SPE 167031

Vitrinite Reflectance Versus Pyrolysis Tmax Data: Assessing Thermal Maturity in Shale Plays with Special Reference to the Duvernay Shale Play of the Western Canadian Sedimentary Basin, Alberta, Canada Raphael A.J. Wust, TRICAN Geological Solutions, Calgary, AB, T2E 2M1, Canada, email: rwust@trican.ca; and SEES, JCU, 4811 Townsville, QLD, AUS Paul C. Hackley, USGS, MS 956 National Center, Reston, VA 20192, USA Brent R. Nassichuk, Nicole Willment, Ron Brezovski; TRICAN Geological Solutions, Calgary, Canada

Copyright 2013, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Unconventional Resources Conference and Exhibition-Asia Pacific held in Brisbane, Australia, 1113 November 2013. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.

Abstract

In unconventional, self-sourced sedimentary rocks, organic matter type and maturity and therefore the hydrocarbon production potential, are the most critical parameters when evaluating unconventional hydrocarbon resources. Several methods exist that determine the maturity level of sedimentary rocks and the organic matter. Organic maturity is commonly determined by vitrinite reflectance (%Ro). Vitrinite is a type of maceral that is derived from higher order plants. In rock with little or no vitrinite, bitumen or other organic matter type reflectances are measured and calculated to a normalized reflectance value (%Ro). Measuring vitrinite/bitumen reflectance is time-consuming and subject to the interpretation of the analysts. Alternatively, organic matter type and maturity are also measured using Rock Eval or equivalent pyrolysis techniques. The temperature (Tmax) at which thermal cracking of heavy hydrocarbons and kerogen reaches the maximum depends on the nature and maturity of the kerogen and indicates the level of thermal maturity. Pyrolysis results are independent of an operator although the data output may still require validation. In order to compare data from these two techniques, a study from the Barnett in 2001 produced a conversion formula to calculate %Ro from Tmax data. The conversion formula (calculated Ro = 0.0180 x Tmax - 7.16) has been used extensively in basins worldwide despite the fact that the correlation was produced for the Barnett shale. Here we present new maturity data (>100) (%Ro and Tmax) within the Duvernay Formation in Alberta, Canada, which is compared to data using the conversion formula. The Duvernay Formation of the Western Canada Sedimentary Basin is an Upper Devonian (~360 Ma) source rock which has been praised as one of the most promising oil/gas resource plays in Canada. Since late 2009, land sale activity has seen over $1.4 Bn spent in Alberta with land purchases focused in the Pembina and Kaybob areas. The total organic carbon (TOC) content of the Duvernay Formation can exceed 20 wt% in areas of low maturity but on average, the dark shales have TOC contents ranging between 4-11 wt%. TOC is a key indicator of hydrocarbon generation potential. In this study, we discuss the details of both analytical techniques, findings of the organic petrography, bitumen reflectance data and corresponding Tmax data. The data is also compared to calculated Ro values and problems using the formula are highlighted. In addition, the data is put into perspective of production information and the hydrogen-generative models (initial production data). The results show that inherent problems are manyfold and conversion calculations should be avoided in new formations where a conversion formula has not been established. Introduction

Over the last decade, exploration of shale gas/oil has increased multifold. Shale gas refers to unconventional, self-sourced hydrocarbon resources from sedimentary fine-grained rocks, such as silt-, mudstones and shales (carbonates and siliciclastics) (National Energy Board, 2009). These rocks are rich in organic carbon and are tight and thus self-sourcing hydrocarbon reservoirs (hydrocarbons formed within formation and trapped due to the tightness of the rock), although some may contain gas/oil migrated from other formations during burial and diagenesis. Most of the gas/oil is thermogenically generated (with occasional small amounts of biogenic gas) and stored as free, adsorbed (clays, organics) and solution gas. The critical factors for hot unconventional plays

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are organic richness, lithological composition and thickness, thermal maturity, pressure and depth and fracturing characteristics.

Of all these parameters, type and organic maturity of organic matter and therefore the hydrocarbon production potential is the most critical when evaluating unconventional hydrocarbon resources. Several methods exist that determine the maturity level of sedimentary rocks and their organic matter, including vitrinite reflectance (e.g. Sweeney and Burnham, 1990), pyrolysis (e.g. Espitali 1986), fluorescence alteration of multiple macerals (FAMM; e.g. Lo et al, 1997), thermal alteration index (e.g. Staplin, 1982), time temperature index (e.g. Lowrie et al. 1996), conodont alteration index (e.g. Deaton et al. 1996) and clay mineral crystallinity (e.g. Kbler, 1967; Aparicio and Galan, 1999). Some other methods have also been developed and tested to determine the level of organic maturity, but vitrinite reflectance (%Ro) and pyrolysis (C Tmax) remain the most common methods utilized.

Vitrinite reflectance allows for the identification of thermal maturity in sedimentary basins as vitrinite is sensitive to temperature (~ between 60-120C). Vitrinite is a type of maceral that is derived from higher order plants. In rock with little or no vitrinite, bitumen (or other organic matter type) reflectance is measured and is corrected to an equivalent reflectance value (%Ro). The reported Ro is a single number (average) but the data almost always represents a range in measured reflectance values. Measuring vitrinite/bitumen reflectance is time-consuming and subject to instrument (photomultiplier) quality, the volume of organic material to analyze and the expertise of the analyst.

Alternatively, organic matter type and organic maturity is also measured using Rock Eval or equivalent pyrolysis techniques (Espitali, 1986). The temperature (Tmax) at which thermal cracking of heavy hydrocarbons and kerogen reaches the maximum depends on the nature and maturity of the kerogen and corresponds to its thermal maturity level. In order to compare data from these two techniques, a study from the Barnett in 2001 (Jarvie et al., 2001) produced a conversion formula to calculate %Ro from Tmax data. The conversion formula (calculated Ro = 0.0180 x Tmax - 7.16) has been used extensively in basins around the world with various ages and lithologies. Here we present new maturity data (%Ro and Tmax) for the Duvernay Formation in Alberta, Canada, and determine if a Barnett Shale based formula can be applied to determine thermal maturity of these rocks.

The Duvernay Formation of the Western Canada Sedimentary Basin is an upper Devonian (~360 Ma) source rock and has been praised as one of the most promising oil/gas resource plays in Canada. Since late 2009, land sale activity has seen over $1.4 Bn spent in Alberta with land purchases focused in the Pembina and Kaybob areas. The Duvernay interval is a unique depositional unit within the Woodbend Group (Fowler and Stasiuk, 2001; Stoakes and Creany, 2011). The conditions resulting in the deposition of the Duvernay Formation signalled a profound change in the basin. Deposition of the Duvernay sequence is characterized by extensive basinal deposits, synchronous with a significant stage of Leduc reef growth (Middle Leduc) similar to the underlying Majeau Lake interval (Fig. 1). The Duvernay Formation consists of dark brown bituminous shale and limestone and represents a period of extended sediment accumulation and preservation of organic carbon. The high organic carbon content reflects a major change in the stratification and oxygenation of basinal waters during the maximum transgressive stage of the Woodbend. Adjacent to the Leduc reef complexes, the Duvernay is thick and intermixed with reef-derived detritus and was deposited within the protected Leduc embayments and beneath the Grosmont shelf complex (Fig. 2). Basinward from the reefs, Duvernay basin-fill thins markedly.

Fig. 1: Schematic cross-section showing reef build-up and basinal deposits during the Devonian in Alberta, Canada. Adapted from Fig. 12.10 of the Geological Atlas of the Western Canada Sedimentary Basin, http://www.ags.gov.ab.ca/publications/wcsb_atlas/a_ch12/ch_12.html.

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The total organic carbon of the Duvernay Formation can exceed 20 wt-% in areas of low maturity but on average, the organic rich shales have TOC contents ranging between 4-11 wt-%. TOC is considered a key indicator of hydrocarbon generation potential but in places with high amounts of pyrolitic carbon or pyrobitumen, this can be misleading. In this study, we discuss the details of pyrolysis and reflectance techniques, findings of the organic petrography, bitumen reflectance data and corresponding Tmax data. The data is also compared to calculated Ro values and problems using the formula are highlighted. In addition, the data is considered in the context of production information.

Distribution of upper Devonian carbonate complexes (Leduc Fm. and equivalent) and

Fig. 2: Distribution of Upper Devonian carbonate complexes (Leduc Fm and equivalent) and intervening West and East Shale Basins. Adapted from Stoakes (1980).

Database selection

Several studies (e.g. Fowler and Stasiuk, 2001) from the Alberta Geological Survey (AGS) and the Alberta Energy Regulator (AER) have investigated the organic composition and vitrinite reflectance of rock samples of the Duvernay Formation with the latest compilation being Beaton et al. 2010. Here, we use the vitrinite reflectance data of the open file reports of the AGS (Beaton et al. 2010, Fowler and Stasiuk, 2002). This database contains exclusively Ro data with 41 samples also having Tmax data. It is critical to point out that the data mostly reflects bitumen reflectance analysis which then were converted to a vitrinite Ro value using the following formula: %Ro Vequivalent = Bitumen %Ro x 0.618+0.4 (Beaton et al. 2010). Analysis is based on core material. Generally, the onset of oil generation is correlated with a vitrinite reflectance of 0.5-0.6% and the termination of oil generation with reflectance of 0.85-1.1% (Tissot and Welte, 1984).

From the AGS database (Beaton et al., 2010), we plotted all Duvernay Ro data (and several data points from the overlying Ireton Formation) against present-day depth (Figure 3). An overall trend of increasing vitrinite reflectance versus depth prevails but up to 3300 m depth, vitrinite reflectance shows a large spread of values (~0.3-1.2% Ro).

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Fig. 3. Vitrinite reflectance values (%Ro) of versus depth of both the Duvernay and the Ireton Formations of Alberta. Data from Beaton et al. (2010). Note the large reflectance range (0.3-1.2%Ro) variability in particular where abundant data are present between ~1000-3300 m depth. The data represents samples across the entire basin from shallow eastern locations to deeper and more tectonic overprinted areas which have experienced different thermal gradients and uplift histories.

The TMax data used in this study is exclusively based on propriatary data of Trican Geological Solutions Ltd

and consists of >350 wells (>1000 samples) analyzed across the Duvernay play area. The data is mostly cuttings data with core data where available. For analysis, a Source Rock Analyzer was used. If possible, TMax data from the same well and similar depth as the Ro data from the AGS was compiled but if not available, TMax data from an adjacent well within the same township were selected. Methods

Samples of the Devonian Duvernay Formation were collected from the core repository of the Alberta Energy Regulator (AER) in Calgary, AB, Canada. Cuttings samples were analysed under a binocular microscope and the Duvernay shale fragments hand-picked. From wells with cored sections in the Duvernay Formation, rock fragments were collected. Samples were finely ground to pass through a 200 mesh screen and prepared for the source rock analyses. An SRA (Source Rock Analyzer) was used to determine the TOC and degree of organic thermal maturity. The SRA is equipped with an FID and two IR detectors. The method uses programmed heating of a small sample (~100 mg) (in a pyrolysis oven) over two stages. The pyrolysis stage is run in an inert atmosphere (helium) to quantitatively and selectively determine (1) the free hydrocarbons contained in the sample (S1); 2) the generated hydrocarbons from artificially cracking the kerogen (S2) and (3) the CO2 generated from programmed pyrolysis between 300o-390oC (S3). The pyrolysis oven temperature program starts at ~300C and is kept at that temperature isothermally for volatilization of any free hydrocarbons that are measured as the S1 peak (detected by FID). The temperature is then increased from 300 to 600C during which volatilization of heavy hydrocarbon compounds (>C40), as well as the cracking of nonvolatile organic matter occurs. The hydrocarbons released from this thermal cracking are measured as the S2 peak (by FID). The temperature at which S2 reaches its maximum depends on the nature and maturity of the kerogen and is called Tmax. In the oxidation phase, the sample is held isothermally (640oC) in an oxygen environment which breaks down the organic matter into CO2 and CO (S4). TOC is then determined by adding the residual organic carbon detected (oxidation phase) to the pyrolyzed organic carbon (pyrolysis phase) using the formula: TOC = 0.83(S1+S2)/10 + S4/10.

For vitrinite and bitumen reflectance, core chip samples were prepared as pellets for petrographic analysis at the USGS. A modification of ASTM (2012a) Standard Practice D2797: Preparing coal samples for microscopical analysis by reflected light was used by mounting the sample material into a 1-inch mold using a heat-setting thermoplastic resin medium. For each sample, a representative portion of the core or cuttings was crushed to approximately 1 mm top size; crushed samples were not sieved. The examination surfaces of the pellets were ground and polished prior to overnight desiccation. A Zeiss AxioImager polarizing microscope equipped with a digital camera and tungsten halogen and fluorescence illumination was used for the petrographic analysis and imaging of the pellets. A Leica DMRX Pol microscope equipped with a J&M photomultiplier was used for reflectance analysis. Bitumen reflectance was measured on the pellets according to ASTM (2012b) Standard Test Method D7708: Microscopical determination of the reflectance of vitrinite dispersed in sedimentary rocks. Pellets were examined at 500x magnification under oil immersion and with blue and white incident light.

Results

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"Vitrinite" reflectance versus depth

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SPE 167031 5

For this study, 28 new samples from 14 wells across the Duvernay Shale Play area in Central Alberta, Canada, were selected for SRA analysis. At least one sample per well was also selected for bitumen reflectance analysis (total 20 samples) and the data is provided in Table 1. Tmax data ranges between 415-474C with a TOC range of 0.6-9.5 wt-%.

Table 1. Well identifier (UWI), sample ID, depth, Tmax (C), TOC (wt-%), measured bitumen reflectance values (%Ro) and calculated vitrinite reflectance (%Ro) based on Jarvie et al., 2001 and the difference between our new data and the calculated data.

Reflectance measurements of the organic matter (bitumen) maturity show some interesting results. Vitrinite is not present in the samples. Solid bitumen is abundant and occurs in a bimodal reflectance population in most of the samples (Fig. 4). A higher reflectance population occurs as mostly homogeneous (labeled hb) larger accumulations with discrete boundaries and a lower reflectance population occurs as more ragged, inhomogeneous accumulations (labeled ib) with wispy and indistinct margins (Fig. 5).

Figure 4. Sample 2758.37-2758.46 of well 14-2-69-21W5 showing the characteristic bimodal bitumen reflectance observed in most samples. The homogenous population has higher Ro values than the inhomogenous (degraded) population.

Mean random reflectance values for the homogeneous (higher reflectance) solid bitumen population reported

as Ro. Ro values calculated from Tmax data also are included in Table 1. The sample from well 6-14-37-7W5 has the highest bitumen Ro (for homogeneous population) with lower intensity organic fluorescence compared to the other samples from the other wells. This sample also showed highest Tmax data of 474C. Across all samples, measured bitumen reflectance values range between 0.41-1.4 %Ro (Table 1). The associated calculated Ro

Well Sample ID Depth (m/ft) Tmax (C) TOC% Ro meas sd Ro calc* Ro(meas)-Ro(calc)2364.31-2364.34 2364.31-2364.34m 434 5.15 0.68 0.08 0.65 0.032365.42-2365.48 2365.42-2365.48m 435 6.07 0.57 0.07 0.66 -0.091149.30-1149.35 1149.30-1149.35m 422 7.84 0.56 0.05 0.44 0.121151.18-1151.26 1151.18-1151.26m 417 9.40 0.61 0.08 0.34 0.271156.30-1156.35 1156.30-1156.35m 415 8.87 0.58 0.01 0.30 0.282752.20-2752.28 2752.20-2752.28m 443 3.00 0.812757.43-2757.48 2757.43-2757.48m 444 2.32 0.842758.37-2758.46 2758.37-2758.46m 444 5.27 0.70 0.14 0.83 -0.133040.56-3040.60 3040.56-3040.60m 451 2.59 0.96 0.05 0.96 0.00

3054.98 3054.98m 446 1.44 0.98 0.14 0.86 0.122274.64-2274.66 2274.64-2274.66m 449 6.16 0.79 0.09 0.92 -0.132283.12-2283.16 2283.12-2283.16m 448 7.70 0.81 0.09 0.90 -0.09

1823.74A 1823.74m 429 6.26 0.551823.74B 1823.74m 432 1.35 0.42 0.08 0.61 -0.191829.60 1829.6m 435 2.32 0.43 0.10 0.67 -0.24

100/14-29-48-06W5/00 2647.28 2647.28m 448 4.55 0.76 0.10 0.90 -0.142688.70 2688.7m 446 1.82 0.862689.80 2689.8m 446 4.17 0.67 0.08 0.86 -0.1910850.64 10850.64ft 466 3.93 1.21 0.12 1.24 -0.03

10857.86A 10857.86ft 466 1.58 1.223816.92 3816.92m 467 3.65 1.19 0.10 1.24 -0.053819.50 3819.5m 438 1.70 0.735871.00 5871ft 438 8.34 0.43 0.12 0.73 -0.305882.00 5882ft 438 9.53 0.72

7790-7840 7790-7840ft 449 2.17 0.71 0.12 0.91 -0.207962-8012 7962-8012ft 450 0.60 0.93

100/06-14-37-07W5/00 3644.16 3644.16m 474 2.49 1.40 0.12 1.38 0.02100/13-17-67-23W4/00 1107.18 1107.18m 429 2.62 0.41 0.10 0.57 -0.16

100/13-14-35-25W4/00

100/12-01-57-03W5/00

100/06-36-63-12W5/00

100/11-01-59-18W5/00

100/11-08-62-24W5/00

100/01-23-49-25W4/00

100/02-19-039-26W4/00

100/14-16-073-01W6/00

100/11-18-072-17W5/00

100/10-27-057-21W4/00

100/14-02-069-21W5/00

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values, based on the Jarvie et al. (2001) formula, range between 0.3-1.38%Ro. The difference between the measured bitumen reflectance and calculated vitrinite reflectance for each sample ranges between 0-0.3%Ro.

At the low thermal maturity level of this sample set, solid bitumen generally is expected to have lower reflectance values than vitrinite due to its higher hydrogen content (Robert, 1988). Assuming calculated Ro values correspond to approximate vitrinite reflectance, it would appear that selecting the mean of all solid bitumen measurements (Table 1) may most closely represent actual thermal maturity. Bitumen reflectance can be empirically related to vitrinite reflectance by the following equations: vitrinite Ro = 0.618 * bitumen Ro + 0.40 (Jacob, 1989), or vitrinite Ro = 0.898 * bitumen Ro + 0.43 (Landis and Castao, 1995). However, application of bitumen reflectance conversions should be approached with caution as 1) the Jacob (1989) and Landis and Castao (1995) studies resulted in different conversion equations, 2) these studies have not been duplicated, and 3. the bitumen may not be indigenous to the samples and may have experienced a different thermal history. In fact, the presence of a conspicuous bimodal bitumen distribution in the Duvernay samples may suggest different migratory phases. For instance, the homogeneous population may be allochthonous whereas the inhomogeneous population may be autochthonous, or the two populations may represent separate oil migration events. The presence of abundant bitumen in the Duvernay samples may be a positive factor for reservoir porosity/permeability and potential gas storage in organic porosity (e.g., Curtis, 2010; Passey et al. 2010). The majority (>95%) of the TOC measured on the higher maturity samples may be presumed to reside in the solid bitumen. Some high TOC in lower maturity samples may represent amorphous organic material or its byproducts resulting from bacterial degradation (or even bacterial biomass). Generally, the solid bitumen is not fluorescent with the exception of one occurrence noted in the higher maturity sample from 14-2-69-21W5. Rarely, solid bitumen occurs with a fine mosaic or granular texture of multiple reflectance domains; such textures have been interpreted to result from coking as a result of exposure to higher temperatures such as from localized hydrothermal activity (e.g., Landis and Castao, 1995).

Vitrinite was not present in any of the samples and/or is not texturally distinguishable from the solid bitumen. Inertinite (unreactive carbonized vitrinite) is present in low quantities in several samples and indicates the presence of a terrestrial sediment source. Evaluation in blue light indicated that marine telalginite is relatively common in all samples except the higher maturity sample from well 14-2-69-21W5. In this sample, advanced thermal maturity may obscure the identification of telalginite by reduction of its fluorescence intensity. Unequivocal tasmanitids are not present, instead most telalginite simply are identified as prasinophytes (labeled T for telalginite in Fig. 5). These planktonic green algae occur in various forms in the lower maturity samples, including some relatively complex morphologies dissimilar to the typical thick-walled spherical to flattened Tasmanites. Except for the higher maturity sample from 14-2-69-21W5, all samples contain a fluorescent mineral bituminous groundmass (Teichmller and Ottenjann, 1977) intimately admixed with the inorganic phases, which occurs as small masses and wisps between and around mineral grains. The mineral bituminous groundmass probably imparts much of the brown color of the rock. This material presumably consists of very finely comminuted filamentous algae fragments along with bacterial biomass. The higher maturity sample from 14-2-69-21W5 may contain some mineral bituminous groundmass; however, its fluorescence intensity is minimal. The descriptions of Duvernay organic material presented herein generally are consistent with previous illustrated reports on low maturity samples (e.g., Chow et al., 1995; Stasiuk and Fowler, 2004). Morphologies interpreted by Stasiuk and Fowler (2004) as terrestrial sporinite are here reinterpreted as marine prasinophyte algae.

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Figure 5: A. low maturity (Ro ~0.4%) solid bitumen (b) in groundmass of abundant fluorescent amorphous organic matter, lamalginite, clays, zoned carbonate with fluorescing hydrocarbon inclusions, and pyrite (p). Bitumen is abundant as a finely disseminated material along mineral grain boundaries. Well 100/01-23-049-25W4/00, organic-rich sample 5871 (8.34% TOC), oil immersion, white incident light. B. same field as A under blue light epi-fluorescence with amorphous organic matter (AOM), lamalginite (l), carbonate (c) and Tasmanites (T) labeled. C. bimodal solid bitumen (Ro ~0.3% vs. ~0.5%) in Well 100/01-23-049-25W4/00, organic-rich sample 5871, oil immersion, white incident light, similar groundmass as A-B. Low reflectance population (ib) is wispy, inhomogeneous, with reddish internal reflections and fluorescent (in some cases) whereas high reflectance population (hb) is homogenous with sharp boundaries, and frequently embayed against carbonate. The presence of two bitumen populations is most evident at lower maturities where two peaks are clear on some reflectance histograms. D. same field as C under blue light epi-fluorescence. Note difference in fluorescence response between fluorescent inhomogeneous bitumen (ib - dark yellowish) and weakly fluorescent homogeneous bitumen (hb - dark brown). E. Authigenic carbonate (dolomite?, c) coeval with generation/migration of hydrocarbon (now solid bitumen, b) in intermediate maturity (Ro 0.76%) sample 2647.28m from well 100/14-29-048-06W5/00, oil immersion under incident white light. F. Network of solid bitumen occurring interstitially with neo-carbonate in high maturity sample 3644.16m (Ro ~1.4%) from well 100/06-14-037-07W5/00. Oil immersion, incident white light.

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Figure 6 shows the location of the well sites superimposed over the vitrinite equivalent reflectance map (based on bitumen reflectance) generated based on the database of Beaton et al. (2010). The map shows increasing maturity of the Duvernay Formation from the NE towards the SW and is highest along the deformation front (fault line). This thermal maturity is closely linked to burial depth as the basin sediments are deeper buried in a SW direction. The Western Canada Sedimentary Basin runs in a NW-SE direction.

Figure 6: Countoured vitrinite equivalent maturity (brown=immature, green=oil window, pink=condensate, and orange=overmature) map of the Duvernay Shale in Central Alberta, Canada, showing an increasing maturity towards the western part of the basin. Data from Beaton et al. (2010). Black dots represents new samples analysed in this study (Well Identifier provided), blue dots are from the AGS database.

The main purpose of this study was to test the usefulness of a widely-used vitrinite conversion formula (Jarvie et al., 2001) that was established in the Barnett Shale (USA) with measured reflectance values and Tmax data from the Duvernay Shale play in Canada. The following two graphs (Fig. 7 and Fig. 8) show the reflectance data available for the Duvernay Shale play (AGS database and this study). Figure 7 shows three populations across the full range: 1. AGS vitrinite equivalent data combined with Trican Tmax data either from the same or an adjacent well (blue crosses); 2. AGS vitrinite equivalent and Tmax data (red triangles); and 3. Bitumen reflectance and Tmax data for this study (black circles). The Jarvie et al. (2010) conversion line is also presented.

Figure 7: Vitrinite equivalent (AGS) or bitumen reflectance (this study) and Tmax data from the Duvernay Shale play

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illustrating data spread across the Tmax and Ro range. Blue cross: AGS vitrinite equivalent data combined with Trican Tmax data either from the same or an adjacent well, red triangle: AGS vitrinite equivalent and Tmax data, black circle: bitumen and Tmax data for this study. Black line represents regression line for this study, blue line for the AGS dataset.

Details of the data are revealed in Figure 8. The data shows that in all three datesets, the range or spread is significant. Jarvie et al. (2001) and this study have a similar regression formula (calculated Ro = 0.0180 x Tmax - 7.16 versus calculated Ro = 0.0149 x Tmax 5.85 from this study) but the spread of data is too significant (up to 0.3% Ro deviation between calculated and measured Ro) to demonstrate that either of these formulas present a solid tool in the Duvernay Shale Play. Hence currently used conversions need to be treated with caution.

Figure 8: Vitrinite and Tmax data from the Duvernay Shale play illustrating data spread between a Tmax of 400-480C and an Ro range of 0.4-1.8%. Note that all three datasets show a marked spread and do not show tight clusters around the regression lines. Hence, using conversion formulas for Tmax values may lead to misleading interpretations.

Summary and Discussion

This study has focused on the maturity assessment of the Duvernay Shale Play in Western Canada (Alberta) using both vitrinite equivalent (AGS) and bitumen reflectance (this study) and SRA Tmax data. The goal was to identify if a Tmax conversion formula established in the Barnett (Jarvie et al. 2001) could potentially be applied for other unconventional shale plays. Several interesting observations resulted from our study:

1) No vitrinite was present in any of the samples analysed. The AGS dataset used a conversion formula to calculate vitrinite equivalent values from the bitumen reflectance data. Our new data shows total bitumen reflectance data of both ib and hb populations.

2) Bitumen reflectance analysis shows a marked bimodal population distribution (ib and hb) across all samples with an inhomogenous, less reflective fraction and a more reflective homogenous fraction. Origin of these two populations will be discussed in a future study. However, our observations are in line with previous regional thermal maturity studies (e.g., Creaney et al., 1994; Stasiuk and Fowler, 2002).

3) Tmax data ranges between 415-474C across the samples selected and their converted values according to the formula by Jarvie et al. (2001) range between 0.3-1.38%Ro. The true measured bitumen reflectance values range between 0.41-1.4%Ro. The highest difference between calculated and measured value was 0.3% Ro.

4) Cross-plots of Duvernay data (20 samples) of Tmax data and bitumen reflectance (%Ro) of this study results in a conversion formula of: Calculated Ro = 0.0149 x Tmax 5.85 (R2=0.71). However, the data and the AGS data (Beaton et al. 201) combined shows marked spread of the data across the plot area and the data did not cluster closely to the regression line. The spread in data suggests that a conversion formula for Tmax data from the Barnett

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Shale should not be utilized in the Duvernay Shale play and conversion calculations should be avoided in new formations where formulas are not yet established.

5) Our data shows a large spread of bitumen reflectance data and the regression fit is only R2=0.71. Future studies need to investigate the reason for such spreads and determine if it is dependend on organic matter type, organic richness, mineral matter or thermal heat differences during burial. This is paramount to comprehend as thermal maturity is one of the most critical factors in hydrocarbon exploration.

For future investigations, we suggest follow-up activities including examination of these low maturity Duvernay samples in polished thin sections and selection of additional samples from other wells or stratigraphic intervals to broaden the available thermal maturity information and potentially identify co-occurring vitrinite (if present) and bitumen. Another idea for the sample set evaluated herein is to analyze via GC-MS for a biomarker approach to more rigorous thermal maturity determination (e.g. Hackley et al. 2013) or apply other techniques which may provide thermal maturity information (e.g, fluid inclusion analysis or spectral fluorescence analysis of low maturity prasinophytes). Finally, lower maturity Duvernay samples should be evaluated to better characterise the original kerogen.

Acknowledgments The authors would like to thank the management of Trican Geological Solutions Ltd (TGS) to allow this work to be conducted and presented. The laboratory data presented in this study relied on the prompt hard work of many TGS team members. Many thanks go also to C.D. Rokosh and J.G. Pawlowicz (AER) for discussions and help with the database.

References

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SPE 167031Vitrinite Reflectance Versus Pyrolysis Tmax Data: Assessing Thermal Maturity in Shale Plays with Special Reference to the Duvernay Shale Play of the Western Canadian Sedimentary Basin, Alberta, CanadaRaphael A.J. Wust, TRICAN Geological Solutions, Calgary, AB, T2E 2M1, Canada, email: rwust@trican.ca; and SEES, JCU, 4811 Townsville, QLD, AUS Paul C. Hackley, USGS, MS 956 National Center, Reston, VA 20192, USA Brent R. Nassichuk, Nicole Willment, Ro...AbstractIntroductionFig. 1: Schematic cross-section showing reef build-up and basinal deposits during the Devonian in Alberta, Canada. Adapted from Fig. 12.10 of the Geological Atlas of the Western Canada Sedimentary Basin, http://www.ags.gov.ab.ca/publications/wcsb_atla...Fig. 2: Distribution of Upper Devonian carbonate complexes (Leduc Fm and equivalent) and intervening West and East Shale Basins. Adapted from Stoakes (1980).

Database selectionFig. 3. Vitrinite reflectance values (%Ro) of versus depth of both the Duvernay and the Ireton Formations of Alberta. Data from Beaton et al. (2010). Note the large reflectance range (0.3-1.2%Ro) variability in particular where abundant data are prese...

MethodsResultsTable 1. Well identifier (UWI), sample ID, depth, Tmax ( C), TOC (wt-%), measured bitumen reflectance values (%Ro) and calculated vitrinite reflectance (%Ro) based on Jarvie et al., 2001 and the difference between our new data and the calculated data.Figure 4. Sample 2758.37-2758.46 of well 14-2-69-21W5 showing the characteristic bimodal bitumen reflectance observed in most samples. The homogenous population has higher Ro values than the inhomogenous (degraded) population.Figure 5: A. low maturity (Ro ~0.4%) solid bitumen (b) in groundmass of abundant fluorescent amorphous organic matter, lamalginite, clays, zoned carbonate with fluorescing hydrocarbon inclusions, and pyrite (p). Bitumen is abundant as a finely dissemi...Figure 6: Countoured vitrinite equivalent maturity (brown=immature, green=oil window, pink=condensate, and orange=overmature) map of the Duvernay Shale in Central Alberta, Canada, showing an increasing maturity towards the western part of the basin. D...Figure 7: Vitrinite equivalent (AGS) or bitumen reflectance (this study) and Tmax data from the Duvernay Shale play illustrating data spread across the Tmax and Ro range. Blue cross: AGS vitrinite equivalent data combined with Trican Tmax data either ...Figure 8: Vitrinite and Tmax data from the Duvernay Shale play illustrating data spread between a Tmax of 400-480 C and an Ro range of 0.4-1.8%. Note that all three datasets show a marked spread and do not show tight clusters around the regression lin...

Summary and DiscussionAcknowledgmentsReferences