4 results on '"MENDEZ, MARTIN"'
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2. Solid bitumen in shales: Petrographic characteristics and implications for reservoir characterization
- Author
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Misch, D., Gross, D., Hawranek, G., Horsfield, B., Klaver, J., Mendez-Martin, F., Urai, J.L., Vranjes-Wessely, S., Sachsenhofer, R.F., Schmatz, J., Li, J., and Zou, C.
- Published
- 2019
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3. Solid bitumen in shales: Petrographic characteristics and implications for reservoir characterization
- Author
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Reinhard F. Sachsenhofer, Caineng Zou, David Misch, János Urai, Joyce Schmatz, F. Mendez-Martin, Jop Klaver, Gerhard Hawranek, Sanja Vranjes-Wessely, Jian Li, Doris Gross, and Brian Horsfield
- Subjects
chemistry.chemical_classification ,020209 energy ,Stratigraphy ,Mineralogy ,Geology ,02 engineering and technology ,Authigenic ,010502 geochemistry & geophysics ,01 natural sciences ,Diagenesis ,Petrography ,chemistry.chemical_compound ,Fuel Technology ,chemistry ,0202 electrical engineering, electronic engineering, information engineering ,Kerogen ,Carbonate ,Economic Geology ,Organic matter ,Dissolution ,Oil shale ,0105 earth and related environmental sciences - Abstract
The presence of solid bitumen strongly affects hydrocarbon storage and expulsion from a source rock as it might either cause blockage of pore throats leading to lower effective gas permeability, or contribute to hydrocarbon storage and provide migration pathways when a continuous network of hydrocarbon-wet organic matter (OM) pores is formed. Furthermore, organic matter transformation reactions are suggested to influence mineral diagenesis as well. In an attempt to characterize different solid bitumen types and transformation stages over a broad maturity interval (0.5–2.7%Ro) and for varying primary kerogen compositions, we reviewed optical and scanning electron microscopy (SEM) data of 35 solid bitumen-rich shale samples with a Cambrian to Triassic age. We were able to identify in-situ pre-oil solid bitumen, as well as remobilized post-oil solid bitumen at various maturity stages from the early oil window onwards. Solid bitumen is the main host for SEM-visible organic matter porosity; onset of porosity development in solid bitumen differs considerably between predominantly oil-prone (e.g., alginites, amorphous OM from algal and bacterial precursors) and gas-prone (vitrinite-rich) kerogen compositions. Furthermore, solid bitumen (pyrobitumen) in rocks with a terrestrially dominated OM composition seems to be considerably less mobile within the source rock compared to pre- and post-oil solid bitumen in oil-prone rocks, and less reactive in terms of porosity generation. In most samples, several solid bitumen populations with varying fluorescence properties and bitumen reflectance were observed, complicating the use of these petrographic maturity indicators. The apparently different solid bitumen populations often form continuous networks at the SEM-scale. Microstructural features such as irregularly distributed sponge-like porosity or detrital and authigenic mineral inclusions in the sub-micrometer scale were found to have a great influence on texture and reflectance under reflected light microscopy. The formation of authigenic minerals (quartz, various carbonate phases with different Ca/Mg/Fe proportions, magnetite in Cambrian samples) was observed frequently in post-oil solid bitumen of oil-prone rocks, indicating a close genetic relationship between transformation products formed during hydrocarbon generation (e.g., acetate, carbon dioxide and methane) and the dissolution and precipitation of minerals during diagenesis. In some cases, stylolite-like features in the sub-micrometer scale were found, showing that processes well-known from reservoir characterization at core-scale also play a role at the micrometer-scale. Furthermore, the observed strong interaction between organic matter transformation and mineral authigenesis indicates a substantial aqueous component even in pores filled apparently exclusively with solid bitumen.
- Published
- 2019
4. Petrographic and sorption-based characterization of bituminous organic matter in the Mandal Formation, Central Graben (Norway)
- Author
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Reinhard F. Sachsenhofer, F. Mendez-Martin, David Misch, Bo Liu, Brian Horsfield, Sanja Vranjes-Wessely, F. Riedl, and Volker Ziegs
- Subjects
Maturity (geology) ,chemistry.chemical_classification ,Total organic carbon ,020209 energy ,Stratigraphy ,Geochemistry ,Geology ,Sorption ,02 engineering and technology ,010502 geochemistry & geophysics ,01 natural sciences ,chemistry.chemical_compound ,Fuel Technology ,Hydrocarbon ,chemistry ,Source rock ,Liptinite ,0202 electrical engineering, electronic engineering, information engineering ,Kerogen ,Economic Geology ,Organic matter ,0105 earth and related environmental sciences - 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 Sogne 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 Sogne 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 (S2 bitumen ) shows a strong correlation with the total inner surface area, suggesting that small mesopores ( bitumen , which appears non-porous 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 S2 bitumen (high petroleum quality). Pyrobitumen is not affected by solvent extraction, thus not contributing high-molecular weight compounds to the extracted fraction. Such inert meso- to macroporous residues might contribute only relatively little to gas sorption capacity, but might represent important storage space for free gas, as well as flow pathways during expulsion.
- Published
- 2019
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