Pyrolysis S2-peak characteristics of Raniganj shales (India) reflect complex combinations of kerogen kinetics and other processes related to different levels of thermal maturity

The Permian shales of the Raniganj basin, India, have experienced a dramatic burial history of rapid subsidence (Jurassic-Early Cretaceous) followed by igneous intrusion (Cretaceous) and rapid uplift and erosion (Late Cretaceous-Tertiary). This has left these shales with mixed kerogen macerals with a characteristic thermal signature, ranging from early mature to post mature, which is reflected in the characteristics of their pyrolysis S2 peak. Many of these shales are today at peak thermal maturity but reached that condition more than 100 million years ago. They have significant potential to be exploited as a shale gas resource and their S2 peak characteristics should help to identify sweet spots for such exploitation. Here we analyze single-rate and multi-rate heating ramp Rock-Eval data from a suite of these shales at varying stages of thermal maturity. The S2 peak shapes provide significant insight to the kerogen kinetics involved in their thermal evolution. However, detailed fitting of the peak shapes with kerogen-kinetic mixing models indicate that factors other than static first-order reaction kinetics are also involved in their S2-peak-shape characteristics. Such factors likely include the catalytic effects, influenced by sulfur and charcoal, on some kerogen components, and kerogen pore-size distribution changes during their complex burial and thermal maturation histories. It is likely that the peak-mature shales contain significant, already generated, gas trapped within some of the kerogen nanopores that may be released during the S2 pyrolysis heating ramp rather than during the S1 heating ramp. This causes the S2 peak to broaden in the mature shales, a characteristic that could be used as an exploration marker for zones best suited to shale gas exploitation.Cited as: Wood, D.A., Hazra, B. Pyrolysis S2-peak characteristics of raniganj shales (India) reflect complex combinations of kerogen kinetics and other processes related to different levels of thermal maturity. Advances in Geo-Energy Research, 2018, 2(4): 343-368, doi: 10.26804/ager.2018.04.0

Significance of lithotypes for hydrocarbon generation and storage

This paper examines the hydrocarbon generation and storage potential of lithotypes, macerals, kerogen type relative to thermal maturity. To investigate authors had collected lithotype (vitrain, durain and fusain) samples from the high volatile sub-bituminous coal of Barjora area, SE of Raniganj coal basin, India. Relevant analyses viz. Rock Eval pyrolysis (REP), total organic carbon (TOC), micropetrography, vitrinite reflectance (Romv) and Fourier Transform Infrared Spectrometry (FTIR) were carried. The geochemical analysis indicates that the studied lithotypes have excellent potentiality of generating hydrocarbon in respect of TOC and S2 (under Rock-Eval pyrolysis) and it increases from vitrain to durain to fusain. Also, the free hydrocarbons which was recorded under S1 curve of Rock Eval pyrolysis, was observed to be highest within the fusain lithotype (21.73 mg HC/g rock). Further, the thermal maturity (Tmax: 418–423 °C) and mean vitrinite reflectance (Romv: 0.42–0.56%) indicate the samples are immature in nature. However, ↑Vt60 (vitrinite grains having a reflectance greater than 0.60%), indicates that thermogenic gas generation was occurring to some degree in almost all the samples. Moreover, comparison between geochemical and petrographical analysis it has been inferred that storing capability of hydrocarbons also increases from vitrain to durain to fusain. The higher capability of hydrocarbons within the fusain (in comparison to durain and vitrain) may be due to presence of large amount of fusinite and semifusinite macerals. The production index (PI) also shows similar trend with increasing S1 value. The FTIR study demonstrates that the fusain has higher intensity of aliphaticity than that of vitrain and durain. The higher intensity of aliphaticity in the fusain may be due to presence of considerable amount of bituminite and other liptinites within the cavities/cell lumens. All the observation suggests that fusain has the highest hydrocarbon generation and storage potentiality, whereas durain has less and vitrain has least generation potentiality in comparison to fusain

Nano-scale physicochemical attributes and their impact on pore heterogeneity in shale

Heterogeneity in shale due to distribution of mineral and organic matter controls the disposition of pores in them. While the effect of vertical anisotropy is accounted for most cases of porosity estimation, the effect of bedding parallel heterogeneity is often ignored. This study dives deep into the shale fabric using bedding parallel sections, and the pore volume distribution is estimated in shales of varying thermal maturity and organic carbon content (2.6% − 38.2 %). Three among the five shales used in this study are early mature (Tmax: 439–444 ◦C), whereas the remaining two are over-mature, signified by very high S4Tpeak (670–685 ◦C). The higher thermal maturity indicates thermal alteration induced by igneous intrusion. The pore volume, functional groups, and organic matter distribution are systematically derived in different positions of the bedding parallel section using a combination of 3D imaging, spectroscopy, small-angle scattering and low-pressure gas adsorption techniques. These spot-specific properties are further compared with bulk properties to quantify the extent of heterogeneity. It is observed that the over-mature shales with higher aromaticity contain 150–200% more bulk accessible pore volume than the lesser-mature shales. It is also evident that the smaller mesopores (~10 nm pore width) are more inaccessible compared to their coarser (~20 nm pore width) counterparts. Higher matured shales show increased inaccessibility of mesopores up to 228 % due to bitumen deposition in pores during thermal maturation, resulting in a sharp decline in mesopore surface fractal dimension. The uniformity of the functional group and organic matter distribution in different parts of the shale depends on the maturity, and reflects the extent of variation in pore volume across the specimen. The 3D tomography-derived spatial abundance of organic matter in over-mature shales show higher deviation (±15-20%) from the average than lesser mature shales (5–10%). This study proposes a multiscale methodology which can evolve and develop as a protocol for systematic, reservoir-scale maturity-dependent heterogeneity quantification in gas-shales

Source rock properties of Permian shales from Rajmahal Basin, India

In the present study, shale samples from Rajmahal Basin, India, were analysed in terms of their source rock properties using an open-system programmed pyrolysis instrument (Rock–Eval 6). Comprehensive analysis of the diferent Rock–Eval graph�ics was conducted for the samples under consideration. Construction of S2 (mg HC/g rock) vs. total organic carbon (wt%) cross-plot using iso-HI (iso-hydrogen index) lines classifed the studied suit of samples into three zones with increasing hydrogen index (Zone A<Zone B<Zone C). Analysis of S2 curves of samples from diferent zones revealed distinctive features attributed to the variable nature of kerogen present within the sample as well as the levels of S2 and HI. S2 curves of sample with higher Tmax were observed to be asymmetric, broad, and marked by lower fame ionization detector signals. However, for those samples, the S4 Tpeak was observed to be similar to that of the other samples. On the other hand, the higher S2 Tmax of some samples coincided with higher S4 Tpeak indicating the samples to be more mature. Additionally, samples with higher levels of oxygen index (OI), and siderite content, were observed to have S3′ curve marked by pronounced release of CO2 above 400 °C, whereas the samples with higher OI but without any presence of siderite were marked by noisy curves due to low IR CO2 signal. The results reiterated the importance of careful monitoring of the diferent curves obtained during the pyrolysis and oxidation stage so that erroneous characterization of the samples could be avoided

Insights into the effects of matrix retention and inert carbon on the petroleum generation potential of Indian Gondwana shales

The Rock-Eval pyrolysis and total organic carbon (TOC) analysis technique is widely used for organic geochemistry screening of source rocks and potential unconventional petroleum reservoirs. The Rock-Eval-derived parameters, the Hydrogen Index (HI), which is the ratio between hydrocarbons released under the S2 curve (hydrocarbon formed by thermal pyrolysis; S2 is an indicator of petroleum generation potential) and total organic carbon (TOC) can be used to infer the type of organic matter present in a rock. However, HI is often under-estimated due to retention of some hydrocarbons included under the S2 curve by the rock matrix, and the presence of inert carbon within the rock. Here we describe and correct the matrix retention and inert carbon effects on hydrocarbon generation from a suite of shale samples from Indian Gondwana shale reservoirs. Removal of the petrographically-identified inert carbon component from the samples tested leads to less scatter in the TOC-S2 relationship obtained. The ratio of volume percentage of organic matter identified through optical microscopy to TOC is calculated, and that ratio was least in the one heat-affected sample, but higher in low-TOC shales (12.5%). With decreasing TOC content in the sample set analyzed, the corrected HI values calculated using the S2-TOC intercept, increase significantly. This correction can therefore lead to false indications about the type of organic matter present. A key novel finding of this work is the need while correcting HI for matrix retention effects, to consider samples with a specific range of TOC contents, and to match them to the kerogen types present (e.g. Types III and IV in the samples analyzed). Filters should also be applied to adjust for the degree of thermal maturity and organic facies

Pyrolysis S2-peak characteristics of Raniganj shales (India) reflect complex combinations of kerogen kinetics and other processes related to different levels of thermal maturity

The Permian shales of the Raniganj basin, India, have experienced a dramatic burial history of rapid subsidence (Jurassic-Early Cretaceous) followed by igneous intrusion (Cretaceous) and rapid uplift and erosion (Late Cretaceous-Tertiary). This has left these shales with mixed kerogen macerals with a characteristic thermal signature, ranging from early mature to post mature, which is reflected in the characteristics of their pyrolysis S2 peak. Many of these shales are today at peak thermal maturity but reached that condition more than 100 million years ago. They have significant potential to be exploited as a shale gas resource and their S2 peak characteristics should help to identify sweet spots for such exploitation. Here we analyze single-rate and multi-rate heating ramp Rock-Eval data from a suite of these shales at varying stages of thermal maturity. The S2 peak shapes provide significant insight to the kerogen kinetics involved in their thermal evolution. However, detailed fitting of the peak shapes with kerogen-kinetic mixing models indicate that factors other than static first-order reaction kinetics are also involved in their S2-peak-shape characteristics. Such factors likely include the catalytic effects, influenced by sulfur and charcoal, on some kerogen components, and kerogen pore-size distribution changes during their complex burial and thermal maturation histories. It is likely that the peak-mature shales contain significant, already generated, gas trapped within some of the kerogen nanopores that may be released during the S2 pyrolysis heating ramp rather than during the S1 heating ramp. This causes the S2 peak to broaden in the mature shales, a characteristic that could be used as an exploration marker for zones best suited to shale gas exploitation

Porosity controls and fractal disposition of organic-rich Permian shales using low-pressure adsorption techniques

The pore structure characteristics of the Lower and Upper Permian shales belonging to the Barren Measures and Raniganj Formations, respectively, were investigated using the low-pressure N2 adsorption-desorption experiments. It was found that the kaolinite content of the Barren Measures shales strongly influenced the Brunauer-Emmett-Teller specific surface area (BET SSA). However, it was the Rock-Eval temperature maxima (Tmax) for the Raniganj Formation shales that influenced the BET SSA values. These shales are dominantly mesoporous and display a negative correlation between BET SSA and average pore radius. Nitrogen adsorption-desorption isotherms are of type IIB and type IV, displaying H2, H3, and hybrid H3-H4 hysteresis patterns. A strong positive correlation exists between average pore radius and the difference in volumes of gas adsorbed at the last-two-highest relative pressures measured. Samples with steeper isotherm slopes at the higher relative pressure range were those with the highest average pore radii. Porosity fractal dimension, D2 displayed a positive correlation with BET SSA and Tmax, and a negative correlation with average pore radius. It is thus concluded that shales with the lowest average pore sizes and highest thermal maturities are marked by larger SSA and more complex pore structures. One of the tested samples (CG 1019) with the highest D2 value is associated with the lowest D1 fractal dimension value. That counter intuitive relationship may reflect analytical constraints of the nitrogen adsorption method at lower relative pressures

Pore Characteristics of Distinct Thermally Mature Shales: Influence of Particle Size on Low-Pressure CO2 and N2 Adsorption

The influence of crushed sample particle size on low-pressure gas adsorption and desorption behavior of shales and their measurement is an issue of significant current interest in this new era focused on shale gas and oil resources. Here we study two samples of distinct Indian shales, with different organic contents, ages, levels of thermal maturity, and pore-size distributions crushed to four different particle size ranges [S1 (1 mm to 500 μm), S2 (500–212 μm), S3 (212–75 μm), and S4 (75–53 μm)]. Low-pressure gas adsorption analysis with nitrogen and carbon dioxide gases reveals significant and complex impacts of particle-crush sizes on the measured pore structure characteristics for the two shales. The CO2 results suggest that at the smallest (S4) particle-crush size evaluated, low-pressure gas adsorption measurements record more, finer nanopores (i.e., less than about 8 Å), fewer larger nanopores (i.e., greater than about 8 Å), and a lower overall nanopore surface volume. The N2 results show an overall increase in macro-pore volume at the smallest particle-crush size. The results imply that while more, smaller pores are exposed to gas adsorption at the smaller crush sizes, a significant number of nanopores are in some way altered and are not recorded as part of the measured nanopore-size distribution >8 Å by low-pressure CO2 adsorption analysis. Fractal dimensions of one shale varied across a range of particle-crush sizes, whereas the fractal dimensions of the other shale studied did not. The analyses suggest that low-pressure gas adsorption results conducted with samples of very small particle-crush sizes should be viewed with caution

Applicability of Low-Pressure CO2 and N2 Adsorption in Determining Pore Attributes of Organic-Rich Shales and Coals

Low-pressure gas adsorption (LPGA) using N2 and CO2 has been widely used by researchers to evaluate the porous structures present within shales and coals. For a suite of shale and coal samples from India, a drop in the N2-BET specific surface area (SSA) was observed with an increase in total organic carbon content (TOC), with low-TOC shales showing a higher SSA than high-TOC shales and coals. Previous research works have demonstrated the limitations of using N2 at −196 °C to penetrate complex microporous structures in coals and thus yielding a low SSA. Likewise, the limitations of N2 to decipher complex porous structures in coals will hold for shales as well. An overall trend of decreased N2-SSA with increasing TOC content, especially for shales with TOC >10 wt %, and higher N2-SSA at lower TOC levels indicates that N2 does not completely detect the porous structures in organic-rich rocks. It mostly accesses the porous structures in minerals, thereby yielding a generally high SSA for low-TOC shales. In light of these facts, correlating and evaluating SSA in shales based on organic richness and thermal maturity levels can be misleading. On the other hand, while LPGA studies using CO2 are also debated, we propose an improved relationship between organic matter abundance and CO2-SSA in coals and shales

Impact of Degassing Time and Temperature on the Estimation of Pore Attributes in Shale

The influence of degassing time and temperature on low-pressure gas adsorption (LPGA) behavior of shales was examined in this study. Two organic-rich shales of contrasting maturity, reactivity and organic matter type, were crushed to <1 mm and <212 μm grain-sizes and degassed at 110, 200, and 300 °C for 3 and 12 h, respectively. Our results indicate that degassing duration has a minimal influence on pore-character interpretations from LPGA experiments, while the degassing temperature shows a strong influence on the pore attributes. For both shales, reliable porosity estimates were obtained when the samples were degassed at 110 °C. When the degassing temperature was increased to 200 and further to 300 °C, distinct changes in adsorption isotherms and other pore structural features were observed. For the mesoporous low-mature shale (collected from a lignite mine) when the degassing temperature was kept at 200 °C, a macroporous character was induced with a manifold increase in pore diameter. Results from thermogravimetry and Rock-Eval indicate abundance of reactive kerogen, which undergoes alteration when degassed at higher temperatures. When the degassing temperature was kept at 300 °C, the organic matter underwent further alteration and showed an isotherm similar to the shales degassed at 110 °C. Similarly, for the oil-window mature shale sample, a transition towards macroporous structure was observed when the sample was degassed at 200 and 300 °C, compared to a mesoporous structure observed when degassed at 110 °C. The results from fractal dimensions also support the above inferences, indicating the presence of simpler structures at higher degassing temperatures. Reduction in pore volume (110–200 °C) and its further rise (200–300 °C) are also evident in the micropore domain, more distinctly in the oil window mature shale. Our results strongly indicate that degassing temperature should be kept at around 110 °C for reliable shale pore character estimation