Organic Matter In Source Rocks Research Articles

Catalysis and hydrogenation: volcanic activity and hydrocarbon generation in rift basins, eastern China

Major oil reserves in rift basins in eastern China are correlated with high quality source rocks. The high quality source rocks and their hydrocarbon generation are often related to volcanic activity in the basins. Three kinds of volcanic rocks in source rocks have been defined in the Songliao, Bohaiwan and North Jiangsu basins. Some of the volcanic rocks were formed in lacustrine environments during the deposition of source rocks. It is remarkable that a part of volcanic-derived materials serves as a source of nutrients for lacustrine organisms which resulted in the formation of the organic matter in source rocks with high organic C contents. Besides hydrothermal alteration, the volcanic minerals contributed catalysis and H 2 to thermal alteration of organic matter into hydrocarbons during burial and diagenesis of source rocks and volcanics. A series of thermal laboratory simulations were performed with various combinations of immature source rocks and natural mineral assemblages. Results indicate that a significant volume of H 2 was produced from the source rock mixed with olivine and zeolite; moreover, this combination provided a 3-fold increase in hydrocarbons. It is proposed that catalysis and hydrogenation by the volcanic minerals promote hydrocarbon generation, although organic matter type is significantly variable. Hydrocarbons are generated at a lower degree of thermal stress when the reaction mixture contains volcanic minerals, and have a heavier C isotopic composition, compared to the control set of experiments.

Geochemical characteristics of terrigenous- and marine-sourced oils in Hokkaido, Japan

Crude oils in Hokkaido, Japan, are divided into two genetic groups based on bulk properties, carbon-isotope compositions and biomarker distributions. One group is characterized by high carbon-isotope canonical variables ( Sofer, 1984), high wax and low sulfur content, high Pr/Ph ratios, low C 27/(C 27+C 29) sterane ratios, relatively low Ts/(Ts+Tm) ratios, and the absence of tricyclic terpanes and C 35 homohopanes. These characteristics suggest that the oils were generated mainly from terrigenous organic matter in source rocks deposited under highly oxic conditions. The other group is characterized by low canonical variables, low wax and high sulfur content, low Pr/Ph ratios, high C 27/(C 27+C 29) sterane ratios, relatively high Ts/(Ts+Tm) ratios, and the presence of tricyclic terpanes and C 35 homohopanes, properties that suggest that they were generated from marine shales. Based on the biomarker distributions, the terrigenous oils correlate to Paleogene coals and coaly shales, whereas the marine oils correlate to Miocene marine shales. The atomic H/C ratios of the coals indicate that they have oil-generating potential. The geographic distribution of the terrigenous and marine source rocks, and their thermal maturity control the distribution of the oils in Hokkaido. The geographic distribution of the Paleogene coal-bearing formations corresponds to the distribution of the terrigenous oils in central Hokkaido. The marine oils are restricted either to areas of high heat flow related to volcanic activity, or to the area with thick Neogene and Quaternary sediments, where the Miocene source rocks are buried deep enough for oil generation.

Resistant biomacromolecules in marine microalgae of the classes Eustigmatophyceae and Chlorophyceae: Geochemical implications

Non-hydrolysable macromolecular constituents (i.e. algaenans) were isolated from two out of seven marine microalgae investigated. Nannochloropsis salina and Nannochloropsis sp. from the class of Eustigmatophyceae produce highly aliphatic algaenans. Flash pyrolysis and chemical degradations with HI and RuO 4 allowed for the identification of their chemical structure, which is mainly composed of polyether-linked long-chain (up to C 36) n-alkyl units. The building blocks of this polymer were also recognized in lipid fractions. The green microalgae (Chlorophyceae) Chlorella spaerckii, Chlorococcum sp. and Nannochloris sp. were earlier thought to biosynthesize algaenans comprising aliphatic and/or aromatic moieties. However, a new isolation method utilizing trifluoroacetic acid (TFA) prior to the other hydrolyses revealed that the macromolecular material isolated from these three chlorophytes was either hydrolysable with TFA or artefacts from the former method. Similar to algaenans from fresh water green microalgae, the aliphatic eustigmatophyte algaenans are likely to be selectively preserved in depositional environments and might ultimately serve as source rock organic matter of marine crude oils. Furthermore, they may play an important role in the cycling of carbon.

Atomic H/C Ratio of Kerogen as an Estimate of Thermal Maturity and Organic Matter Conversion

In recent years, the atomic H/C (hydrogen to carbon) ratio of kerogen as a way to assess the quality of organic matter in source rocks has been overlooked in favor of the more easily determined Rock-Eval hydrogen index. Rock-Eval pyrolysis provides fast, inexpensive, quantitative (mg HC/g rock) data without requiring kerogen isolation from the rock. Because of the general scatter in the data, many source rock interpreters consider Rock-Eval pyrolysis to be a screening analysis. In this paper I describe the benefits of using H/C ratios in source rock evaluations and present new correlations between atomic H/C ratios and thermal maturity, organic matter conversion, and expulsion volumetrics. Atomic H/C ratios of pyrolyzed kerogens have been correlated to the extent of thermal conversion of organic matter for both type I and type II kerogens. The excellent agreement between stoichiometric calculated hydrogen and carbon loss to observed losses from hydrous pyrolysis maturation experiments suggests that kerogen H/C ratios are excellent indicators of thermal maturity for end-member kerogen types. These data also offer a method to estimate percent organic matter conversion, provided that both the initial and present H/C ratios of the kerogen are known. Present H/C ratios can be measured, and initial H/C ratios can be reasonably estimated, from microscopic organic analysis of kerogen. For oil-prone source rocks, typical immature type I kerogens have H/C ratios of 1.35-1.50, whereas type II kerogens have H/C ratios of 1.20-1.35. Correlations of the amount of expelled oil in hydrous pyrolysis experiments to atomic H/C ratio of the spent kerogen offer exploration geologists a quick estimate of oil expulsion volumes. Based on hydrous pyrolysis experiments, measured H/C ratios, and calculated original TOC (total organic carbon) values, first-order volumetric approximations were made on three basins containing mature source rocks. Results compared favorably with published approximate-oil-in-place estimates for the Williston basin (Bakken shale), Los Angeles basin (Nodular shale), and the Illinois basin (New Albany Shale).

Analysis of the Organic Matter in Oil Shales Distributed in Korea.

The organic matter in source rocks and oil shales distributed in the southeastern and southwestern parts of the Korean peninsular has been analyzed. A mixture of benzene, acetone and methanol was used to extract bitumen by Soxhlet extraction method. The extractable organic matter was separated into aliphatic hydrocarbons, aromatic hydrocarbons, and asphaltene by preparative thin layer chromatography. By urea adduction method, aliphatic hydrocarbons were separated into linear aliphatic hydrocarbons and cyclic or branched aliphatic hydrocarbons. The aliphatic hydrocarbons were analyzed by GC/FID and GC/MS. The gas chromatograms for linear aliphatic hydrocarbons showed the distribution of C12-C35 compounds. Generally, the odd number hydrocarbons were detected more than the even number hydrocarbons. From the total ion chromatograms and mass spectra of cyclic and branched aliphatic hydrocarbons, several compounds including 1-methylpropyl-cyclohexane were identified.

Burial History and Kinetic Modeling for Hydrocarbon Generation, Part I: The galo Model

This paper discusses the principles and applications of the GALO computer program, which generates numerical simulations of the evolution of a sedimentary basin. The program calculates variations in the sedimentary bed thickness, predicts the thermal regime in the sedimentary cover or in the basement, and estimates the potential hydrocarbon yield of the source rocks. Alternative methods for determining the magnitude of tectonic subsidence of the basement surface within the framework of a local isostasy model are applied to provide a detailed model of the sequential tectonic-thermal events involved in the development of the basin. The program determines reaction parameters controlling the maturation of the organic matter in source rocks; these parameters are based largely on the hydrocarbon pyrolysis yield data and the stage of maturation of the organic matter entered into the program. Neglecting this stage drastically displaces the reaction spectrum toward higher energies, leading to considerable underestimation of hydrocarbon output.

Aromatic sulfur compounds as maturity indicators for petroleums from the Buzuluk depression, Russia

This study demonstrated that phase state and compositional variations of hydrocarbons in the Buzuluk depression, Russia, are related to maturity levels of Devonian source rocks. Maturity levels of organic matter of source rocks estimated by Rock-Eval T max and vitrinite reflectance ( R o%) are in the range from ‘oil window’ to ‘overmature’ and increase from east to west in the depression. The volume of the gas-condensate deposits increases in the same direction. Geochemical analyses using GC with dual FID/FPD and GC-MS show the variation in distributions of aromatic sulfur compounds in oils and condensates with different maturity levels. Very mature petroleums are characterized by very low concentrations of benzothiophenes (BTs) and abundant methyldibenzothiphenes (MDBTs). Maturity parameters such as the 4-MDBT/1-MDBT and newly proposed dimethyldibenzothiophenes (DMDBT) ratios of sulfur aromatics correlate well with other maturity indicators based on hydrocarbon distributions in gasoline-range and saturate fractions of petroleum. Sulfur aromatic parameters work well over a wide range of catagenesis, showing no reversal at the advanced levels of thermal evolution and can efficiently discriminate very mature petroleums.

Quantitative modeling of organic matter connectivity in source rocks using fractal geostatistical analysis

Numerical modeling of hydrocarbon expulsion requires accurate assessment of the 3-D geometry and connectivity of hydrocarbon pathways (such as pore systems, organic matter networks, fractures, and stylolites) in source rocks. In this paper, a method combining scanning electron microscopy (SEM), digital image analysis, fractal geostatistical analysis, and a renormalization algorithm is developed to determine the 3-D geometrical properties, defined as organic matter connectivity factor (OCF), of these pathways in source rocks. The method is applied to derive fractal geostatistical models and the OCFs of organic matter networks (OMN) of fourteen source rocks with wide variation in total organic carbon (TOC) content and texture. The results show that the connectivity of the OMNs is affected by both the amount and distribution of organic matter in source rocks. Uniformly distributed OMNs lose 3-D connectivity when the TOC content is below approx. 6%, whereas OMNs with preferred orientation may maintain lateral connectivity at 4% and perhaps lower TOC content. Thus, in shales such as the Bakken in which vertical OMN connectivity may not exist, the fracture systems may provide not only primary migration pathway, but hydrocarbon reservoirs that are recharged through the laterally connected OMNs. The method developed in this paper can be used to quantify geological models and average geological properties over a wide range of scales and thereby provide reliable geometric parameters for basin modeling using a numerical technique.

Characterization and Evolution of Paleozoic Source Rock Organic Matter in Algerian Central Sahara: ABSTRACT

The objective of the proposed poster is to provide a knowledge of the evolution history of organic matter in an intracratonic basin. The Paleozoic source rocks (Ordovician - Silurian - Upper Devonian and Carboniferous) of the Algerian Central Sahara (Ahnet and Timimoun basins) experienced severe conditions of maturation during the geological history, therefore, the source rocks intervals are presently mature to overmature and only dry gas has been descovered throughout this zone. The several geochemical models (Genex, Basimod, Matoil) in addition to Afta and Zafta Data show that regionaly significant heating event occured with maximum palaeo-temperature and maximum gas generation at 300 +/- 30 My. However, high palaeotemperatures can not be explained only by the significant burial. An important anomalous heat flow is needed to explain the geothermal history. In this case, there has been no significant petroleum from the Paleozoic source rocks in this zone since this age; but following some assumptions, a certain hypothesis about a recent generation (-60 to -30 My) is now in discussion.

Petroleum geochemistry of the Talimu Basin

The Talimu Basin in China consists of a Paleozoic platform and a Meso-Cenozoic land block series. On the basis of sedimentological and tectonic studies of the Talimu Basin, it is proposed in this paper that two different kinds of oil-generating sub-basins and source beds are present, and responsible for the formation and accumulation of both marine and nonmarine hydrocarbons. A preliminary evaluation for different source beds within the basin has been carried out using the disciplines of sedimentology, lithofacies-paleogeography and organic geochemistry. We distinguish various depositional settings, with different oxidation and/or reduction features, by showing systematic differences in relative molecular distributions. These include characteristic facies-related biomarkers, such as tricyclic terpanes, pregpanes, fluorenes, dibenzofurans and dibenzothiophenes. Types of organic matter in source rocks are revealed by the presence/absence of land plant-derived biomarkers, including pimarane, abietane, dehydroabietane, fluoranthenes, chrysenes and perylenes. Kerogens, from black mudstones of the Saergan Formation and the Yingan Formation at the northwestern margin of the basin, have been selected for detailed examination of their hydrocarbon potential. Favorable regions for hydrocarbon prospecting in the basin are also discussed.

Expulsion from hydrocarbon sources: the role of organic absorption

The role of absorption of generated petroleum within solid organic matter in source rocks has been investigated. We conclude that absorption is a significant phenomenon and that selective absorption is one cause of observed compositional differences between migrated petroleum and petroleum (bitumen) extracted from source rocks. Evidence for absorption includes the frequently-noted correlation between extractable organic content and TOC. Absorption selectivity appears consistent with documented interactions between solvents and either coals or synthetic polymers. Preliminary modeling of selective absorption equilibrium gives compositions of absorbed versus free liquids that are consistent with observations. A method is described for including hydrocarbon absorption effects in predictive models of hydrocarbon generation and expulsion. A key part of this method is assessment of expulsion efficiency from source rocks, using geochemical measurements. When absorptive retention of generated hydrocarbon liquids is included in yield calculations, expulsion of oil from low Hydrogen Index sources (even with high TOC values) is delayed. This results in ultimately higher gas-oil ratios of expelled petroleum.

Thermal evolution of organic matter in source rocks — Experimental and scanning electron microscopic studies

Five major forms (lamellar, banded, crack-like, disseminated and segregated encrustation) of organic matter distribution in source rocks have been revealed under scanning electron microscope by using the heavy metal staining technique. The degree of organic impregnation is related to the amount of liquid hydrocarbons in the rocks, and from this relationship a rough estimation of organic matter can be made on the basis of electron microscopic observations. In conjunction with experimental studies it has been found that the distribution forms of organic matter are a function of its maturity in the process of thermal evolution and accordingly some microscopic criteria can be developed for the assessment of source rocks.

Identification of aryl isoprenoids in source rocks and crude oils: Biological markers for the green sulphur bacteria

A series of C 13 to C 31 aryl isoprenoids (1-alkyl,2,3,6-trimethylbenzenes) have been identified in reef-hosted oils and their source rocks from the Middle and Upper Silurian of the Michigan Basin and Middle Devonian of the Alberta Basin, Canada. Their structure has been confirmed by unambiguous synthesis of the C 14 member of the series. Their structure and isotopic composition indicate that they are derived from isorenieratene from the Chlorobiaceae family of sulphur bacteria. These results are consistent with geological and geochemical studies that show that the source rocks were deposited under metahaline to hypersaline sulphate and sulphide rich water columns. The distribution of other biomarkers in these oils and source rocks indicates that a diverse biota contributed organic matter to the source environment. In conjunction with the aryl isoprenoids, they show that there is a remarkable similarity in composition between the two sets of oils and source rocks despite their great temporal and geographic separation. This reflects the similarity of their environments and emphasizes the importance of sedimentary facies in controlling the composition of organic matter in source rocks and their derived oils.

Petroleum isotopic and biomarker composition related to source rock organic matter and depositional environment

A multivariate approach has been developed that separates oils derived from organic matter in nonmarine shales, marine shales, and marine carbonates. Some or all of the following analyses were completed on 43 oils from known source rocks: (1) C 30-sterane and monoaromatic steroid biomarker ratios, and (2) stable carbon and hydrogen isotope compositions of whole oil, saturates, and aromatics. Three-group discriminant analysis of the 28 oils whereall biomarker and isotopic data are available results in no misclassifications at a significance level of 99%. Using only carbon and hydroogen isotopic data for whole oils, saturates, and aromatics results in correct classifications of 82% for oils derived from marine shale organic matter and 100% for oils from the other two sources. Triangular plots probabilities can be used to distinguish oils derived from the three source rock organic matter end-members. Several publications describe classifications of “marine” vs “nonmarine” oils using stable carbon isotope ratios of the whole oil or the saturate and aromatic fractions. Our results confirm that these methods do not completely differentiate oils by source.

Pyrolytic Generation of Oxidized Carbon Species Estimated from Rock-Eval FID Response: ABSTRACT

The hydrogen index is defined as the amount of the S2 pyrolysis peak (in mg hydrocarbons) normalized to grams of total organic carbon (TOC) obtained from the usual Rock-Eval procedure. This value has been used to determine the type and, in part, the maturity of the organic matter in source rocks. When the same S2 peak (in mg hydrocarbons) is normalized to the grams of reactive organic carbon (ROC) actually consumed in the pyrolysis (measured by difference), one should expect a reasonably constant value between 1,110 and 1,330 mg S2/g ROC if all of the products of pyrolysis are hydrocarbons. However, this is not the case. The values of S2/ROC range from 700 to 1,400 mg S2/g ROC for samples having hydrogen index values above 200 mg HC/g TOC. Below a hydrogen index of approx mately 200 mg HC/g TOC, the value of S2/ROC decreases sharply. The low values of S2/ROC mean that FID-nondetectable carbon is being released probably as CO and CO2. The sharp decrease of this value in samples with lower hydrogen indices indicates that a large proportion of the reactive carbon is transformed to the oxidized species. This is true not only for type III kerogens, but also for the more mature type II kerogens with lower hydrogen indices. The amounts of CO and CO2 can be estimated from a plot of S2/ROC versus S2/TOC. The calculated amounts of CO and CO2 produced exceed that of CH4 in source rocks having a hydrogen index of 100 mg HC/g TOC. The effects of this phenomenon are significant both with respect to natural gas compositions an with respect to the role of CO2 as a possible medium for hydrocarbon migration. End_of_Article - Last_Page 472------------

Immature Oil and Condensate--Modification of Hydrocarbon Generation Model for Terrestrial Organic Matter

Petroleum has been found in Canadian frontier basins in reservoirs which have undergone low levels of thermal alteration (vitrinite reflectance <=0.6%Ro). Paraffin indices, stable carbon and hydrogen isotope contents, pristane to nC17 ratios, and diterpenoid biologic markers have been used to assess the level of maturity of the hydrocarbons in the reservoir independently of the level of maturity of the reservoir itself and of the surrounding shale units. In the Tertiary of the Beaufort-Mackenzie basin, naphthenic oils and condensates have been generated from terrestrially derived organic matter in source rocks juxtaposed with the reservoir at reflectance levels of 0.4 to 0.6%Ro. However, condensates discovered in reservoirs which are th rmally immature on the Labrador Shelf have undergone extensive vertical migration and can be classed as conventional mature to overmature condensates. Hydrocarbons discovered in the Lower Cretaceous of the Beaufort-Mackenzie basin and also those of the Scotian Shelf are more or less in place in that they are at a level of thermal alteration about equivalent to that of the reservoirs in which they are trapped. The source for the early oils and condensates is considered to be resinite occurring dispersed in coal fragments. The proportion of resinite, liptinite, and vitrinite in the organic matter of terrestrial source rocks strongly controls both the level of thermal alteration necessary for the section to function as an effective source rock and the ultimate product (gas, oil, or condensate) which will be generated.

Near-Surface Evidence of Migration of Natural Gas from Deep Reservoirs and Source Rocks

Gaseous hydrocarbons migrate to the surface in small quantities from deep source rocks and natural gas or crude oil accumulations. This process leads to anomalous concentrations of hydrocarbons in near-surface sediments. The hydrocarbon anomalies (amount and composition) are useful in exploration, because they may point to oil and gas reservoirs. The origin of hydrocarbon anomalies in shallow sediments is not a simple one. Methane in near-surface sediments may be caused by a combination of bacterial production of methane, leakage from reservoirs, and leakage of methane from thermal maturation of organic matter in source rocks. Organic geochemistry, especially carbon isotope techniques, have been used to recognize secondary fractionation processes caused by degassing or bacterial oxidation. Examples of geochemical surveys in onshore and offshore areas indicate secondary fractionations so small that gases from near-surface sediments and from reservoirs can be correlated by the geochemical data. The application of stable carbon isotopes is a significant step toward improving geochemical hydrocarbon surface exploration methods.

Oil and Organic Matter in Source Rocks of Petroleum

Practically all shales and carbonate rocks contain indigenous organic matter disseminated in three forms: (1) soluble hydrocarbons, which are similar in composition to the heavier fractions of crude oil found in reservoir rock, (2) soluble asphalt, which is similar to the asphaltic constituents of crude oil, and (3) insoluble organic matter (kerogen), which is pyrobituminous in nature. Non-reservoir ancient sediments have been found to contain up to 5 times as much oil as that reported from recent unconsolidated sediments off the Gulf and California coasts. A typical ancient petroleum source rock such as the Frontier shale in the Powder River Basin of Wyoming, which has yielded millions of barrels of oil to reservoirs in the past, still contains 6 barrels of oil, 20 barrels of asphalt, and about 250 barrels of kerogen per acre-foot. The distribution of this oil, asphalt, and kerogen within the non-reservoir rocks of a sedimentary basin varies between formations and between different facies of the same formation.