Identification of organic matter in thin section by staining and a study programme for carbonate rocks

1970 ◽  
Vol 40 (4) ◽  
pp. 1350-1351 ◽  
Author(s):  
M. H. Smith
Keyword(s):  
Organic Matter ◽  
Thin Section ◽  
Carbonate Rocks ◽  
Study Programme

scholarly journals The role of organic matter in formation of the properties of a shale deposit

2019 ◽  
Vol 484 (2) ◽  
pp. 220-223
Author(s):  
И. Ф. Юсупова
Keyword(s):  
Organic Matter ◽  
Carbonate Rocks ◽  
Strength Properties ◽  
Low Density ◽  
Lower Strength ◽  
Reduction Processes ◽  
Local Areas ◽  
Oil Shales ◽  
Mosaic Distribution

Baltic oil shales — kukersites were studied as an example of rocks with rock-forming organic matter (OM). The volumetric significance of their OM is shown (due to the low density) in the volume and thickness of the shale layers. A higher OM content is responsible for a lower strength of the shales relative to the carbonate rocks of the deposit. The variable OM contents and other heterogeneities of the shale layers (structure, nodules, etc.) are factors of the mosaic distribution of areas with different density–strength properties and, as a result, of uneven reduction of layers and their deformation in the case of OM loss (full or partial). It is concluded that the intercalation of kukersite and limestone layers leads to density and strength anisotropy of the shale deposit. Episodic loss of OM and carbonates by the shales is considered for the local areas of the deposit: here, kukersites contain only a terrigenous component with clasts of limestones, shales, and epigenetic sulfides. The loss of OM is explained by sulfate-reduction processes in the underground hydrosphere.

scholarly journals An integrated analysis of mineralogical and microstructural characteristics and petrophysical properties of carbonate rocks in the lower Indus Basin, Pakistan

2019 ◽  
Vol 11 (1) ◽  
pp. 1151-1167
Author(s):  
Waheed Ali Abro ◽  
Abdul Majeed Shar ◽  
Kun Sang Lee ◽  
Asad Ali Narejo
Keyword(s):  
Thin Section ◽  
Carbonate Rocks ◽  
Carbonate Rock ◽  
Indus Basin ◽  
Reservoir Quality ◽  
Data Sets ◽  
Petrophysical Properties ◽  
X Ray ◽  
Lower Indus Basin

Abstract Carbonate rocks are believed to be proven hydrocarbon reservoirs and are found in various basins of Pakistan including Lower Indus Basin. The carbonate rock intervals of the Jakkher Group from Paleocene to Oligocene age are distributed in south-western part of Lower Indus Basin of Pakistan. However, there are limited published petrophysical data sets on these carbonate rocks and are essential for field development and risk reduction. To fill this knowledge gap, this study is mainly established to collect the comprehensive high quality data sets on petrophysical properties of carbonate rocks along with their mineralogy and microstructure. Additionally, the study assesses the impact of diagenesis on quality of the unconventional tight carbonate resources. Experimental techniques include Scanning Electronic Microscopy (SEM), Energy-Dispersive X-ray Spectroscopy (EDS), and X-ray diffraction (XRD), photomicrography, Helium porosity and steady state gas permeability. Results revealed that the porosity was in range of 2.12 to 8.5% with an average value of 4.5% and the permeability was ranging from 0.013 to 5.8mD. Thin section study, SEM-EDS, and XRD analyses revealed that the samples mostly contain carbon (C), calcium (Ca), and magnesium (Mg) as dominant elemental components.The main carbonate components observed were calcite, dolomite, micrite, Ferron mud, bioclasts and intermixes of clay minerals and cementing materials. The analysis shows that: 1) the permeability and porosity cross plot, the permeability and slippage factor values cross plots appears to be scattered, which showed weaker correlation that was the reflection of carbonate rock heterogeneity. 2) The permeability and clay mineralogy cross plots have resulted in poor correlation in these carbonate samples. 3) Several diagenetic processes had influenced the quality of carbonates of Jakkher Group, such as pore dissolution, calcification, cementation, and compaction. 4) Reservoir quality was mainly affected by inter-mixing of clay, cementation, presence of micrite muds, grain compactions, and overburden stresses that all lead these carbonate reservoirs to ultra-tight reservoirs and are considered to be of very poor quality. 5) SEM and thin section observations shows incidence of micro-fractures and pore dissolution tended to improve reservoir quality.

OIL GEOCHEMISTRY AND POTENTIAL SOURCE ROCKS OF THE OFFICER BASIN, SOUTH AUSTRALIA

1980 ◽  
Vol 20 (1) ◽  
pp. 68 ◽  
Author(s):  
D.M. McKirdy ◽  
A.J. Kantsler
Keyword(s):  
Organic Matter ◽  
Organic Carbon ◽  
Carbonate Rocks ◽  
Depositional Environment ◽  
South Australia ◽  
Source Rocks ◽  
Potential Source ◽  
Playa Lake ◽  
Oil Source ◽  
Extractable Organic Matter

Oil shows observed in Cambrian Observatory Hill Beds, intersected during recent stratigraphic drilling of SADME Byilkaoora-1 in the Officer Basin, indicate that oil has been generated within the basin. Shows vary in character from "light" oils exuding from fractures through to heavy viscous bitumen in vugs in carbonate rocks of a playa-lake sequence.The oils are immature and belong to two primary genetic families with some oils severely biodegraded. The less altered oils are rich in the C13 - C25 and C30 acyclic isoprenoid alkanes. Source beds within the evaporitic sequence contain 0.5 - 1.0% total organic carbon and yield up to 1900 ppm solvent-extractable organic matter. Oil-source rock correlations indicate that the oils originated within those facies drilled; this represents the first reported examples of non-marine Cambrian petroleum. The main precursor organisms were benthonic algae and various bacteria.Studies of organic matter in Cambrian strata from five other stratigraphic wells in the basin reveal regional variations in hydrocarbon source potential that relate to differences in precursor microbiota and/or depositional environment and regional maturation. Micritic carbonates of marine sabkha origin, located along the southeast margin of the basin, are rated as marginally mature to mature and good to prolific sources of oil. Further north and adjacent to the Musgrave Block, Cambrian siltstones and shales have low organic carbon values and hydrocarbon yields, and at best are only marginally mature. Varieties of organic matter recognised during petrographic studies of carbonates in the Officer Basin include lamellar alginite (alginite B) and "balls" of bitumen with reflectance in the range 0.2 to 1.4%.

Notes on Carbonate Reservoir Rocks, No. 4: Determination of Permeability of Carbonate Rocks from Thin-Section Analysis

1986 ◽  
Vol 8 (4) ◽  
pp. 369-380 ◽  
Author(s):  
George V. Chilingarian ◽  
Chum Yang Zhang ◽  
Moayed Yusif Al-Bassam ◽  
Teh Fu Yen
Keyword(s):  
Thin Section ◽  
Carbonate Rocks ◽  
Carbonate Reservoir ◽  
Reservoir Rocks ◽  
Thin Section Analysis ◽  
Section Analysis

scholarly journals INFLUENCE OF ORGANIC MATTER AND IRON OXIDES ON THE COLOUR PROPERTIES OF A MICRITIC LIMESTONE FROM KEFALONIA

2004 ◽  
Vol 36 (1) ◽  
pp. 72 ◽  
Author(s):  
G. E. Christidis ◽  
N. Sakellariou ◽  
E. Repouskou ◽  
Th. Markopoulos
Keyword(s):  
Organic Matter ◽  
Iron Oxides ◽  
Carbonate Rocks ◽  
Organic Carbon Content ◽  
Colour Properties ◽  
Ultra High Purity ◽  
Proposed Model ◽  
Fe Oxyhydroxides ◽  
Micritic Limestone ◽  
Experimental Values

The influence of organic matter and iron oxides on the colour properties of an ultra-high purity micritic limestone from Kefalonia Island containing 99.7% calcite was studied. Colouring impurities, organic matter and iron-oxide, were added in the form of a xylitic lignite and a hematite-rich Fe-ore respectively. Both impurities decrease lightness (L*) and increase deviation from perfect white diffuser (AE*ab) as well as redness and yellowness of calcite. Organic matter affects colour properties to a greater degree than iron oxides. The results obtained were used in a model, which predicts lightness and AE*ab of white limestones and marbles from their Fe2Ü3 and organic carbon content. The theoretical values of L* and AE*ab of a series of known limestones and calcific marbles obtained from this model are comparable to experimental values determined using a colourimeter. Slight deviations between theoretical and experimental values are attributed to several factors, which include the different nature of iron oxides/oxyhydroxides (goethite or/and lepidocrocite and/or amorphous Fe-oxyhydroxides instead of hematite) and organic matter (kerogene instead of xylitic lignite) present in the carbonate rocks, the different particle size of calcite and impurities in the different carbonates, to the multiphase nature of the colouring impurities used in this study and to the possible existence of other Fe-rich phases such as Fe-carbonates in the limestones. The proposed model can facilitate quality control of limestone resources used as fillers and can be extended to dolomitic rocks.

scholarly journals Organic matter identification in source and reservoir carbonate in the Lower Cretaceous Mauddud Formation in Kuwait

GeoArabia ◽  
2005 ◽  
Vol 10 (4) ◽  
pp. 17-34
Author(s):  
Fowzia H. Abdullah ◽  
Bernard Carpentier ◽  
Isabelle Kowalewski ◽  
Frans van Buchem ◽  
Alain-Yves Huc
Keyword(s):  
Gas Chromatography ◽  
Organic Matter ◽  
Source Rock ◽  
Lower Cretaceous ◽  
Carbonate Rocks ◽  
Total Organic Matter ◽  
The South ◽  
Core Samples ◽  
The North ◽  
Kerogen Type

ABSTRACT The purpose of this study is to identify the source rock, reservoirs and nonproductive zones in the Lower Cretaceous Mauddud Formation in Kuwait, using geochemical methods. This formation is one of the major Cretaceous oil reservoirs. It is composed mainly of calcarenitic limestone interbedded with marl and glauconitic sands. Its thickness ranges from almost zero in the south to about 100 m (328 ft) in the north. A total of 99 core samples were collected from six oil fields in Kuwait: Raudhatain, Sabiriyah and Bahra in the north, and from the Burgan, Ahmadi and Magwa in the south. Well logs from these fields (gamma ray GR, sonic, resistivity, density) were correlated and used in the study. The core samples were screened for the amount and nature of the organic matter by Rock-Eval 6 pyrolysis (RE6) using reservoir mode. A set of samples was selected to study the properties of the organic matter including the soluble and insoluble organic parts. The geochemical characterisation was performed using different methods. After organic solvent extraction of rock samples, the solvent soluble organic matter or bitumen was characterised in terms of saturates, aromatics and heavy compounds (resins and asphaltenes). Then the hydrocarbon distribution of saturates was studied using gas chromatography (GC/FID) and gas chromatography-mass spectrometry (GC/MS) for tentative oil-source rock correlation. After mineral matrix destruction of previously extracted rocks, insoluble organic matter or kerogen was analysed for its elemental composition to identify kerogen type. The geology and the analytical results show similarities between the wells in the southern fields and the wells in the northern fields. Average Total Organic Matter (TOC) in the carbonate facies is 2.5 wt.% and the highest values (8.0 wt.%) are in the northern fields. The clastic intervals in the northern fields show higher total organic matter (1.3 wt.%) relative to the southern fields (0.6 wt.%). The total Production Index is higher in the carbonate (0.6) than the clastic section (0.3). This reflects the amount of extractable hydrocarbons, which are usually associated with the carbonate section in this formation, representing its reservoir section. Although the carbonate rocks are dominated by richer total organic matter, there are some intervals, with low total organic matter values (0.07 wt.%), representing its poor reservoir sections. The kerogen type varies between type II-III and III in the shales with a slightly better quality in the carbonate section. It is immature in almost all the studied fields. The composition of the rock extract has no relation with the rock type. Some sandstone show similar extract composition to the carbonate rocks in the reservoir intervals. The extracts from these intervals show different genetic nature than those in the shales. The maturity level in the reservoir extract is much higher than in the shale intervals. Thus, the oil accumulated in the reservoir might be largely related to migrated oil from a more mature source rock deposited in a clearly different environment than the associated shaly intervals. The best candidates being a more deeply buried Early Cretaceous Sulaiy Formation and Upper Jurassic Najmah Formation.

Micromorphological report on Chalton B Layer 3

1983 ◽  
Vol 49 (S2) ◽  
pp. mf55-mf57
Author(s):  
Richard Macphail
Keyword(s):  
Organic Matter ◽  
Thin Section ◽  
Gravel Size ◽  
Coarse Grains ◽  
Small Grains ◽  
Fine Gravel ◽  
Fine Organic ◽  
Fine Organic Matter ◽  
Bt Horizon

Layer 3 was examined in the fiela and provisionally interpreted as a Bt horizon. A sample (locaxion shown on fig.5) was examined in thin section in order to throw further light on how the layer had formed. It can be described as follows using the method and terminology of Brewer 1964, Bullock and Murphy 1979:- Homogeneous; well developed fine and meciium subangular blocky; total macrovoids (> 20 μm) 13.1%; smoothed orthovughs and channels occur intrapedally; silt-size mineral grains dominantly quartz; includes fine gravel-size flint; coarse grains angular; small grains moderately rounded; many fine void argillans (few medium); few compound ferri-argillans; few embedded argillans; common to many fine to medium matrans and matri-argillans; common to many irregular, and linear intrapedal clay concentrations; few fine to medium distinct ferromanganiferous nodules; finely mixed organic matter and medium organic matter fragments in matrix; fine organic matter and charcoal fragments in matrans; silt layers within compound matrans ana matri-argillans; silasepic; porphyroskelic.

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