Rock-Eval Analysis Research Articles

Geochemical characterization of sedimentary organic matter by means of pyrolysis kinetic parameters

A new means to classify organic matter in rock samples using kinetic parameters is described. Kinetic parameters are computed for Rock-Eval comparative pyrolysis curves, using a single heating rate experiment. The kinetic parameters are computed by an improved Freeman-Carroll method, assuming an overall nth-order reaction. Kinetic parameters are used for characterizing the type and maturity of sedimentary organic matter. For kerogens, the kinetic parameters are obtained on extracted-rock samples. They provide a complementary determination of organic matter type, by using the S2 peak shape which is not described by the classical Rock-Eval parameters. For resins + asphaltenes, the kinetic parameters are computed on the S2′ pyrolysis curve obtained by comparative pyrolysis. They allow the determination of the type of kerogen from which they were derived and also their maturity level. The kinetic characterization can be applied directly to current Rock-Eval analysis and used in routine analysis, without changing the standard procedures but care should be taken for bitumen rich samples.

Laminated Black Shale-Chert Cyclicity in Woodford Formation (Upper Devonian of Southern Mid-Continent): ABSTRACT

The Woodford formation, a known hydrocarbon source rock, is contemporaneous with other mid-Paleozoic (Frasnian to Tournasian) black shales occurring throughout North America and Europe. Much of the Woodford formation in outcrop along the southern flank of the Arbuckle uplift (Carter County, Oklahoma) consists of rhythmic alternating beds of laminated black shale and chert. A time series analysis of the chert-black shale couplets displays an approximately 20-ka periodicity, suggesting that deposition was controlled by external orbital forcing of the earth (Milankovitch cyclicity). Total organic carbon ranges from 3 to 9% in the chert and from 10 to 28% in the black shale; carbonate carbon content is essentially zero. Carbon isotope (/delta//sup 13/C = -29 per mil), pyrolysis-gas chromatography, and Rock-Eval analyses indicate that the kerogen is of marine origin and is oil-prone type II. Except for the difference in organic carbon contents, the kerogens of the chert-black shale couplets are analytically similar.

Organic geochemistry of Cretaceous black shales from the Galicia Margin, Ocean Drilling Program Leg 103

Organic-carbon-rich “black shales” from three different Cretaceous episodes sampled during Ocean Drilling Program Leg 103 have been studied by organic geochemical methods. Rock-Eval analysis, carbon isotope data, and lipid biomarkers show organic matter to contain varying proportions of marine and continental materials. In Hauterivian-Barremian organic-carbon-rich turbiditic marlstones, major amounts of land-derived organic matter are found. Aptian-Albian black-colored shales are interspersed within green claystones, from which they differ by containing more marine organic matter. An abbreviated layer of black shale from the Cenomanian-Turonian boundary is dominated by well-preserved marine organic matter. Downslope transport and rapid reburial within a predominantly oxygenated deepwater setting created most of these examples of black shales, except for the Cenomanian-Turonian deposits in which deepwater anoxia may have been involved.

Light hydrocarbon redistribution in a shallow core from the Ravnefjeld formation on the Wegener Halvø, East Greenland

Twenty nine core samples, extending from the surface to 60 m depth, from the Upper Permian organic-rich Ravnefjeld Formation source rock of East Greenland have been analyzed for detailed light hydrocarbon composition. In addition, complementary organic carbon and Rock-Eval analysis, as well as some mineralogical and permeability analyses were carried out. The objective was partly to determine if the changes in light hydrocarbon composition reflect generation patterns (i.e. small-scale changes in kerogen type and amount) or are controlled primarily by redistribution processes. A second objective was to discuss possible modes by which hydrocarbon redistribution took place. The interval examined in the Ravnefjeld Formation is overmature (1.75% R o). Organic carbon contents (TOC) and hydrogen index values range mostly between 1.0–5.5% and 10–20 mg HC/g TOC respectively. The amount of hydrocarbons present in the examined section represent only a fraction of the total amount generated. Petroleum Expulsion Efficiency (PEE) exceeding 0.99 was calculated. Systematic changes of light hydrocarbon composition with depth indicate that effective redistribution has occurred over wide intervals. In particular, there is good evidence to suggest that there was major loss with chemical fractionation of molecular species by depletion into several zones of fractures and also towards the outcrop surface and that fracture occurrence is the single most important factor in controlling the present day hydrocarbon depth trends. In this paper, a novel scheme is presented for effective and objective comparison of hydrocarbon depth trends. The application of this method to elucidation of the migration mechanisms responsible for fractionation during hydrocarbon loss in the fractured zones is illustrated.

Petroleum Geology and Geochemistry of Middle Proterozoic McArthur Basin, Northern Australia II: Assessment of Source Rock Potential

Five potential source rocks have been discovered in the middle Proterozoic of the McArthur basin. The lacustrine Barney Creek Formation (McArthur Group) and the marine Velkerri Formation (Roper Group) compare favorably in thickness and potential with demonstrated petroleum source rocks in the Phanerozoic. The former contains up to 7% total organic carbon (TOC) and kerogen types I and II. TOC values in the latter range up to 6.5% and the kerogen is type II. Petrographic examination shows the organic matter is mostly lamalginite, which on maturation yields nonfluorescent and bitumen. Extractable hydrocarbon yields from mature samples indicate that good to excellent source rocks are present and there is ample evidence of migration having occurred. Tmax values derived from Rock-Eval analysis may be used to define maturation levels in much the same way as in Phanerozoic sediments. At low maturation levels, the reflectivities of lamalginite and bitumen are lower than vitrinite reflectance values calculated from methylphenanthrene indices, but converge in the mature zone. This convergence reflects both the inherent lower reflectivity of hydrogen-rich macerals and the source control on methylphenanthrene indices at low maturity. Maturation levels in McArthur Group sediments vary from marginally mature to overmature with abrupt changes over short distances associated with faults. Hydrocarbon generation occurred prior to the deposition of the younger Proterozoic sediments of the Roper Group. In contrast, the source rocks in the Roper Group re marginally mature to mature throughout the study area and are overmature only where they are affected by igneous intrusions. Considerations of burial history suggest that hydrocarbon generation may have occurred during deposition of the Roper Group although an early Paleozoic timing cannot be excluded.

Source Rock Potential of an Eocene Carbonate Slope: The Armancies Formation of the South-Pyrenean Basin, Northeast Spain: ABSTRACT

The Armancies Formation is an Eocene carbonate slope succession in the Catalonian South Pyrenean basin. It ranges from 500 to 700 m in thickness. The first 200 m are made of a thin-bedded facies of wackestones alternating with dark pelagic fauna of miliolid, ostracods, bryozoans, and planktonic foraminifers and show significant bioturbation. They also show a low organic content (< 0.5% TOC). The lime-mudstone beds show a massive structure or planar millimeter laminations. They may contain sparse pelagic fossils of planktonic foraminifers, ostracods, and dinoflagellates; they do not show any bioturbation, and have high TOC values, which can reach individual scores of about 14%. They qualify, therefore, as a typical oil shale. Rock-Eval Pyrolysis analysis affords a mean S{sub 2} value of 25 mg HC/g. Mean S{sub 1} value is around 1.0 mg HC/g. As is typical of an initial oil window, T{sub max} maturity parameter ranges from 432 to 440{degree}C (mean = 434{degree}C). This degree of evolution is in accordance with the very low value of carbonyl and carboxyl groups, as determined by IR spectrometry and NMR on Fischer assay extract. The proton NMR shows an aromatic/aliphatic hydrocarbon ratio of 1:4, as expected in earlier stages of catagenesis. N-alkanemore » gas chromatography profiles show n-C{sub 15} to n-C{sub 19} prevalence and that neither even nor odd carbon numbers prevail. This distribution perfectly matches that of typical sediments of marine origin and also agrees with obtained hydrogen index values (mean HI = 500 mg HC/g TOC). Sedimentological and geochemical results indicate an autochthonous marine organic matter and the potential of these slope shales is good oil-prone source beds.« less

Organic Facies of the Neogene Argillaceous Rocks in Noto Peninsula, Central Japan, with Special Reference to Geochemical Evaluation for Source Rock of Petroleum

The Neogene formations in the Noto Peninsula are widely distributed as an extention of the “Green tuff” basin formed in the inner zone of Northeast Japan. The Suzu and the Himi-Nadaura areas, among them, are well known as the standard Neogene sequences of the Noto-Hokuriku district, Central Japan.In order to obtain some information on geochemical evaluation for petroleum source rock, 119 argillaceous rock samples collected from each Formations of both areas mentioned above were examined through the stratigraphic variation of organic constituents and maturation obtained by extractable organic matter, visual kerogen and Rock-Eval analysis.The average values of organic carbon contents of the Nazimi and the Iizuka Formations (Middle Miocene) in the Suzu area, and the Sugata Formation (Middle Miocene) in the Himi-Nadaura area are high more than 2.0 per cent. They are higher than ones of the other Neogene oil field areas along the Japan Sea side. The results of Rock-Eval analysis, however, show that argillaceous source rocks from these Formations are immature in terms of organic maturation. Althogh the source rocks are immature, on the basis of those results and other geochemical and geological information, some considerations on the expectancy for the occurrence of immature hydrocarbon deposits in this distrct have been also presented.

Organic petrology and RockEval analysis of the Lower Carboniferous Emma Fiord Formation in Sverdrup Basin, Canadian Arctic Archipelago

Samples of the Lower Carboniferous Emma Fiord Formation from two localities in the Sverdrup Basin of Arctic Canada were examined using reflected white and fluorescent light. The samples from Kleybolte Peninsula on Ellesmere Island show a relatively high level of thermal maturity. In contrast, those from Grinnell Peninsula on Devon Island are immature to marginally mature and include subbituminous coals and oil shales. Two types of oil shales are distinguished on the basis of liptinite content, mineral matrix, RockEval pyrolysis analysis, and concentration of boron. One is characterized by a liptinite-rich, clay-carbonate matrix with a relatively high hydrogen index and boron content, and the other by a liptinite-poor carbonate matrix with a relatively low hydrogen index and boron content. Hydrogen-rich components of these shales consist of alginite, matrix bituminite and minor amounts of exsudatinite and sporinite. Kerogen Types III and IV comprise only minor components of the organic matter. Thermal maturity of the Grinnell Peninsula oil shales increases with depth. Matrix bituminite in these oil shales has seeped into cavities and microfractures in the kerogen Types III and IV, forming exsudatinite. The distribution and character of the organic constituents and also the concentration of boron in these samples indicate a fresh to brackish water environment.

Oil Generating Characteristics of Monterey Formation in Santa Maria Basin, California: ABSTRACT

Oil generation in the Monterey Formation is studied in a deep well in the Careaga Canyon area of the Santa Maria basin. Rock-Eval pyrolysis and total organic carbon analyses on extracted and unextracted samples indicate that oil generation begins early (425/sup 0/-430/sup 0/C T/sub max/) and reaches a peak below 12,000 ft (450/sup 0/C T/sub max/). At greater depths there is active condensate and gas generation. These data are used to derive chemical reactions kinetics for Monterey type kerogens. A one-dimensional quantitative basin analysis model was developed for the area. It shows that hydrocarbon generation is very rapid due to a high heating rate. This results in rapid oil generation and high expulsion efficiency, and causes kerogen maturation to lag behind hydrocarbon generation. This study elucidates the nature of hydrocarbon generation in the Monterey Formation and has important exploration and development applications in both onshore and offshore areas.

Effect of D2O on the transport of ascorbate across membranes of DPPC vesicles.

established. It should be stressed that the phenomenon described has only been observed under very specific experimental conditions thus far. If similar processes occur under different conditions, they may be of considerable importance in nature and industry. It is well known that steam reduces the decarboxylation temperature of calcite, but this has been attributed to the catalytic effect of H 2 0 o n the thermal decomposition [5]. At present we should enter a caveat against the use of wholerock Rock-Eval pyrolysis for typing kerogen from carbonate rocks if appreciable amounts of water are supplied to the system by any component of the rocks in the process of pyrolysis. A significant contribution of inorganically derived CO2 may then be obtained, even below 400 ~ which is generally regarded as the limit between organic and inorganic CO2 in Rock-Eval analysis. Indeed, elevated oxygen index values, based on high CO2 yields, have been reported for carbonate rocks [3, 4].

Preliminary analysis of the hydrocarbon source rock potential of central and western North Greenland

During the 1984 field season potential hydrocarbon source rocks were studied in central and western North Greenland. Samples from most lithostratigraphic units were collected from Freuchen Land in the north-east to Washington Land in the south-west. Preliminary results from LECO, Rock-Eval and palynofacies analyses suggest that some intervals in the Cambrian shelf sequence and in the Ordovician and Silurian trough sequence have enough organic matter to qualify as source rocks. Most of the trough sequence is, however, thermally postrnature with respect to oil generation and only the Cambrian Brønlund Fjord Group is expected to have been the source of the oil accumulations in the subsurface.

Preliminary organic petrography of Palaeozoic rocks from the Grand Banks, Newfoundland

Samples of lower Palaeozoic bedrock from the Grand Banks of Newfoundland were examined using reflected light microscopy and Rock-Eval pyrolysis. These samples contained organic material which included bitumen (structureless organic material), acritarchs, chitinozoa, scolecodonts and graptolites. The reflectance of the organic material increased from acritarchs towards graptolites with bitumen showing a wide range of reflectance. Multiple phases of oil migration through one sample were inferred by examination of the bitumens: the lowest reflecting being more recent than the highest reflecting bitumen. Combined reflectance and Rock-Eval analysis indicate that these samples are mature to overmature. The two oldest samples (Arenig-Llanvirn, Ordovician) are assessed as mature and as having potential for generation of liquid hydrocarbons, but must be considered as mainly gas prone.

Comparison Between Immature Vitrinite and Solid Bitumen, Green River Formation, Piceance Creek Basin, Colorado: ABSTRACT

A major problem in organic petrography is the inability to distinguish immature vitrinite from solid bitumen. For this study, several samples of coal and solid bitumen, found interlayered with oil shales of the Green River Formation, were collected from three continuous cores. Each sample was analyzed under oil immersion with reflected light, with fluorescence (blue light), and by Rock-Eval. In the uppermost part of the cores, the vitrinite and solid bitumen have identical reflectance values under oil immersion (Ro), and the structureless (nonbanded, noncellular) vitrinite is optically indistinguishable from the bitumen. Observation with blue light reveals some details in both the vitrinite and the bitumen; solid bitumen appears more granular than the vitrinite. With the yellow filter, vitrinite shows some banding and spores are visible. Without the filter, the bitumen has an orange-brown hue, whereas the vitrinite is a bright blue. Rock-Eval analysis indicated a much higher hydrogen index for the bitumen (800-850) than for the coal (400-450). The total organic carbon (TOC) was higher for the coal (50-55) than for the bitumen (20-25). In the cores examined, the vitrinite reflectance changes downhole from 0.20 to 0.55; however, the Ro for the bitumen remains constant. Because reflectance values for vitrinite and solid bitumen can be the same or very similar, a researcher should not rely on reflectance values alone to distinguish vitrinite from solid bitumen. End_of_Article - Last_Page 293------------

Comparison between natural and artificial maturation series of humic coals from the Mahakam delta, Indonesia

Type III (humic) organic matter from the Mahakam delta (Indonesia) was chosen to compare artificial and natural coal series. Powdered and concentrated immature organic matter was heated in sealed gold tubes for 24 hr at temperatures ranging from 250 to 550°C and under pressures ranging from 0.5 to 4 kb, with and without water. Both elemental and Rock-Eval analyses were used to characterize the products. A comparison between our results, published data and the natural model shows that, quantitatively, natural maturation is simulated better when pyrolysis is performed under confined conditions (no free volume, no diluting inert gas). Thus, pyrolysis in a medium swept by an inert gas, vacuum pyrolysis and some pyrolysis in sealed glass tubes must be considered to be poor simulation tools. The presence of water does not seem to have an essential effect. Allowing the hydrocarbons formed to reach a certain value of partial pressure seems to be important. Results are unchanged when external pressure varies from 0.5 to 4 kb.

Organic Petrology of Selected Oil Shale Samples from Lower Carboniferous Albert Formation, New Brunswick, Canada: ABSTRACT

Incident light microscopy was used to describe maturation and composition of organic material in oil shale samples from the Lower Carboniferous Albert Formation of New Brunswick. The maturation level was determined in normal (white) light by measuring vitrinite reflectance and in fluorescent light by measuring fluorescence spectra of alginite B. Results indicate low to intermediate maturation for all of the samples. Composition was determined by maceral analysis. Alginite B is the major organic component in all samples having significant oil potential. Oil yields obtained from the Fischer Assay process, and oil and gas potentials from Rock-Eval analyses correlate to the amounts of alginite B and bituminite determined in the samples. In some of the samples characterized by similar high concentrations of alginite B, decrease in Fischer Assay yields and oil and gas potentials is related to an increase in maturation, as expressed by increase in the fluorescence parameter ^lgrmax and red/green quotient of alginite B. Incident light microscopy, particularly with fluorescent light, offers a valuable tool for the identification of the organic matter in oil shales and for the evaluation of their oil and gas potentials. End_of_Article - Last_Page 494------------

Source rock potential of Bahamian Trough carbonates

Summary The organic content of fine-grained carbonate muds deposited in the intraplatform basins and canyons of the Bahamas range between 0.1 and 2.6% total organic carbon (TOC). Geochemical analyses suggest some of these muds are a potential source for hydrocarbon. Interbedded with the carbonate muds are porous carbonate sands and gravels which can serve as local reservoirs or serve as conduits for hydrocarbons to migrate into carbonate slope and platform reservoir facies. Ingeneral, periplatform oozes are lean (generally less than 0.5 to 1% TOC) whereas green muds, very likely the products of turbidity currents, have higher organic contents (0.5 to more than 2.5% TOC), but values of TOC vary considerably both within and between study areas. Tongue of the Ocean and Exuma Sound are less than 80 km apart but their average TOC values differ markedly, 1% and 0.33% respectively. Higher sedimentation rates in the Tongue of the Ocean are thought, in part, to be responsible for better preservation of organic matter. In Tongue of the Ocean, cyclic variations in TOC are correlated with fluctuations of sea-level. High stands of sea-level are recorded by aragonite-rich muds with TOC on the average 0.5% higher than the calcitic periplatform oozes deposited during low stands of sea-level. Organic fractions of green muds have δ 13 C values (−16.4‰ to −13.9‰ vs PDB) which are similar to platform carbonates, whereas lighter δ 13 C values of periplatform oozes reflect mixing of organic material derived from platform and pelagic sources. Rock-Eval analysis shows that the periplatform oozes are relatively rich in oxygen; this, along with their low organic contents, results in a poor source rock potential. The green muds range between type II (mixed gas and oil potential) and III (gas potential) source rocks, which, through favourable maturation, should generate hydrocarbons. Gas chromatographic analysis of organic matter evolved at relatively low temperatures (300°C) demonstrated that these immature sediments underwent vapourization and thermal cracking of relatively heat-sensitive or thermally labile material.

Frictional behaviour of lubricated rolling-contact elements

Two cultured chlorophyceae algae and two cyanobacteria-rich phytoplankton were separated into five fractions and characterized by 13C cross polarization/total sideband suppression (CP/TOSS) nuclear magnetic resonance spectroscopy (NMR), X-ray photoelectron spectroscopy (XPS), Rock-Eval and closed pyrolysis analyses. The structures of the acid nonhydrolyzable organic matter (NHOM) fractions were similar to those of poly(methylene)-rich aliphatic algaenan. We found that the cyanobacteria-rich phytoplankton contained aliphatic nonhydrolyzable biopolymers. The NMR and Rock-Eval analyses showed that the isolated NHOM exhibited high oil-prone potentials. Pyrolysis analysis of the field-collected NHOM from Liuhuahu Park in Guangzhou (GP_NHOM) indicated that it exhibited high oil-prone potential and comprised a long, saturated and unbranched hydrocarbon chain (up to C33) structural unit. The maximum oil and gaseous hydrocarbon generation potentials reached 55.9% and 7.2%, respectively and were very close to those derived from 13C CP/TOSS NMR, suggesting that 13C NMR is an effective approach for evaluation of oil and gas production potentials. This investigation is helpful for improving understanding of kerogen formation mechanisms through selective preservation and the generation mechanisms of biocrude oil.