Michael D. Lewan

Experiments on the role of water in petroleum formation

Pyrolysis experiments were conducted on immature petroleum source rocks under various conditions to evaluate the role of water in petroleum formation. At temperatures less than 330°C for 72 h, the thermal decomposition of kerogen to bitumen was not significantly affected by the presence or absence of liquid water in contact with heated gravel-sized source rock. However, at 330 and 350°C for 72 h, the thermal decomposition of generated bitumen was significantly affected by the presence or absence of liquid water. Carbon-carbon bond cross linking resulting in the formation of an insoluble bitumen (i.e., pyrobitumen) is the dominant reaction pathway in the absence of liquid water. Conversely, thermal cracking of carbon-carbon bonds resulting in the generation of saturate-enriched oil, which is similar to natural crude oils, is the dominant reaction pathway in the presence of liquid water. This difference in reaction pathways is explained by the availability of an exogenous source of hydrogen, which reduces the rate of thermal decomposition, promotes thermal cracking, and inhibits carbon-carbon bond cross linking. The distribution of generated n-alkanes is characteristic of a free radical mechanism, with a broad carbon-number distribution (i.e., C5 to C35) and only minor branched alkanes from known biological precursors (i.e., pristane and phytane). The generation of excess oxygen in the form of CO2 in hydrous experiments and the high degree of hydrocarbon deuteration in a D2O experiment indicate that water dissolved in the bitumen is an exogenous source of hydrogen. The lack of an effect on product composition and yield with an increase in H+ activity by five orders of magnitude in a hydrous experiment indicates that an ionic mechanism for water interactions with thermally decomposing bitumen is not likely. Several mechanistically simple and thermodynamically favorable reactions that are consistent with the available experimental data are envisaged for the generation of exogenous hydrogen and excess oxygen as CO2. One reaction series involves water oxidizing existing carbonyl groups to form hydrogen and car☐yl groups, with the latter forming CO2 by decar☐ylation with increasing thermal stress. Another reaction series involves either hydrogen or oxygen in dissolved water molecules directly interacting with unpaired electrons to form a hydrogen-terminated free-radical site or an oxygenated functional group, respectively. The latter is expected to be susceptible to oxidation by other dissolved water molecules to generate additional hydrogen and CO2. In addition to water acting as an exogenous source of hydrogen, it is also essential to the generation of an expelled saturate-enriched oil that is similar to natural crude oil. This role of water is demonstrated by the lack of an expelled oil in an experiment where a liquid GaIn alloy is substituted for liquid water. Experiments conducted with high salinity water and high water/rock ratios indicate that selective aqueous solubility of hydrocarbons is not responsible for the expelled oil generated in hydrous pyrolysis experiments. Similarly, a hydrous pyrolysis experiment conducted with isolated kerogen indicates that expelled oil in hydrous pyrolysis is not the result of preferential sorption of polar organic components by the mineral matrix of a source rock. It is envisaged that dissolved water in the bitumen network of a source rock causes an immiscible saturate-enriched oil to become immiscible with the thermally decomposing polar-enriched bitumen. The overall geochemical implication of these results is that it is essential to consider the role of water in experimental studies designed to understand natural rates of petroleum generation, expulsion mechanisms of primary migration, thermal stability of crude oil, reaction kinetics of biomarker transformations, and thermal maturity indicators in sedimentary basins.

D/H isotope ratios of kerogen, bitumen, oil, and water in hydrous pyrolysis of source rocks containing kerogen types I, II, IIS, and III

Abstract Immature source rock chips containing different types of kerogen (I, II, IIS, III) were artificially matured in isotopically distinct waters by hydrous pyrolysis and by pyrolysis in supercritical water. Converging isotopic trends of inorganic (water) and organic (kerogen, bitumen, oil) hydrogen with increasing time and temperature document that water-derived hydrogen is added to or exchanged with organic hydrogen, or both, during chemical reactions that take place during thermal maturation. Isotopic mass-balance calculations show that, depending on temperature (310–381°C), time (12–144 h), and source rock type, between ca. 45 and 79% of carbon-bound hydrogen in kerogen is derived from water. Estimates for bitumen and oil range slightly lower, with oil–hydrogen being least affected by water-derived hydrogen. Comparative hydrous pyrolyses of immature source rocks at 330°C for 72 h show that hydrogen in kerogen, bitumen, and expelled oil/wax ranks from most to least isotopically influenced by water-derived hydrogen in the order IIS > II ≈ III > I. Pyrolysis of source rock containing type II kerogen in supercritical water at 381°C for 12 h yields isotopic results that are similar to those from hydrous pyrolysis at 350°C for 72 h, or 330°C for 144 h. Bulk hydrogen in kerogen contains several percent of isotopically labile hydrogen that exchanges fast and reversibly with hydrogen in water vapor at 115°C. The isotopic equilibration of labile hydrogen in kerogen with isotopic standard water vapors significantly reduces the analytical uncertainty of D/H ratios when compared with simple D/H determination of bulk hydrogen in kerogen. If extrapolation of our results from hydrous pyrolysis is permitted to natural thermal maturation at lower temperatures, we suggest that organic D/H ratios of fossil fuels in contact with formation waters are typically altered during chemical reactions, but that D/H ratios of generated hydrocarbons are subsequently little or not affected by exchange with water hydrogen at typical reservoir conditions over geologic time. It will be difficult to utilize D/H ratios of thermally mature bulk or fractions of organic matter to quantitatively reconstruct isotopic aspects of paleoclimate and paleoenvironment. Hope resides in compound-specific D/H ratios of thermally stable, extractable biomarkers (“molecular fossils”) that are less susceptible to hydrogen exchange with water-derived hydrogen.

Organic acids in geological processes

1 Introduction to the Role of Organic Acids in Geological Processes.- 2 Techniques and Problems in Sampling and Analyzing Formation Waters for Carboxylic Acids and Anions.- 3 Distribution and Occurrence of Organic Acids in Subsurface Waters.- 4 Organic Acids from Petroleum Source Rocks.- 5 Material Balance Considerations for the Generation of Secondary Porosity by Organic Acids and Carbonic Acid Derived from Kerogen, Denver Basin, Colorado, USA.- 6 Role of Soil Organic Acids in Mineral Weathering Processes.- 7 Chemistry and Mechanisms of Low-Temperature Dissolution of Silicates by Organic Acids.- 8 Comparison and Evaluation of Experimental Studies on Dissolution of Minerals by Organic Acids.- 9 Experimental Studies of Organic Acid Decomposition.- 10 Application of Thermodynamic Calculations to Geochemical Processes Involving Organic Acids.- 11 Metal Transport in Ore Fluids by Organic Ligand Complexation.- 12 Geochemical Models of Rock-Water Interactions in the Presence of Organic Acids.- 13 Organic Acids and Carbonate Stability, the Key to Predicting Positive Porosity Anomalies.- 14 How Important are Organic Acids in Generating Secondary Porosity in the Subsurface?.

Comparison of petroleum generation kinetics by isothermal hydrous and nonisothermal open-system pyrolysis

This study compares kinetic parameters determined by open-system pyrolysis and hydrous pyrolysis using aliquots of source rocks containing different kerogen types. Kinetic parameters derived from these two pyrolysis methods not only differ in the conditions employed and products generated, but also in the derivation of the kinetic parameters (i.e., isothermal linear regression and non-isothermal nonlinear regression). Results of this comparative study show that there is no correlation between kinetic parameters derived from hydrous pyrolysis and open-system pyrolysis. Hydrous-pyrolysis kinetic parameters determine narrow oil windows that occur over a wide range of temperatures and depths depending in part on the organic-sulfur content of the original kerogen. Conversely, open-system kinetic parameters determine broad oil windows that show no significant differences with kerogen types or their organic-sulfur contents. Comparisons of the kinetic parameters in a hypothetical thermal-burial history (2.5 °C/my) show open-system kinetic parameters significantly underestimate the extent and timing of oil generation for Type-IIS kerogen and significantly overestimate the extent and timing of petroleum formation for Type-I kerogen compared to hydrous pyrolysis kinetic parameters. These hypothetical differences determined by the kinetic parameters are supported by natural thermal-burial histories for the Naokelekan source rock (Type-IIS kerogen) in the Zagros basin of Iraq and for the Green River Formation (Type-I kerogen) in the Uinta basin of Utah. Differences in extent and timing of oil generation determined by open-system pyrolysis and hydrous pyrolysis can be attributed to the former not adequately simulating natural oil generation conditions, products, and mechanisms.

Sulphur-radical control on petroleum formation rates

Most petroleum is formed through the partial decomposition of kerogen (an insoluble sedimentary organic material) in response to thermal stress during subsurface burial in a sedimentary basin,. Knowing the mechanisms and kinetics of this process allows the determination of the extent and timing of petroleum formation, which, in turn, are critical for evaluating the potential for petroleum occurrences within a sedimentary basin. Kinetic models of petroleum generation are derived mainly from pyrolysis experiments,, in which it is usually assumed that formation rates are controlled by the strength of the bonds within the precursor compounds: this agrees with the observation that petroleum formation rates increase with increasing sulphur content of thermally immature kerogen, C–S bonds being weaker than C–C bonds. However, this explanation fails to account for the overall composition of petroleum. Here I argue, on the basis of pyrolysis experiments, that it is the presence of sulphur radicals, rather than the relative weakness of C–S bonds, that controls petroleum formation rates. My findings suggest that the rate of petroleum formation depends critically on the concentration of sulphur radicals generated during the initial stages of thermal maturation. The proposed mechanism appears to provide a realistic explanation for both the overall composition of petroleum and the observed variation in formation rates.

A thermal and chemical degradation approach to decipher pristane and phytane precursors in sedimentary organic matter

A thermal and chemical degradation approach was followed to determine the precursors of pristane (Pr) and phytane (Ph) in samples from the Gessoso-solfifera, Ghareb and Green River Formations. Hydrous pyrolysis of these samples yields large amounts of Pr and Ph carbon skeletons, indicating that their precursors are predominantly sequestered in high-molecular-weight fractions. However, chemical degradation of the polar fraction and the kerogen of the unheated samples generally does not release large amounts of Pr and Ph. Additional information on the precursors of Pr and Ph is obtained from flash pyrolysis analyses of kerogens and residues after hydrous pyrolysis and after chemical degradation. Multiple precursors for Pr and Ph are recognised in these three samples. The main increase of the Pr/Ph ratio with increasing maturation temperature, which is associated with strongly increasing amounts of Pr and Ph, is probably due to the higher amount of precursors of Pr compared to Ph, and not to the different timing of generation of Pr and Ph.

New insights on the Green River petroleum system in the Uinta basin from hydrous pyrolysis experiments

The Tertiary Green River petroleum system in the Uinta basin generated about 500 million bbl of recoverable, high pour-point, paraffinic crude oil from lacustrine source rocks. A prolific complex of marginal and open-lacustrine source rocks, dominated by carbonate oil shales containing up to 60 wt. % type I kerogen, occur within distinct stratigraphic units in the basin. Petroleum generation is interpreted to originate from source pods in the basal Green River Formation buried to depths greater than 3000 m along the steeply dipping northern margin of the basin. Producing fields in the Altamont-Bluebell trend have elevated pore-fluid pressures approaching 80% of lithostatic pressure and are completed in strata where open fractures provide permeability. Active hydrocarbon generation is one explanation for the origin of the overpressured reservoirs. In this study, experiments were undertaken to examine the mechanisms of hydrocarbon generation and accumulation in the Uinta basin. We combined analyses of representative source rocks from the entire Green River stratigraphic section with detailed laboratory simulation experiments using both open- and closed-system pyrolysis. This information provides new insights on lacustrine source rock lithofacies, gas-oil-source rock correlations, hydrocarbon generation kinetics, and basin modeling. The results show that the basal Green River Formation contains a unique type I source facies responsible for generation of paraffinic crude oils. The classic type I oil shales in the upper Green River Formation correlate well with low-maturity aromatic-asphaltic samples. We determined kinetic parameters for the source rocks and used them to develop basin models for hydrocarbon generation. The models show that hydrous pyrolysis kinetic parameters are more consistent with the natural data in terms of predicted timing and extent of oil generation as compared to models using Rock-Eval kinetics. (Begin page 1334)

Impact of dia- and catagenesis on sulphur and oxygen sequestration of biomarkers as revealed by artificial maturation of an immature sedimentary rock

Hydrous pyrolysis of an immature (Ro ≈ 0.25%) sulphur-rich marl from the Gessoso-solfifera Formation (Messinian) in the Vena del Gesso Basin was carried out at 160°C ≤ T ≤330°C for 72 h, to study the effect of progressive diagenesis and early catagenesis on the abundance and distribution of sulphur-containing and sulphur- and oxygen-linked carbon skeletons in low-molecular-weight and high-molecular-weight fractions (e.g. kerogen). To this end, compounds in the saturated hydrocarbon fraction, monoaromatic hydrocarbon fraction, polyaromatic hydrocarbon fraction, alkylsulphide fraction and ketone fraction were quantified, as well as compounds released after desulphurisation of the polar fraction and HILiAlH4 treatment of the desulphurised polar fraction. Sulphur-bound phytane and (20R)-5α,14α,17α(H) and (20R)-5β,14α,17α(H) C27–C29 steranes in the polar fraction become less abundant with increasing maturation temperature, whereas the amount of their corresponding hydrocarbons increases in the saturated hydrocarbon fraction. Carbon skeletons that are bound in the kerogen by multiple bonds (e.g. C38n-alkane and isorenieratane) are first released into the polar fraction, and then as free hydrocarbons. These changes occur at relatively low levels of thermal maturity (Ro <0.6%), as evidenced by the “immature” values of biomarker maturity parameters such as the ββ/(ββ + αβ + βα) C35 hopane ratio and the 22S/(22S + 22R)−17α,21β(H) C35 hopane ratio. Sulphur- and oxygen-bound moieties, present in the polar fraction, are not stable with increasing thermal maturation. However, alkylthiophenes, ketones, 1,2-di-n-alkylbenzenes and free n-alkanes seem to be stable thermal degradation products of these sulphur- and oxygen-bound moieties. Thus, apart from free n-alkanes, which are abundantly present in more mature sedimentary rocks and crude oils, alkylthiophenes, 1,2-di-n-alkylbenzenes and ketones can also be expected to occur. The positions of the thiophene moiety and the carbonyl group coincide with the original positions of the functional groups of their precursors. Thus, important information about palaeobiochemicals is retained throughout the sequestration/degradation process.

Formation temperatures of thermogenic and biogenic methane

Making of methane deep underground Technologies such as hydraulic fracturing, or “fracking,” can now extract natural gas from underground reservoirs. Within the gas, the ratio of certain isotopes holds clues to its origins. Stolper et al. analyzed a wide range of natural gas, including samples from some of the most active fracking sites in the United States. Using a “clumped isotope” technique, the authors could estimate the high temperatures at which methane formed deep underground, as well as the lower temperatures at which ancient microbes produced methane. The approach can help to distinguish the degree of mixing of gas from both sources. Science, this issue p. 1500 Isotopic analysis of methane indicates the timing and location of hydrocarbon gas formation in natural settings. Methane is an important greenhouse gas and energy resource generated dominantly by methanogens at low temperatures and through the breakdown of organic molecules at high temperatures. However, methane-formation temperatures in nature are often poorly constrained. We measured formation temperatures of thermogenic and biogenic methane using a “clumped isotope” technique. Thermogenic gases yield formation temperatures between 157° and 221°C, within the nominal gas window, and biogenic gases yield formation temperatures consistent with their comparatively lower-temperature formational environments (<50°C). In systems where gases have migrated and other proxies for gas-generation temperature yield ambiguous results, methane clumped-isotope temperatures distinguish among and allow for independent tests of possible gas-formation models.

Fluid inclusion and vitrinite-reflectance geothermometry compared to heat-flow models of maximum paleotemperature next to dikes, western onshore Gippsland Basin, Australia

Abstract Nine basalt dikes, ranging from 6 cm to 40 m thick, intruding the Upper Jurassic–Lower Cretaceous Strzelecki Group, western onshore Gippsland Basin, were used to study maximum temperatures ( T max ) reached next to dikes. T max was estimated from fluid inclusion and vitrinite-reflectance geothermometry and compared to temperatures calculated using heat-flow models of contact metamorphism. Thermal history reconstruction suggests that at the time of dike intrusion the host rock was at a temperature of 100–135°C. Fracture-bound fluid inclusions in the host rocks next to thin dikes ( T max systematically increases towards the dike margin to at least 500°C. The estimated T max next to the thickest dike (thickness ( D )=40 m) suggests an extended zone of elevated R v-r to at least a distance from the dike contact ( X ) of 60 m or at X / D >1.5, using a normalized distance ratio used for comparing measurements between dikes regardless of their thickness. In contrast, the pattern seen next to the thin dikes is a relatively narrow zone of elevated R v-r . Heat-flow modeling, along with whole rock elemental and isotopic data, suggests that the extended zone of elevated R v-r is caused by a convection cell with local recharge of the hydrothermal fluids. The narrow zone of elevated R v-r found next to thin dikes is attributed to the rise of the less dense, heated fluids at the dike contact causing a flow of cooler groundwater towards the dike and thereby limiting its heating effects. The lack of extended heating effects suggests that next to thin dikes an incipient convection system may form in which the heated fluid starts to travel upward along the dike but cooling occurs before a complete convection cell can form. Close to the dike contact at X / D R v-r often decreases even though fluid inclusion evidence indicates that T max is still increasing. Further, fluid inclusion evidence indicates that the evolution of water vapor or supercritical fluids in the rock pores corresponds to the zone where R v-r begins to decrease. The generation of the water vapor or supercritical fluids near the dike contact seems to change vitrinite evolution reactions. These metamorphic conditions, closer to the dike than X / D =0.3 make vitrinite-reflectance unreliable as a geothermometer. The form of the R v-r profile, as it indicates T max , can be interpreted using temperature profiles estimated from various heat-flow models to infer whether the dike cooled by conduction, incipient convection, or a convection cell. A contact aureole that consists of decreasing R v-r or T max extending out to X / D ≥2 and that has a T contact ≫( T magma + T host )/2 appears to be a signature of simple conductive cooling. Incipient convection is indicated by a R v-r profile that decreases to background levels at X / D R v-r profile and consistently high R v-r that may not decrease to background levels until beyond distances of X / D >1.5.