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In order to understand the influence of thermal maturity on porosity evolution in shale reservoirs, samples from five wells (88 core samples) from the Upper Devonian Duvernay shale were examined by integrated methods, including Rock-Eval pyrolysis, inorganic composition analysis, helium pyncnometry, mercury injection analysis, nitrogen adsorption and scanning electron microscopy (SEM) imaging combined with ion-milling technique. The samples span a maturity range from immature to wet gas window and a wide range of compositions.

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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 × 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.