Solid bitumens: an assessment of their characteristics, genesis, and role in geological processes

Familiar since antiquity, and subject in contemporary times to various characterization schemes, the exact nature of solid bitumen is not yet fully known. Bitumens have ‘random polymer-like’ molecular structures, are mobile as highly viscous fluids or were once fluids but have since turned into solids. Solid bitumens consist mainly of large moieties, of polyclyclic aromatic hydrocarbons, occasionally with finely admixed, fine-grained cryptocrystalline graphite. Solid bitumens are distinguished from kerogen, which is the syngenetic and generally finely dispersed particulate organic matter in sedimentary rock that virtually does not migrate following its deposition. Occurrences of solid bitumens are relevant to petroleum exploration as well as the search for, and evaluation of, a variety of metallic mineral deposits. Genesis of bitumen is in many cases linked to the thermal and hydrothermal history of organic matter in sedimentary rock. Apparently bitumen, or more specifically organic acids generated along with bitumen during diagenesis, may alter porosity of reservoir rocks or otherwise prepare the ground for ore deposition. Bitumen is also relatively sensitive to alteration processes, some of which, such as oxidative weathering, water leaching, biodegradation (contact) metamorphism and ionizing radiation may likewise affect its nature. Elemental composition of bitumen commonly reflects the nature of mineral deposits. Is is possible that in petroleum exploration, trace metal abundances of bitumen may eventually allow prediction of crude oil types and volumes anticipated from a given source rock? Beside transition elements, notably Ni and V, highly anomalous concentrations of U, Pt and Au occur in some solid bitumens. During the generation of petroleum from kerogen, the trend in δ¹³C is toward lighter values. The opposite seems to occur when liquid petroleum is subjected to thermal cracking (and /or related processes) yielding solid bitumen enriched in ¹³C, and isotopically light methane. In fact, except for deasphalting and possibly some irradiation processes, the result of thermal cracking, oxidation, water leaching, inspissation (drying) and bacterial degradation of crude oil is that lower molecular weight hydrocarbons are removed leaving bitumen residues enriched in aromatic hydrocarbons, heteroatomic compounds (NSO) and ¹³C. Such phenomena are relevant to bitumen paragenesis in petroleum reservoir rocks, to certain Phanerozoic occurrences of multiple generations of bitumens, and to bitumens in mineral deposits.     

Biological marker distribution in coexisting kerogen, bitumen and asphaltenes in Monterey Formation diatomite, California

Organic-rich (18.2%) Monterey Formation diatomite from California was studied. The organic matter consist of 94% bitumen and 6% kerogen. Biological markers from the bitumen and from pyrolysates of the coexisting asphaltenes and kerogen were analyzed in order to elucidate the relationship between the various fractions of the organic matter. While 17 alpha(H), 18 alpha(H), 21 alpha(H)-28,30-bisnorhopane was present in the bitumen and in the pryolysate of the asphaltenes, it was not detected in the pyrolysates of the kerogen. A C40-isoprenoid with "head to head" linkage, however, was present in pyrolysates of both kerogen and asphaltenes, but not in the bitumen from the diatomite. The maturation level of the bitumen, based on the extent of isomerization of steranes and hopanes, was that of a mature oil, whereas the pyrolysate from the kerogen showed a considerably lower maturation level. These relationships indicate that the bitumen may not be indigenous to the diatomite and that it is a mature oil that migrated into the rock. We consider the possibility, however, that some of the 28,30-bisnorhopane-rich Monterey Formation oils have not been generated through thermal degradation of kerogen, but have been expelled from the source rock at an early stage of diagenesis.     

The characteristics of the biomarkers and δ13C of n-alkanes released from thermally altered solid bitumens at various maturities by catalytic hydropyrolysis

Solid bitumen occurs extensively in the paleo-reservoirs of marine sequences in southern China. The fluids in these paleo-reservoirs have usually experienced severe secondary alteration such as biodegradation and/or thermal maturation. The concentrations of extractable organic matter (EOM) in the resulting solid bitumens are too low to satisfy the amount required for instrumental analysis such as GC–MS and GC–IRMS. It is also difficult to get enough biomarkers and n-alkanes by dry pyrolysis or hydrous pyrolysis directly because such solid bitumens are hydrogen poor due to high maturities. Catalytic hydropyrolysis (HyPy) can release much more EOM from solid bitumen at mature to highly over-mature stages than Soxhlet extraction, dry pyrolysis and hydrous pyrolysis. However, whether the biomarkers in hydropyrolysates can be used for bitumen-source or bitumen–bitumen correlations has been questionable. In this study, a soft biodegraded solid bitumen sample of low maturity was thermally altered to various maturities in a closed system. HyPy was then employed to release bound biomarkers and n-alkanes. Our results show that the geochemical parameters for source and maturity based on biomarkers released from these thermally altered bitumen residues by HyPy are insensitive to the degree of thermal alteration. Furthermore, the maturity parameters are indicative of lower maturity than bitumen maturation products at a corresponding temperature. This suggests that biomarker source and maturity parameters, based on the products of HyPy, remain valid for bitumens which have suffered both biodegradation and severe thermal maturation. The distributions of δ¹³C of n-alkanes in hydropyrolysates are also insensitive to the temperature used for bitumen artificial maturation. Hence, the δ¹³C values of n-alkanes in hydropyrolysates may also provide useful information in bitumen–bitumen correlation for paleo-reservoir solid bitumens.     

Vanadyl porphyrins in exploration: maturity indicators for source rocks and oils

The Porphyrin Maturity Parameter (PMP), which is derived from the vanadyl porphyrin distribution, is an excellent parameter for: (1) identifying the zone of hydrocarbon generation from marine source rock extracts; and (2) determining from oils the thermal maturity of their source rocks at expulsion.The PMP is measured using a methodology which is inexpensive, reliable and faster than earlier methods, allowing it to be used as a routine exploration tool. The PMP may be a more reliable maturity indicator for marine organic matter than some conventional methods such as vitrinite reflectance. Unlike most conventional maturity parameters guided by processes other than kerogen conversion, the reactions causing PMP evolution directly monitor the generation of bitumen and the concurrent thermal degradation of kerogen.Measurements on hydrous pyrolyzates from the Monterey Formation (offshore California), source rock bitumens from the Devonian-Mississippian Bakken Shale (Williston Basin), and Miocene Monterey equivalent source strata (San Joaquin Basin, California) illustrate the method. In all cases reviewed so far, PMP begins increasing at the onset of hydrocarbon generation and increases systematically and predictably as kerogen decomposition proceeds.In oils generated from high-S marine kerogens, PMP reflects the maturity of the source rock at the time of oil expulsion, provided that the oil does not undergo subsequent reservoior maturation or mixing with in-situ bitumen.     

Stable sulfur isotope partitioning during simulated petroleum formation as determined by hydrous pyrolysis of Ghareb Limestone, Israel

Hydrous pyrolysis experiments at 200 to 365°C were carried out on a thermally immature organic-rich limestone containing Type-IIS kerogen from the Ghareb Limestone in North Negev, Israel. This work focuses on the thermal behavior of both organic and inorganic sulfur species and the partitioning of their stable sulfur isotopes among organic and inorganic phases generated during hydrous pyrolyses. Most of the sulfur in the rock (85%) is organic sulfur. The most dominant sulfur transformation is cleavage of organic-bound sulfur to form H₂S_(gas). Up to 70% of this organic sulfur is released as H₂S_(gas) that is isotopically lighter than the sulfur in the kerogen. Organic sulfur is enriched by up to 2‰ in ³⁴S during thermal maturation compared with the initial δ³⁴S values. The δ³⁴S values of the three main organic fractions (kerogen, bitumen and expelled oil) are within 1‰ of one another. No thermochemical sulfate reduction or sulfate formation was observed during the experiments. The early released sulfur reacted with available iron to form secondary pyrite and is the most ³⁴S depleted phase, which is 21‰ lighter than the bulk organic sulfur. The large isotopic fractionation for the early formed H₂S is a result of the system not being in equilibrium. As partial pressure of H₂S_(gas) increases, retro reactions with the organic sulfur in the closed system may cause isotope exchange and isotopic homogenization. Part of the δ³⁴S-enriched secondary pyrite decomposes above 300°C resulting in a corresponding decrease in the δ³⁴S of the remaining pyrite. These results are relevant to interpreting thermal maturation processes and their effect on kerogen-oil-H₂S-pyrite correlations. In particular, the use of pyrite-kerogen δ³⁴S relations in reconstructing diagenetic conditions of thermally mature rocks is questionable because formation of secondary pyrite during thermal maturation can mask the isotopic signature and quantity of the original diagenetic pyrite. The main transformations of kerogen to bitumen and bitumen to oil can be recorded by using both sulfur content and δ³⁴S of each phase including the H₂S_(gas). H₂S generated in association with oil should be isotopically lighter or similar to oil. It is concluded that small isotopic differentiation obtained between organic and inorganic sulfur species suggests closed-system conditions. Conversely, open-system conditions may cause significant isotopic discrimination between the oil and its source kerogen. The magnitude of this discrimination is suggested to be highly dependent on the availability of iron in a source rock resulting in secondary formation of pyrite.     

珠江口盆地番禺低隆起-白云凹陷北坡干酪根热演化模拟与生烃

通过密封金管-高压釜体系对珠江口盆地番禺低隆起-白云凹陷北坡恩平组炭质泥岩的干酪根(PY),在24.1 MPa压力、20℃/hr(373.5~526℃)和2℃/h(343~489.2℃)两个升温速率条件下进行热模拟生烃实验,分析气态烃(C1 5)和液态烃(C6 14和C14+)的产率,以及沥青质和残余有机质碳同位素组成。同时与Green River页岩(GR)和Woodford泥岩(WF)的干酪根,分别代表典型的I型和II型干酪根进行对比研究。结果显示PY热演化产物中总油气量明显低于GR和WF干酪根,且气态烃(C1 5)最高产率是液态烃的1.5倍,揭示恩平组炭质泥岩主要以形成气态烃为主。在热演化过程中,有机质成熟度和母质类型是控制油气比的主要因素,气态烃和轻烃的产率比值主要受热演化成熟度的影响。干酪根残余有机质碳同位素和沥青质碳同位素在热演化过程中受有机质成熟度的影响较小,δ13C残余和δ13C沥青质可以间接反映原始母质的特征,为高演化烃源岩油气生成提供依据。     

Role of water in hydrocarbon generation from Type-I kerogen in Mahogany oil shale of the Green River Formation

Hydrous and anhydrous closed-system pyrolysis experiments were conducted on a sample of Mahogany oil shale (Eocene Green River Formation) containing Type-I kerogen to determine whether the role of water had the same effect on petroleum generation as reported for Type-II kerogen in the Woodford Shale. The experiments were conducted at 330 and 350 °C for 72 h to determine the effects of water during kerogen decomposition to polar-rich bitumen and subsequent bitumen decomposition to hydrocarbon-rich oil. The results showed that the role of water was more significant in bitumen decomposition to oil at 350 °C than in kerogen decomposition to bitumen at 330 °C. At 350 °C, the hydrous experiment generated 29% more total hydrocarbon product and 33% more C₁₅₊ hydrocarbons than the anhydrous experiment. This is attributed to water dissolved in the bitumen serving as a source of hydrogen to enhance thermal cracking and facilitate the expulsion of immiscible oil. In the absence of water, cross linking is enhanced in the confines of the rock, resulting in formation of pyrobitumen and molecular hydrogen. These differences are also reflected in the color and texture of the recovered rock. Despite confining liquid-water pressure being 7-9 times greater in the hydrous experiments than the confining vapor pressure in the anhydrous experiments, recovered rock from the former had a lighter color and expansion fractures parallel to the bedding fabric of the rock. The absence of these open tensile fractures in the recovered rock from the anhydrous experiments indicates that water promotes net-volume increase reactions like thermal cracking over net-volume decrease reactions like cross linking, which results in pyrobitumen. The results indicate the role of water in hydrocarbon and petroleum formation from Type-I kerogen is significant, as reported for Type-II kerogen.     

The effect of oil expulsion or retention on further thermal degradation of kerogen at the high maturity stage: A pyrolysis study of type II kerogen from Pingliang shale,China

High maturity oil and gas are usually generated after primary oil expulsion from source rocks, especially from oil prone type I/II kerogen. However, the detailed impacts of oil expulsion, or retention in source rock on further thermal degradation of kerogen at the high maturity stage remain unknown. In the present study, we collected an Ordovician Pingliang shale sample containing type II kerogen. The kerogens, which had previously generated and expelled oil and those which had not, were prepared and pyrolyzed in a closed system, to observe oil expulsion or oil retention effects on later oil and gas generation from kerogen. The results show that oil expulsion and retention strongly impacts on further oil and gas generation in terms of both the amount and composition in the high maturity stage. Gas production will be reduced by 50% when the expulsion coefficient reaches 58%, and gas from oil-expelled kerogen (less oil retained) is much drier than that from fresh kerogen. The oil expulsion also causes n-alkanes and gas compounds to have heavier carbon isotopic compositions at high maturity stages. The enrichment of ¹³C in n-alkanes and gas hydrocarbons are 1‰ and 4–6‰ respectively, compared to fresh kerogen. Oil expulsion may act as open system opposite to the oil retention that influences the data pattern in crossplots of δ¹³C₂–δ¹³C₃ versus C₂/C₃, δ¹³C₂–δ¹³C₃ versus δ¹³C₁ and δ¹³C₁–δ¹³C₂ versus ln(C₁/C₂), which are widely used for identification of gas from kerogen cracking or oil cracking. These results suggest that the reserve estimation and gas/source correlation in deep burial basins should consider the proportion of oil retention to oil expulsion the source rocks have experienced.     

Evaluation of the petroleum composition and quality with increasing thermal maturity as simulated by hydrous pyrolysis: A case study using a Brazilian source rock with Type I kerogen

Hydrous pyrolysis (HP) experiments were used to investigate the petroleum composition and quality of petroleum generated from a Brazilian lacustrine source rock containing Type I kerogen with increasing thermal maturity. The tested sample was of Aptian age from the Araripe Basin (NE-Brazil). The temperatures (280–360 °C) and times (12–132 h) employed in the experiments simulated petroleum generation and expulsion (i.e., oil window) prior to secondary gas generation from the cracking of oil. Results show that similar to other oil prone source rocks, kerogen initially decomposes in part to a polar rich bitumen, which decomposes in part to hydrocarbon rich oil. These two overall reactions overlap with one another and have been recognized in oil shale retorting and natural petroleum generation. During bitumen decomposition to oil, some of the bitumen is converted to pyrobitumen, which results in an increase in the apparent kerogen (i.e., insoluble carbon) content with increasing maturation.The petroleum composition and its quality (i.e., API gravity, gas/oil ratio, C₁₅₊ fractions, alkane distribution, and sulfur content) are affected by thermal maturation within the oil window. API gravity, C₁₅₊ fractions and gas/oil ratios generated by HP are similar to those of natural petroleum considered to be sourced from similar Brazilian lacustrine source rocks with Type I kerogen of Lower Cretaceous age. API gravity of the HP expelled oils shows a complex relationship with increasing thermal maturation that is most influenced by the expulsion of asphaltenes. C₁₅₊ fractions (i.e., saturates, aromatics, resins and asphaltenes) show that expelled oils and bitumen are compositionally separate organic phases with no overlap in composition. Gas/oil ratios (GOR) initially decrease from 508–131 m³/m³ during bitumen generation and remain essentially constant (81–84 m³/m³) to the end of oil generation. This constancy in GOR is different from the continuous increase through the oil window observed in anhydrous pyrolysis experiments. Alkane distributions of the HP expelled oils are similar to those of natural crude oils considered to be sourced from similar Brazilian lacustrine source rocks with Type I kerogen of Lower Cretaceous age. Isoprenoid and n-alkane ratios (i.e., pristane/n-C₁₇ and phytane/n-C₁₈) decrease with increasing thermal maturity as observed in natural crude oils. Pristane/phytane ratios remain constant with increasing thermal maturity through the oil window, with ratios being slightly higher in the expelled oils relative to those in the bitumen. Generated hydrocarbon gases are similar to natural gases associated with crude oils considered to be sourced from similar Brazilian lacustrine source rocks with Type I kerogen of Lower Cretaceous, with the exception of elevated ethane contents. The general overall agreement in composition of natural and hydrous pyrolysis petroleum of lacustrine source rocks observed in this study supports the utility of HP to better characterize petroleum systems and the effects of maturation and expulsion on petroleum composition and quality.     

The influence of hydrocarbon expulsion on carbon isotopic compositions of individual n-alkanes in pyrolysates of selected terrestrial kerogens

Expulsion of petroleum from source rock is a complex part of the entire migration process. There exist fractional effects on chemical compositions in hydrocarbon expulsion. Does the carbon isotopic fractionation occur during expulsion and to what extent? Here the influence of hydrocarbon expulsion on carbon isotopic compositions of individual n-alkanes from pyrolysates of selected terrestrial kerogens from Tuha basin and Fushun, Liaoning Province of China has been experimentally studied. The pyrogeneration-expulsion experiments were carried out under semi-closed system. The carbon isotopic compositions of individual n-alkanes were measured by GC-IRMS. The main conclusions are as follows. First, there is carbon isotopic fractionation associated with hydrocarbon expulsion from Type III kerogens in Tuha Basin. There exist differences of carbon isotopic compositions between the unexpelled n-alkanes and expelled n-alkanes from Tuha desmocollinite and Tuha mudstone. Second, there is almost no carbon isotopic fractionation associated with hydrocarbon expulsion from Type II kerogens in Fushun and Liaohe Basin. Third, carbon isotopic fractionation in hydrocarbon expulsion should be considered in making oil-source correlation of Type III kerogens at least in the Tuha Basin. Further studies need to be carried out to determine whether this is true in other basins. Fourth, oil and source at different maturity levels cannot be correlated directly for Type III kerogens since the carbon isotopic compositions of expelled hydrocarbons at different temperatures are different. The expelled hydrocarbons are usually lighter (depleted in ¹³C) than the hydrocarbons remaining in the source rock at the same maturity.     

Biological markers in bitumens and pyrolyzates of Upper Cretaceous bituminous chalks from the Ghareb Formation (Israel)

The sterane and triterpane distributions of three bituminous chalks from the Upper Cretaceous Ghareb Formation (Israel) were investigated both in the original extractable bitumens and in extracts obtained after pyrolysis of whole rock and isolated kerogen samples at 450°C. Pyrolysis was performed in a closed system under hydrous (whole rock) and anhydrous conditions (isolated kerogens). The carbon number distributions of steranes and triterpanes differ significantly between original bitumen and pyrolyzates. Unlike the bitumens in which diasteranes were not detected, the anhydrous pyrolyzates contain small amounts of diasteranes. The presence of water during pyrolysis leads to an increase of sterane isomerization, the abundant formation of diasteranes and an increase of the $\text{18α(}\text{H}\text{)-}\text{trisnorneohopane}\text{17α(}\text{H}\text{)-}\text{trisnorhopane}$ ratio. Sterane isomerization maturation parameters show a closer match between original bitumen and pyrolyzates after pyrolysis in a closed system when compared with an open system.     

Changes in the composition of bitumen extracts and chemical structure of kerogen during hydrous pyrolysis

The paper presents data on the composition of biomarkers from bitumen extracts and the chemical structure of kerogen from C_org-rich sedimentary rocks before and after hydrothermal treatment in an autoclave at 300°C. Samples selected for this study are kukersite and Ordovician Dictyonema shale from the Baltics, Domanik oil shale from the Ukhta region, Upper Permian brown coal from the Pre-Ural foredeep, carbonaceous shale from the Oxfordian horizon of the Russian plate, and Upper Jurassic oil shales from the Sysola oil shale bearing region. The rocks contain type I, II, III, and II-S kerogens. The highest yield of extractable bitumen is achieved for Type II-S kerogen, whereas Type III kerogen produces the lowest amount of bitumen. The stages of organic matter thermal maturation achieved during the experiments correspond to a transition from PC_2–3 to MC_1–2. The ¹³C NMR data on kerogen indicate that the aromatic structures of geopolymers underwent significant changes.     

Isoprenoid constituents in kerogens as a function of depositional environment and catagenesis

The ratio of the abundance of the C_19:1 isoprenoids 1-pristene and 2-pristene to the abundance of (nC_17:1 + nC_17:0) is significantly lower in pyrolysates of kerogens from highly anoxic depositional environments than in pyrolysates of kerogen if similar types and levels of catagenesis from more oxic organic facies. ¹³C-NMR analysis shows that the occurrence of lower relative concentrations of isoprenoid precursors also correlates with the occurrence of low proportions of oxygen-bonded carbon and high proportion of aliphatic carbon in kerogens. The ratio of 1-pristene to (n-C_17:1 + nC_17:0) can be correlated laterally and statigraphically within a basin. There is no clearly discernible dependence of relative isoprenoid concentration of kerogen type for oil-generative kerogens, although immature lignites have high 1-pristene/(nC_17:1 + nC_17:0) ratios.The 1-pristene/(nC_17:1 + nC_17:0) ratios in kerogens pyrolysates from the same organic facies decrease logarithmically with increasing catagenesis and can be correlated directly with measured vitrinite reflectance values. Geologic and experimental data imply that 1-pristene precursors are lost from kerogen more rapidly than the precursors of the C₁₈ isoprenoid.The lower relative isoprenoid concentrations observed in anoxically deposited kerogens appear to be the result of the enhanced preservation of normal alkyl groups and the enhanced formation of free isophrenoids early in the sequence of kerogen alteration. These results are significant to the use of isoprenoids as geochemical marker oils, bitumens, and kerogens and to the determination of the structure and diagenesis of isoprenoid precursors.     

Comparison of natural gases accumulated in Oligocene strata with hydrous pyrolysis gases from Menilite Shales of the Polish Outer Carpathians

This study examined the molecular and isotopic compositions of gases generated from different kerogen types (i.e., Types I/II, II, IIS and III) in Menilite Shales by sequential hydrous pyrolysis experiments. The experiments were designed to simulate gas generation from source rocks at pre-oil-cracking thermal maturities. Initially, rock samples were heated in the presence of liquid water at 330 °C for 72 h to simulate early gas generation dominated by the overall reaction of kerogen decomposition to bitumen. Generated gas and oil were quantitatively collected at the completion of the experiments and the reactor with its rock and water was resealed and heated at 355 °C for 72 h. This condition simulates late petroleum generation in which the dominant overall reaction is bitumen decomposition to oil. This final heating equates to a cumulative thermal maturity of 1.6% R_r, which represents pre-oil-cracking conditions. In addition to the generated gases from these two experiments being characterized individually, they are also summed to characterize a cumulative gas product. These results are compared with natural gases produced from sandstone reservoirs within or directly overlying the Menilite Shales. The experimentally generated gases show no molecular compositions that are distinct for the different kerogen types, but on a total organic carbon (TOC) basis, oil prone kerogens (i.e., Types I/II, II and IIS) generate more hydrocarbon gas than gas prone Type III kerogen. Although the proportionality of methane to ethane in the experimental gases is lower than that observed in the natural gases, the proportionality of ethane to propane and i-butane to n-butane are similar to those observed for the natural gases. δ¹³C values of the experimentally generated methane, ethane and propane show distinctions among the kerogen types. This distinction is related to the δ¹³C of the original kerogen, with ¹³C enriched kerogen generating more ¹³C enriched hydrocarbon gases than kerogen less enriched in ¹³C. The typically assumed linear trend for δ¹³C of methane, ethane and propane versus their reciprocal carbon number for a single sourced natural gas is not observed in the experimental gases. Instead, the so-called “dogleg” trend, exemplified by relatively ¹³C depleted methane and enriched propane as compared to ethane, is observed for all the kerogen types and at both experimental conditions. Three of the natural gases from the same thrust unit had similar “dogleg” trends indicative of Menilite source rocks with Type III kerogen. These natural gases also contained varying amounts of a microbial gas component that was approximated using the Δδ¹³C for methane and propane determined from the experiments. These approximations gave microbial methane components that ranged from 13–84%. The high input of microbial gas was reflected in the higher gas:oil ratios for Outer Carpathian production (115–1568 Nm³/t) compared with those determined from the experiments (65–302 Nm³/t). Two natural gas samples in the far western part of the study area had more linear trends that suggest a different organic facies of the Menilite Shales or a completely different source. This situation emphasizes the importance of conducting hydrous pyrolysis on samples representing the complete stratigraphic and lateral extent of potential source rocks in determining specific genetic gas correlations.     

Release of sulfur- and oxygen-bound components from a sulfur-rich kerogen during simulated maturation by hydrous pyrolysis

An immature sulfur-rich marl from the Gessosso-solfifera Formation of the Vena del Gesso Basin (Messinian, Italy) has been subjected to hydrous pyrolysis (160 to 330°C) to simulate maturation under natural conditions. The kerogen of the unheated and heated samples was isolated and the hydrocarbons released by selective chemical degradation (Li/EtNH₂ and HI/LiAlH₄) were analysed to allow a study of the fate of sulfur- and oxygen-bound species with increasing temperature. The residues from the chemical treatments were also subjected to pyrolysis–GC to follow structural changes in the kerogens. In general, with increasing hydrous pyrolysis temperature, the amounts of sulfide- and ether-bound components in the kerogen decreased significantly. At the temperature at which the generation of expelled oil began (260°C), almost all of the bound components initially present in the unheated sample were released from the kerogen. Comparison with an earlier study of the extractable organic matter using a similar approach and the same samples provides molecular evidence that, with increasing maturation, solvent-soluble macromolecular material was initially released from the kerogen, notably as a result of thermal cleavage of weak carbon–heteroatom bonds (sulfide, ester, ether) even at temperatures as low as 220°C. This solvent-soluble macromolecular material then underwent thermal cleavage to generate hydrocarbons at higher temperatures. This early generation of bitumen may explain the presence of unusually high amounts of extractable organic matter of macromolecular nature in very immature S-rich sediments.     

Characterization of solid bitumens originating from thermal chemical alteration and thermochemical sulfate reduction

Solid bitumen can arise from several reservoir processes acting on migrated petroleum. Insoluble solid organic residues can form by oxidative processes associated with thermochemical sulfate reduction (TSR) as well as by thermal chemical alteration (TCA) of petroleum. TCA may follow non-thermal processes, such as biodegradation and asphaltene precipitation, that produce viscous fluids enriched in polar compounds that are then altered into solid bitumens. It is difficult to distinguish solid bitumen formed by TCA from TSR since both processes occur under relatively high temperatures. The focus of the present work is to characterize solid bitumen samples associated with TSR- or TCA-processes using a combination of solid-state X-ray Photoelectron Spectroscopy (XPS), Sulfur X-ray Absorption Near Edge Structure Spectroscopy (S-XANES), and ¹³C NMR. Naturally occurring solid bitumens from three locations, Nisku Formation, Brazeau River area (TSR-related); La Barge Field, Madison Formation (TSR-related); and, the Alaskan North Slope, Brooks Range (TCA-related), are compared to solid bitumens generated in laboratory simulations of TSR and TCA.The chemical nature of solid bitumens with respect to organic nitrogen and sulfur can be understood in terms of (1) the nature of hydrocarbon precursor molecules, (2) the mode of sulfur incorporation, and (3) their concentration during thermal stress. TSR-solid bitumen is highly aromatic, sulfur-rich, and nitrogen-poor. These heteroatom distributions are attributed to the ability of TSR to incorporate copious amounts of inorganic sulfur (S/C atomic ratio >0.035) into aromatic structures and to initial low levels of nitrogen in the unaltered petroleum. In contrast, TCA-solid bitumen is derived from polar materials that are initially rich in sulfur and nitrogen. Aromaticity and nitrogen increase as thermal stress cleaves aliphatic moieties and condensation reactions take place. TCA-bitumens from the Brooks Range have <75% aromatic carbon. TCA-bitumens exposed to greater thermal stress can have a higher aromaticity, like that observed in TSR-bitumens. Organic sulfur in TCA-organic solids remains relatively constant with increasing maturation (S/C atomic ratio <0.035) due to offsetting preservation and H₂S elimination reactions. Although S-XANES and ¹³C NMR provide information needed to understand changes in structure and reactivity that occur in the formation of petroleum solids, in some cases XPS analysis is sufficient to determine whether a solid bitumen is formed by TCA or TSR.     

Oil-generation kinetics for organic facies with Type-II and -IIS kerogen in the Menilite Shales of the Polish Carpathians

The Menilite Shales (Oligocene) of the Polish Carpathians are the source of low-sulfur oils in the thrust belt and some high-sulfur oils in the Carpathian Foredeep. These oil occurrences indicate that the high-sulfur oils in the Foredeep were generated and expelled before major thrusting and the low-sulfur oils in the thrust belt were generated and expelled during or after major thrusting. Two distinct organic facies have been observed in the Menilite Shales. One organic facies has a high clastic sediment input and contains Type-II kerogen. The other organic facies has a lower clastic sediment input and contains Type-IIS kerogen. Representative samples of both organic facies were used to determine kinetic parameters for immiscible oil generation by isothermal hydrous pyrolysis and S₂ generation by non-isothermal open-system pyrolysis. The derived kinetic parameters showed that timing of S₂ generation was not as different between the Type-IIS and -II kerogen based on open-system pyrolysis as compared with immiscible oil generation based on hydrous pyrolysis. Applying these kinetic parameters to a burial history in the Skole unit showed that some expelled oil would have been generated from the organic facies with Type-IIS kerogen before major thrusting with the hydrous-pyrolysis kinetic parameters but not with the open-system pyrolysis kinetic parameters. The inability of open-system pyrolysis to determine earlier petroleum generation from Type-IIS kerogen is attributed to the large polar-rich bitumen component in S₂ generation, rapid loss of sulfur free-radical initiators in the open system, and diminished radical selectivity and rate constant differences at higher temperatures. Hydrous-pyrolysis kinetic parameters are determined in the presence of water at lower temperatures in a closed system, which allows differentiation of bitumen and oil generation, interaction of free-radical initiators, greater radical selectivity, and more distinguishable rate constants as would occur during natural maturation. Kinetic parameters derived from hydrous pyrolysis show good correlations with one another (compensation effect) and kerogen organic-sulfur contents. These correlations allow for indirect determination of hydrous-pyrolysis kinetic parameters on the basis of the organic-sulfur mole fraction of an immature Type-II or -IIS kerogen.     

Hydrocarbon potential of the Sargelu Formation,North Iraq

Microscopic and chemical analysis of 85 rock samples from exploratory wells and outcrops in northern Iraq indicate that limestone, black shale and marl within the Middle Jurassic Sargelu Formation contain abundant oil-prone organic matter. For example, one 7-m (23-ft.)-thick section averages 442 mg?HC/g S2 and 439 °C Tmax (Rock-Eval pyrolysis analyses) and 16 wt.% TOC. The organic matter, comprised principally of brazinophyte algae, dinoflagellate cysts, spores, pollen, foraminiferal test linings and phytoclasts, was deposited in a distal, suboxic to anoxic basin and can be correlated with kerogens classified as type A and type B or, alternatively, as type II. The level of thermal maturity is within the oil window with TAI?=?3^? to 3⁺, based on microspore colour of light yellowish brown to brown. Accordingly, good hydrocarbon generation potential is predicted for this formation. Terpane and sterane biomarker distributions, as well as stable isotope values, were determined for oils and potential source rock extracts to determine valid oil-to-source rock correlations. Two subfamily carbonate oil types—one of Middle Jurassic age (Sargelu) carbonate rock and the other of Upper Jurassic/Cretaceous age—as well as a different oil family related to Triassic marls, were identified based on multivariate statistical analysis (HCA and PCA). Middle Jurassic subfamily A oils from Demir Dagh oil field correlate well with rich, marginally mature, Sargelu source rocks in well MK-2 near the city of Baiji. In contrast, subfamily B oils have a greater proportion of R₂₈ steranes, indicating they were generated from Upper Jurassic/Lower Cretaceous carbonates such as those at Gillabat oil field north of Mansuriyah Lake. Oils from Gillabat field thus indicate a lower degree of correlation with the Sargelu source rocks than do oils from Demir Dagh field. One-dimension petroleum system models of key wells were developed using IES PetroMod Software to evaluate burial-thermal history, source-rock maturity and the timing and extent of petroleum generation; interpreted well logs served as input to the models. The oil-generation potential of sulphur-rich Sargelu source rocks was simulated using closed system type II-S kerogen kinetics. Model results indicate that throughout northern Iraq, generation and expulsion of oil from the Sargelu began and ended in the late Miocene. At present, Jurassic source rocks might have generated and expelled between 70 % and 100 % of their total oil.     

δC of low-molecular-weight organic acids generated by the hydrous pyrolysis of oil-prone source rocks

Low-molecular-weight (LMW) aqueous organic acids were generated from six oil-prone source rocks under hydrous-pyrolysis conditions. Differences in total organic carbon-normalized acid generation are a function of the initial thermal maturity of the source rock and the oxygen content of the kerogen (OI). Carbon-isotope analyses were used to identify potential generation mechanisms and other chemical reactions that might influence the occurrence of LMW organic acids. The generated LMW acids display increasing ¹³C content as a function of decreasing molecular weight and increasing thermal maturity. The magnitudes of observed isotope fractionations are source-rock dependent. These data are consistent with δ¹³C values of organic acids presented in a field study of the San Joaquin Basin and likely reflect the contributions from alkyl-carbons and carboxyl-carbons with distinct δ¹³C values. The data do not support any particular organic acid generation mechanism. The isotopic trends observed as a function of molecular weight, thermal maturity, and rock type are not supported by either generation mechanisms or destructive decarboxylation. It is therefore proposed that organic acids experience isotopic fractionation during generation consistent with a primary kinetic isotope effect and subsequently undergo an exchange reaction between the carboxyl carbon and dissolved inorganic carbon that significantly influences the carbon isotope composition observed for the entire molecule. Although generation and decarboxylation may influence the δ¹³C values of organic acids, in the hydrous pyrolysis system described, the nondestructive, pH-dependent exchange of carboxyl carbon with inorganic carbon appears to be the most important reaction mechanism controlling the δ¹³C values of the organic acids.     

泥灰岩的生、排烃模拟实验研究

本文采用加水热模拟实验方法对东濮凹陷卫城地区下第三系低熟泥灰岩进行了生、排烃模拟实验研究，重点分析了液态产物（热解油、沥青Ａ、沥青Ｃ）的特征及演化规律。热解油中轻质烃（Ｃ₆－Ｃ₁₄）占有重要的地位，其相对含量随演化程度的增高变化特征是从大到小然后再增大，轻质烃的准确定量为评价泥灰岩的生油量提供了重要参数；热解油、沥青Ａ、沥表Ｃ三者的产率及组成变化的对比研究反映了泥灰岩（碳酸盐岩）中不同赋存状态有机质对成烃的贡献以及排烃机制。