Solid bitumen in shales: Petrographic characteristics and implications for reservoir characterization

Misch, David; Groß, Doris; Hawranek, Gerhard; Horsfield, Brian; Klaver, Jop; Martín, Francisca Méndez; Urai, János L.; Vranjes-Wessely, Sanja; Sachsenhofer, Reinhard F.; Schmatz, Joyce; Li, J.; Zou, Caineng

doi:10.1016/j.coal.2019.02.012

Cited by 74 publications

(37 citation statements)

References 66 publications

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“…Moreover, this work suggests that simply considering the amount and quality of organic matter and the level of maturity is clearly insufficient to estimate the porosity of organic-rich mudstones. As suggested by previous studies (Furmann et al, 2016;Ko et al, 2017Ko et al, , 2016Liu et al, 2018;Loucks et al, 2012;Mastalerz et al, 2013;Misch et al, 2019) the relative proportion of the individual organic components, influenced by depositional and diagenetic processes, can greatly affect pore evolution during thermal maturation.…”

Section: Influence Of the Original Om Particulate Assemblage On Porosmentioning

confidence: 79%

Effect of organic matter composition on source rock porosity during confined anhydrous thermal maturation: Example of Kimmeridge-clay mudstones

Cavelan

Boussafir

Milbeau

et al. 2019

International Journal of Coal Geology

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To investigate how slight differences in the total particulate organic matter (OM) assemblage and maceral types of marine mudstones influence the development and the evolution of OM porosity throughout the same formation, laboratory gold-tube anhydrous confined thermal maturation was applied on low-mature organic-rich marine Kimmeridge clay mudstones (Yorkshire, UK). Organic petrography (palynofacies and maceral analysis), SEM observations, global and molecular geochemical characterization and low-pressure nitrogen adsorption measurements were performed to examine, to our knowledge for the first time, the role of the OM composition and properties on the evolution of porosity during thermal maturation. Evidence from organic petrography and geochemical analyses showed that organic-rich Kimmeridge clay samples containing a higher relative proportion of brown amorphous organic matter (AOM), known to be derived essentially from the cell walls of microalgae, exhibit a different pore evolution compared to samples containing a higher proportion of oil-prone orange AOM derived primarily from preservation by natural sulfurization of phytoplanktonic organic components naturally rich in lipidic compounds. OM conversion of orange AOM-rich samples has led to the production of higher amounts of low viscous oil and abundant gaseous hydrocarbon that are more 2 favorable to the formation of abundant but small OM micropores and mesopores in the condensate/wet gas zone and less abundant large modified mineral pores in the dry gas zone. The secondary cracking of the heavier oil produced by brown-AOM-rich OM has led to the formation of a greater quantity of CO2 and an abundant organic-rich residue more favorable to the formation of larger mesopores. Moreover, the more abundant thick laminar bituminite macerals forming a continuous ductile network particularly prone to compaction and the higher amounts of oil/bitumen generated during their conversion may have led to a higher pore collapse after oil/gas generation and migration, responsible for the destruction of part of the secondary pore network observed on some samples. Despite their slightly lower oil-prone potential, brown AOM-rich samples have thus developed larger mesopores during thermal maturation, resulting in higher pore volumes in the dry gas zone. Thus, the ability of marine mudstones to develop pores during maturation do not increase proportionally with the OM oil prone quality. These results show that variations in the individual particulate OM assemblage of a similar type II kerogen can significantly influence the amount of oil and gas generated during thermal maturation throughout the same formation, resulting in different pore evolution models. This reveals the importance of clearly identifying the composition of the original particulate OM assemblage to better predict the amount of bitumen, oil and gas generated during thermal maturation and the associated pore development.

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Section: Influence Of the Original Om Particulate Assemblage On Porosmentioning

confidence: 79%

Effect of organic matter composition on source rock porosity during confined anhydrous thermal maturation: Example of Kimmeridge-clay mudstones

Cavelan

Boussafir

Milbeau

et al. 2019

International Journal of Coal Geology

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“…Therefore, the presence of bituminous organic matter (OM) residues in the mudstones may indicate that secondary migration has occurred from an underlying, imperfectly sealed reservoir unit. Although such traces are difficult to distinguish from primary OM under SEM (Mastalerz et al, 2018;Misch et al, 2019a), bituminous residues were observed in the intensely carbonate-cemented sample from well Mühlberg 125 (1923 m, 16.TH; ɸ BIB = 2.7 vol.%), in which bitumen fills voids between authigenic carbonate aggregates (Figs 9d-f). Similar traces of bitumen were found in the sample from well Bockfliess 203 (1715 m, 16.TH; ɸ BIB = 10.1 vol.%; Fig.…”

Section: Bib-semmentioning

confidence: 99%

“…Schulz et al, 2015;Grundtner et al, 2017) but may also occur due to the migration of hydrocarbons through low permeability muddy sandstone and mudstone seal rocks (e.g. Misch et al, 2019a;see below). As a result, the Mühlberg 125 sample is dominated by secondary calcite, whereas dolomite is generally the dominant carbonate mineral in nearby wells (Fig.…”

Section: Trends In Bulk Mineralogical Compositionmentioning

confidence: 99%

“…This is particularly the case in studies of solid bitumen derived by secondary alteration of an earlier oil phase which either originated from primary OM within the source rock succession (and which is therefore in situ) or which migrated from another reservoir formation. Solid bitumen often forms rims round mineral grains or fills interparticle void spaces whose study requires sub-micron resolution and noninvasive preparation (Klaver et al, 2012;Misch et al, 2019a;Loucks and Reed, 2014).…”

Section: Solid Bitumen Traces As Indicators Of Hydrocarbons Entering mentioning

confidence: 99%

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Mineralogical, Bib‐sem and Petrophysical Data in Seal Rock Analysis: A Case Study From the Vienna Basin, Austria

Misch

Siedl

Drews

et al. 2020

Journal of Petroleum Geology

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The Vienna Basin is a major hydrocarbon province with a long exploration history. Within the basin, secondary migration from Upper Jurassic source rocks into stacked Middle Miocene (Badenian) sandstone reservoirs was formerly considered to have occurred almost entirely along major fault zones. However recent exploration data has suggested that in areas where no major faults are present, oil may have migrated vertically through the sandy mudstone intervals separating individual reservoir units, which are therefore imperfectly sealed. In order to investigate possible secondary migration through the semi‐permeable mudstones, this study links variations in gross depositional environment (GDE) to variations in mudstone properties (e.g. mineralogy and pore size distribution). The study focussed on the mudstones which seal reservoir sandstones referred to locally as the “8.TH” and “16.TH” units. The bulk mineralogical composition of 56 mudstone and sandy mudstone (and minor intercalated muddy sandstone) samples from seal layers in 22 wells was studied by X‐ray diffraction analysis, broad ion beam – scanning electron microscopy (BIB‐SEM), mercury intrusion porosimetry (MICP) and N2 adsorption. These data are interpreted in the context of GDE maps of the Vienna Basin which were previously established using seismic and well log data.Results indicate that the gross depositional environment strongly controlled the pore space characteristics of the mudstones. The sandy mudstones in the NW part of the study area were influenced by a complex eastward‐prograding deltaic system which deposited coarse detritus into a major palaeo depression (“Zistersdorf Depression”) located in the centre of the basin. Higher overall porosity and a dominance of larger pore size classes, probably resulting in reduced seal quality, were observed for sandy mudstones from well locations within feeder channels and also from within the Zistersdorf Depression. Similarly, sandy mudstones from locations associated with the long‐term input of coarser sediments in shoreline, coastal and proximal offshore settings in the NW and central parts of the study area are considered to be of lower sealing quality compared to fine‐grained mudstones deposited in distal, open‐marine settings which prevailed in the SE part of the study area throughout the Middle Miocene.In general, pore geometries were influenced by mineralogical composition; quartz‐ and detrital carbonate‐rich samples show equidimensional pores, while more elongated pores (with a higher average aspect ratio) characterize clay‐rich samples. Furthermore, matrix mesopores (2‐50 nm) determined by N2 sorption are more abundant in clay‐rich versus quartz‐rich samples, and show a pronounced positive trend with increasing percentage of illite‐smectite mixed‐layer clay minerals.This study shows that regional‐scale mudstone seals in the Vienna Basin have been influenced by variations in sedimentation associated with lateral variations in gross depositional environment during the Middle Miocene. The observed pore characteristics will serve as input data for future models of secondary migration.

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“…Sampling depth, TOC, and Rock-Eval data of whole rock and solventextracted samples (after Ziegs et al, 2017) are given in Table 1. In addition, three peak oil mature samples from Upper Visean Rudov Beds (Ukrainian Dniepr-Donets Basin), hosting a similar type II/III kerogen and abundant nanoporous and likely remobilized (Misch et al, 2019) solid bitumen, were taken as a reference for the evaluation of petroleum quality ratings established by Ziegs et al (2017), as well as for comparison of organic matter microstructures at SEM scale. Rock-Eval parameters were determined for the sub-set of three Rudov samples in untreated and solvent extracted condition (see also Ziegs et al, 2017).…”

Section: Samples and Methodsmentioning

confidence: 99%

Petrographic and sorption-based characterization of bituminous organic matter in the Mandal Formation, Central Graben (Norway)

Misch

Riedl

Liu

et al. 2019

International Journal of Coal Geology

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Research Highlights: • Samples rich in vitrodetrinite are common both in marginal and basinal positions • Coaly layers were exclusively found in the Søgne and Cod areas • A correlation of TOC with liptinite percentages indicates enhanced bioproductivity or preservation efficiency • Nitrogen sorption data indicate that the soluble organic matter fraction represents the controlling factor on micro-and mesopores • Small mesopores are mainly associated with the high-molecular weight bituminous fraction, which appears non-porous at SEM-scale • The total inner surface area decreases with thermal maturity ABSTRACT The Upper Jurassic Mandal Fm. of the Central Graben, Norway represents an important source rock that charged major petroleum accumulations in the North Sea, including the giant Ekofisk field. Nevertheless, exploration to date has been less successful than expected in marginal basin position such as the Cod Terrace, the Mandal High or the Søgne Basin, probably due to higher proportions of thermally stable (type III) kerogen. In an attempt to delineate changes in initial kerogen composition from later effects such as delayed expulsion of hydrocarbons, traditional organic petrography and scanning electron microscopy were combined with organic geochemical proxies and gas adsorption tests. The kerogen composition of the Mandal Fm. shows considerable variation. Samples hosting autochthonous coaly layers were found in wells from the Søgne Basin and the Cod Terrace, for which less generative potential was previously postulated. Nevertheless, samples hosting mainly vitrodetrinite were also found in basinal wells. A correlation of total organic carbon contents with liptinite percentages highlights enhanced bioproductivity or preservation efficiency for samples with abundant algal organic matter, that were likely deposited under deeper water and possibly oxygen-depleted conditions. By combining organic geochemical proxies with nitrogen sorption data, it could be proven that in case of the Mandal Fm., the (bituminous) organic matter fraction represents the controlling factor on abundance of micro-and mesopores and hence adsorptive gas retention. The amount of bitumen extractable from the Rock-Eval S2 peak (S2bitumen) shows a strong correlation with the total inner surface area, suggesting that small mesopores (<10-15 nm) are mainly associated with the high-molecular bituminous fraction represented by the S2bitumen, which appears nonporous at SEM-scale. Furthermore, the total inner surface area decreases strongly with thermal maturity, documenting a change in pore characteristics of the organic matter fraction (growth of mesopores and occurrence of macropores) by advancing hydrocarbon generation. Pyrobitumen-rich Upper Visean reference samples at peak oil and early wet gas window maturity show intense sponge-like pyrobitumen-hosted porosity coinciding with a low relative proportion of S2bitumen (high petroleum quality). Pyrobitumen is not affected by solvent extraction, thus not contributing high-molecular weight compounds...

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Solid bitumen in shales: Petrographic characteristics and implications for reservoir characterization

Cited by 74 publications

References 66 publications

Effect of organic matter composition on source rock porosity during confined anhydrous thermal maturation: Example of Kimmeridge-clay mudstones

Effect of organic matter composition on source rock porosity during confined anhydrous thermal maturation: Example of Kimmeridge-clay mudstones

Mineralogical, Bib‐sem and Petrophysical Data in Seal Rock Analysis: A Case Study From the Vienna Basin, Austria

Petrographic and sorption-based characterization of bituminous organic matter in the Mandal Formation, Central Graben (Norway)

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