consortium that had been initiated by Chris Clarkson. This project was also partially supported by the U.S. Department of Energy, Basic Energy Sciences, Grant No. DE-FG02-11ER16246. Additional financial support was received from an ExxonMobil Global Geoscience Recruiting Grant 2011 for A. Furmann’s research. We thank N. Zajac for assistance with the stratigraphy of the Second White Specks and Belle Fourche formations. References Alberta Geological Survey, 2008. Open File Reports 2008e11. http://www.ags.gov. ab.ca/publications/pubs.aspx?series¼ofr. 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