Organic geochemistry of the 9.6 km Bertha Rogers No. 1. well,Oklahoma

Organic geochemical analyses of fine-grained rocks from the 9.590 km Bertha Rogers No. 1 well have been carried out: total organic carbon, Soxhlet extraction and silica gel chromatography, C₁₅₊ saturated and aromatic hydrocarbon gas chromatography and mass spectrometry, pyrolysis, kerogen analysis, X-ray diffraction and visual kerogen analysis.Rocks ranged in age from Permian to Ordovician; the well has an estimated bottom hole temperature of 225°C. Some data from this study are inconsistent with conventional theories concerning the generation and thermal destruction of hydrocarbons. For example, appreciable amounts of C₁₅₊ gas-condensate-like hydrocarbons are present in very old rocks currently at temperatures where current theory predicts that only methane and graphite should remain. Also, substantial amounts of pyrolyzable C₁₅₊ hydrocarbons remain on the kerogen in these deeply buried Paleozoic rocks. This suggests, at least in somes cases, that temperatures much higher than those predicted by current theory are required for generation and thermal destruction of hydrocarbons. The data from this well also suggest that original composition of organic matter and environment of deposition may have a much stronger influence on the organic geochemical characteristics of fine-grained sediments than has previously been ascribed to them. The results from this well, from other deep hot wells in which temperatures exceed 200°C, and from laboratory experiments, suggest that some of the basic concepts of the generation and maturation of petroleum hydrocarbons may be in error and perhaps should be reexamined.     

Characterization of Precambrian kerogens by analytical pyrolysis

A selection of Precambrian kerogens has been characterized by Curie-point pyrolysis combined with gas chromatography and gas chromatography-mass spectrometry. The resulting pyrograms can be classified into two groups. The first group of pyrograms is derived from kerogens whose pyrolysis products are dominated by alkanes, alkenes and alkadienes, whereas the second group contains pyrograms from kerogens that produce complex mixtures of branched hydrocarbons dominated by components at every third carbon number (C₉, C₁₂, C₁₅, C₁₈, C₂₁, and up to C₃₃). It is suggested that these branched hydrocarbons may remotely represent remains of isoprenoid hydrocarbons, or other branched hydrocarbons, of the original organisms.     

Low-temperature gas from marine shales: wet gas to dry gas over experimental time

Marine shales exhibit unusual behavior at low temperatures under anoxic gas flow. They generate catalytic gas 300° below thermal cracking temperatures, discontinuously in aperiodic episodes, and lose these properties on exposure to trace amounts of oxygen. Here we report a surprising reversal in hydrocarbon generation. Heavy hydrocarbons are formed before light hydrocarbons resulting in wet gas at the onset of generation grading to dryer gas over time. The effect is moderate under gas flow and substantial in closed reactions. In sequential closed reactions at 100°C, gas from a Cretaceous Mowry shale progresses from predominately heavy hydrocarbons (66% C₅, 2% C₁) to predominantly light hydrocarbons (56% C₁, 8% C₅), the opposite of that expected from desorption of preexisting hydrocarbons. Differences in catalyst substrate composition explain these dynamics. Gas flow should carry heavier hydrocarbons to catalytic sites, in contrast to static conditions where catalytic sites are limited to in-place hydrocarbons. In-place hydrocarbons and their products should become lighter with conversion thus generating lighter hydrocarbon over time, consistent with our experimental results.     

Characterization of high molecular weight biomarkers in crude oils

High-temperature gas chromatography (HTGC) has enhanced our ability to characterize hydrocarbons extending to C₁₂₀ in crude oils. As a result, hydrocarbons in waxes (> C₂₀) have been observed to vary significantly between crude oils, even those presumed to originate from the same source. Prior to this development, microcrystalline waxes containing hydrocarbons above C₄₀ were not characterized on a molecular level due to the analytical limitations of conventional gas chromatography. Routine screenings of high pour-point crude oils by high-temperature gas chromatography has revealed that high molecular weight hydrocarbons (> C₄₀) are very common in most oils and may represent 2% of the crude oil. Precise structures, origins, and significance of these high molecular weight compounds remain elusive. As a preliminary step to expand our knowledge of these compounds their general molecular structures and formulas have been investigated in this study. Initial results suggest that the major high molecular weight compounds include a homologous series of n-alkanes, methylbranched alkanes, alkylcyclopentanes, alkylcyclohexanes, alkylbenzenes and alkylcycloalkanes.     

Metathesis in the generation of low-temperature gas in marine shales

The recent report of low-temperature catalytic gas from marine shales took on additional significance with the subsequent disclosure of natural gas and low-temperature gas at or near thermodynamic equilibrium in methane, ethane, and propane. It is important because thermal cracking, the presumed source of natural gas, cannot generate these hydrocarbons at equilibrium nor can it bring them to equilibrium over geologic time. The source of equilibrium and the source of natural gas are either the same (generation under equilibrium control) or closely associated. Here we report the catalytic interconversion of hydrocarbons (metathesis) as the source of equilibrium in experiments with Cretaceous Mowry shale at 100°C. Focus was on two metathetic equilibria: methane, ethane, and propane, reported earlier, Q (K = [(C₁)*(C₃)]/[(C₂)²]), and between these hydrocarbons and n-butane, Q* (K = [(C₁)*(n-C₄)]/[(C₂)*(C₃)]), reported here for the first time. Two observations stand out. Initial hydrocarbon products are near equilibrium and have maximum average molecular weights (AMW). Over time, products fall from equilibrium and AMW in concert. It is consistent with metathesis splitting olefin intermediates [C_n] to smaller intermediates (fission) as gas generation creates open catalytic sites ([ ]): [C_n] + [ ] → [C_n-m] + [C_m]. Fission rates increasing exponentially with olefin molecular weight could contribute to these effects. AMW would fall over time, and selective fission of [C₃] and [n-C₄] would draw Q and Q* from equilibrium. The results support metathesis as the source of thermodynamic equilibrium in natural gas.     

Laboratory methods for evaluating migrated high molecular weight hydrocarbons in marine sediments at naturally occurring oil seeps

A laboratory study has been conducted to determine the best methods for the detection of C₁₀–C₄₀ hydrocarbons at naturally occurring oil seeps in marine sediments. The results indicate that a commercially available method using n-C₆ to extract sediments and gas chromatography–flame ionization detection (GC–FID) to screen the resulting extract is effective at recognizing the presence of migrated hydrocarbons at concentrations from 50 to 5000 ppm. When non-biodegraded, the amount of oil charge is effectively tracked by the sum of n-alkanes in the gas chromatogram. However, once the charge oil becomes biodegraded, with the loss of n-alkanes and isoprenoids, the amount of oil is tracked by the quantification of the unresolved complex mixture (UCM). Gas chromatography–mass spectrometry (GC–MS) was also found to be very effective for the recognition of petroleum related hydrocarbons and results indicate that GC–MS would be a very effective tool for screening samples at concentrations below 50 ppm oil charge.     

Oil geochemistry derived from the Qinjiatun–Qikeshu oilfields: insight from light hydrocarbons

A suite of 27 oils from the Qinjiatun–Qikeshu oilfields in the Lishu Fault Depression of the Songliao Basin was analyzed using whole oil gas chromatography. In combination with the relative distribution of C₂₇, C₂₈, and C₂₉ regular steranes, detailed geochemical analyses of light hydrocarbons in oil samples revealed crude oils characterized by the dual input of lower aquatic organisms and higher terrestrial plants. Several light hydrocarbon indicators suggest that the liquid hydrocarbons have maturities equivalent to vitrinite reflectances of around 0.78%–0.93%. This is consistent with the maturity determination of steranes C₂₉ 20S/(20S + 20R) and C₂₉ ααβ/(ααα + αββ). Crude oils derived from the two distinct oilfields likely both have source rocks deposited in a lacustrine environment based on light hydrocarbon parameters and on higher molecular weight hydrocarbon parameters. The results show that light hydrocarbon data in crude oils can provide important information for understanding the geochemical characteristics of the Qinjiatun–Qikeshu oils during geologic evolution.     

Identification and implications of fight hydrocarbon fluid inclusions from the Proterozoic Bidjovagge gold-copper deposit, Finnmark, Norway

Carbonic fluid inclusions were observed in quartz-bearing veins at the Proterozoic Bidjovagge AuCu deposit within the Kautokeino greenstone belt in Norway, where mineralization occurred in oxidation zones of graphitic schists. A primary fluid inclusion zonation was observed with C0₂-rich fluid inclusions in the structural footwall of the deposit, and CH₄-rich inclusions within the ore zone in the oxidation zone. Microthermometry of the primary hydrocarbon inclusions revealed 2 groups; (1) a group which homogenized between −125°C and the critical temperature of CH₄ (−82.1°C), which indicated the presence of pure CH₄, and (2) a group which homogenized between the critical temperature of CH₄ and −42°C, which indicated the presence CH₄ and higher hydrocarbons (HHC). Raman microprobe analyses of the first group confirmed the presence of CH₄. The second inclusion group were fluorescent, and Raman spectra clearly displayed CH₄,C₂H₆, and rarer C₃H₈ peaks. A typical feature of the Raman spectra were elevated baselines at the hydrocarbon peaks. Carbon peaks were also usually detected in each inclusion by Raman analysis. Bulk gas chromatography analyses of samples containing the first group (CH₄) indicated the presence of CH₄ and low concentrations of C₂H₆ and C₃H₈. Gas chromatography analyses of samples containing the second group (CH₄ and higher hydrocarbons) confirmed the presence of CH₄, and higher hydrocarbons such as C₂H₆ and C₃H₈ and also butanes. Based on the spacial zonation of hydrocarbons and the estimated PT conditions of 300 to 375°C and 2 to 4 kbars, the authors suggest an abiotic origin for the hydrocarbons. It is suggested that the hydrothermal fluids oxidized the graphitic schist, precipitated Cu and Au and formed light gas hydrocarbons.     

Role of minerals in the thermal alteration of organic matter—I: Generation of gases and condensates under dry condition

Pyrolysis experiments were carried out on Monterey formation kerogen and bitumen and Green River formation kerogen (Type II and I, respectively), in the presence and absence of montmorillonite, illite and calcite at 200 and 300°C for 2–2000 hours. The pyrolysis products were identified and quantified and the results of the measurements on the gas and condensate range are reported here.A significant catalytic effect was observed for the pyrolysis of kerogen with montmorillonite, whereas small or no effects were observed with illite and calcite, respectively. Catalytic activity was evident by the production of up to five times higher C₁–C₆ hydrocarbons for kerogen with montmorillonite than for kerogen alone, and by the dominance of branched hydrocarbons in the C₄–C₆ range (up to 90% of the total amount at any single carbon number). This latter effect in the presence of montmorillonite is attributed to cracking via a carbonium-ion [carbocation] intermediate which forms on the acidic sites of the clay. No catalytic effect, however, was observed for generation of methane and C₂ hydrocarbons which form by thermal cracking. The catalysis of montmorillonite was significantly greater during pyrolysis of bitumen than for kerogen, which may point to the importance of the early formed bitumen as an intermediate in the production of low molecular weight hydrocarbons. Catalysis by minerals was also observed for the production of carbon dioxide.These results stress the importance of the mineral matrix in determining the type and amount of gases and condensates forming from the associated organic matter under thermal stress. The literature contains examples of gas distributions in the geologic column which can be accounted for by selective mineral catalysis, mainly during early stages of organic matter maturation.     

Selective enrichment of steroid and triterpenoid hydrocarbons from crude oil using gel permeation chromatography for stable carbon isotope analysis

Gel permeation chromatography (GPC) using a high performance liquid chromatography (HPLC) system was studied for the separation and enrichment of steroid and hopanoid hydrocarbons from crude oil for stable carbon isotope analysis. A crude oil sample was pretreated using silica gel chromatography and 5A molecular sieve to remove polycyclic aromatic hydrocarbons and n-alkanes. The GPC behavior of both the pretreated saturated hydrocarbon fraction of the oil and standard steroid [5α(H), 14α(H), 17α(H) C₂₇–C₂₉ steranes], hopanoid [17α(H) C₂₇ trisnorhopane, 17α(H), 21β(H) C₂₉–C₃₂ hopanes] and triterpenoid [18α(H)-oleanane, gammacerane] mixtures were examined. The results indicate that 17α(H), 21β(H) hopanes as well as steranes could be enriched efficiently using GPC and that they could be obtained without removing n-alkanes from the oil saturated hydrocarbon fraction. The GPC behavior of steroid and triterpenoid hydrocarbons was controlled by molecular size and shape.     

Generation and migration of light hydrocarbons (C2C7) in sedimentary basins

Sixty-five samples from selected source bed-type shale sequences from three exploration wells were analysed for yield and detailed composition of light hydrocarbons(C₂C₇) by a new hydrogen stripping/capillary gas chromatographic technique. In spite of low maturation levels (0.35–0.55% vitrinite reflectance), significant generation of ethane and propane was recognized in a Jurassic source bed sequence bearing hydrogen-poor kerogens. Light hydrocarbon generation in another and mature Jurassic source rock sequence is controlled by kerogen quality. Associated with a change from hydrogen-poor to hydrogen-rich kerogens, yields of total and most individual hydrocarbons exhibit orders-of-magnitude increases. At the same time, iso/n-alkane ratios for butanes, pentanes and heptanes decrease significantly. A study of an interbedded marine/nonmarine coal-bearing sequence of Upper Carboniferous age from the Ruhr area, West Germany, revealed that a marine shale unit in comparison to the adjacent coal seam is more prolific in generating n-alkanes of increasing molecular size.A case history for migration of light hydrocarbons by means of diffusion through shales is presented. In two shallow core holes in Campanian/Maastrichtian shales in West Greenland, upward diffusion of ethane to pentane range hydrocarbons is an active process within the near-surface 3 m interval. Diffusive losses within this interval amount to 99.8% for propane, 85.6% for n-butane and 38.9% for n-pentane.     

Thermal simulation of basic volcanic fluid influence on different source rocks

Based on thermal simulation experiment, interactions between volcanic fluids and source rocks were studied. Gas generations in the dry system and fluid system under different temperatures were analyzed. The results showed that the various types of source rocks are similar in composition, containing gaseous C1-C5 hydrocarbons, H2 and CO2 whose gas yields increase with increasing temperature. The gas yield of source rocks of type I is the high- est, followed by type II, and that of source rocks of type III is the lowest, indicating that the yield of hydrocarbon gases is related to their hydrocarbon generating potential. Although the generating potential of type III is the lowest, it can still be regarded as a useful gas source when it is buried deeply enough. The basic volcanic fluid restrains the generation of gaseous hydrocarbons in different types of source rocks, but promotes the generation of inorganic gases.     

Influences of the basin brines on extractable bitumen of Kupferschiefer from southwestern Poland

A study of the influences of the basin brines on hydrocarbon generation of the Kupferschiefer in southwestern Poland has been carried out.The samples from the Konrad and Polkowics mines were analyzed by orgainc geochemical,microscopic and FTIR methods.The results indicate that organic matter of Kupferschiefer tends to decrease with the ascending,oxidizing brines,In the Konrad profile,the Kupferschiefer was strongly oxidized.The extract yields were depleted up to 50mg Ext/g Corg.Gas chromatography(GC) and gas chromatography-mass spctrometry(GC/MS) data indicate that the depletion occureed predominantly in saturated hydrocarbon compounds.The identified n-alkanes in smpale KD1 were depleted at least to 5000μg/g Corg.The aromatic compounds show a fidderent trend of variation.The concentrations of phenanthrene alkylphenanthrenes(Ph-PAH) and naphthalene alkylnaphthalenes(Na-PAH) show a decrease,whereas sulfur polyaromatic hydrocarbons(S-PAH)and oxygen polyaromatic hydrocarbons(O-PAH) show an incrase under the influences of oxidizing brines,In the Polkowice profile,organic matter under the influences of oxidizing fluids shows a simlar trend of varation as in the Konrad mine.Analyses of polar compounds shed light on the oxidation processes at the molecule level.The dominant products of oxidation are aliphatic acid.alcohol and ester.FTIR results indicate that the oxidation of organic matter led to a decrease in aliphatic CH3 and an increase in C-O,C=O bands.     

Hydrocarbons in 60 northeast Gulf of Mexico shelf sediments: a preliminary survey

Hydrocarbon results from gas chromatography of 60 recent sediment and 10 benthic algae samples delineate two distinct shelf environments in the northeastern Gulf of Mexico.Sediments off Florida (shell hashes and sands) have moderate amounts of lipids/total sediment (average 113ppm ± 80%) but low hydrocarbon levels (average 3.06 ppm ± 41%). Aliphatic hydrocarbons are dominated by a series of branched or cyclic, unsaturated C₂₅ isomers. The major n-alkane is n-C₁₇. The n-alkane and isoprenoid patterns are consistent with a marine hydrocarbon source.Sediments closer to the Mississippi River (silts and clays) contain large amounts of lipids (average 232 ppm ± 53%) and hydrocarbons (average 11.7 ppm ± 55%) to total sediment. Aliphatic hydrocarbons are mainly odd carbon number high molecular weight n-alkanes, indicating a terrigenous hydrocarbon source. Isoprenoids are present in greater abundance than in sediments off Florida (n-C₁₇/ pristane and n-C₁₈/phytane ratios ~2to 3). Relatively large amounts of n-C₁₆, together with an even distribution of n-alkanes in the range C₁₄–C₂₀ and a substantial unresolved envelope all point to a fossil fuel input to the Mississippi samples.Samples off the Alabama coast show intermediate characteristics.     

Low-temperature gas from marine shales

Thermal cracking of kerogens and bitumens is widely accepted as the major source of natural gas (thermal gas). Decomposition is believed to occur at high temperatures, between 100 and 200°C in the subsurface and generally above 300°C in the laboratory. Although there are examples of gas deposits possibly generated at lower temperatures, and reports of gas generation over long periods of time at 100°C, robust gas generation below 100°C under ordinary laboratory conditions is unprecedented. Here we report gas generation under anoxic helium flow at temperatures 300° below thermal cracking temperatures. Gas is generated discontinuously, in distinct aperiodic episodes of near equal intensity. In one three-hour episode at 50°C, six percent of the hydrocarbons (kerogen & bitumen) in a Mississippian marine shale decomposed to gas (C₁–C₅). The same shale generated 72% less gas with helium flow containing 10 ppm O₂ and the two gases were compositionally distinct. In sequential isothermal heating cycles (~1 hour), nearly five times more gas was generated at 50°C (57.4 μg C₁–C₅/g rock) than at 350°C by thermal cracking (12 μg C₁–C₅/g rock). The position that natural gas forms only at high temperatures over geologic time is based largely on pyrolysis experiments under oxic conditions and temperatures where low-temperature gas generation could be suppressed. Our results indicate two paths to gas, a high-temperature thermal path, and a low-temperature catalytic path proceeding 300° below the thermal path. It redefines the time-temperature dimensions of gas habitats and opens the possibility of gas generation at subsurface temperatures previously thought impossible.     

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.     

The deep subsurface temperature controlled origin of the gaseous and gasoline-range hydrocarbons of petroleum

In recent surface sediments there is no indication of any of the saturated C₃–C₇ gasolinerange hydrocarbons which are so common in petroleum. Appreciable gasoline-range hydrocarbon generation (85–180°C) of 80 ppm by weight of dry rock, or more, occurs only with increased temperature due to deeper burial, below about 8000 ft in the Los Angeles basin and below 12,500 ft in the Ventura basin. Because of the lower temperature gradient in the Ventura basin, the zone of substantial gasoline generation is considerably deeper there than in the Los Angeles basin. However, the subsurface temperature range over which substantial gasoline generation occurs is practically the same in the two basins. This demonstrates that the subsurface temperature, not depth, is the controlling factor in gasoline generation in source rocks. For appreciable gasoline generation somewhat higher subsurface temperatures are required than for equivalent generation of heavy hydrocarbons boiling above 325°C. Appreciable generation of the C₁–C₄ wet gas components of 75 ppm by weight of dry rock, or more, takes place quite deep also; in the Los Angeles basin it occurs below 10,000 ft.The composition of the gasoline-range hydrocarbons generated changes gradually with increasing depth, temperature and age of the shales. In deep strata the gasolines from shale cannot be distinguished from the gasolines of waxy crude oils in the same basin. The gasoline-range hydrocarbons mature with depth, temperature and age of the sediments, very much like the heavy hydrocarbons investigated earlier.Based on the similarity of analyses of heavy as well as of gasoline-range hydrocarbons from crude oils and from certain deep shales, a secure identification has been made of mature oil source beds in the Los Angeles and San Joaquin Valley oil basins of California. The combined results of these studies provide strong evidence for the origin of petroleum from the organic matter of sediments.     

Organic inclusions as an indicator of oil/gas potential assessment of carbonate reservoir beds

Organic inclusions could be formed at the stages of either primary or secondary migration of hydrocarbons so long as mineral crystallization or recrystallization takes place in the sediments, presenting a direct indicator of oil/gas evolution, migration and abundance. Based on the study of organic inclusions in carbonate-type reservoir beds of commercial importance from North China, Xingjing, North Jiangsu, Jianghan, Sichuan and Guizhou in China, many inclusion parameters for oil/gas potential assessment of carbonate reservoir beds are summarized in this paper, including: 1) Types of organic inclusion: Commercially important oil beds are characterized by inclusions consisting of either pure liquid hydrocarbons or liquid plus minor gaseous hydrocarbons, while commercially important gas reservoirs are characterized by inclusions consisting of either pure gaseous hydrocarbons or gas plus minor liquid hydrocarbons. 2) Quantity of organic inclusions: The number of organic inclusions in commercially important oil/gas reservoirs is over 60% of the total inclusion percentage. 3) Temperature of saline inclusions: The homogenization temperatures of contemporaneous saline inclusions in oil reservoirs range from 91–161 °C, while in gas reservoirs from 150–250 °C). 4) Inclusion composition: In commercially important oil reservoirs, C₁/C₂=2−10, C₁/C₃=2−4, C₁/C₄=2−21, (C₂−C₄)/(C₁−C₄)(%)>20, (CH₄+CO+H₂)/CO₂ (molecules/g)=0.5−1.0, and in C₂−C₃−nC₄ triangle diagram there should be an upside-down triangle with the apex within the ellipse, while in commercial gas reservoirs, C₁/C₂=10−35, C₁/C₃=14−82, C₁/C₄=21−200, (C₂−C₄)/(C₁−C₄)(%)<20, (CH₄+CO+H₂)/CO₂>1, and there would be an upright triangle with the apex within the ellipse. The above-mentioned parameters have been used to evaluate a number of other unknown wells or regions and the results are very satisfactory. It is valid to use organic inclusions as an indicator to assess the oil/gas potential during oil/gas exploration and prospecting. This approach is effective, economic, rapid, and easy to popularize.     

Insights into oil cracking based on laboratory experiments

The objectives of this pyrolysis investigation were to determine changes in (1) oil composition, (2) gas composition and (3) gas carbon isotope ratios and to compare these results with hydrocarbons in reservoirs. Laboratory cracking of a saturate-rich Devonian oil by confined, dry pyrolysis was performed at T=350–450 °C, P=650 bars and times ranging from 24 h to 33 days. Increasing thermal stress results in the C₁₅₊ hydrocarbon fraction cracking to form C_6–14 and C_1–5 hydrocarbons and pyrobitumen. The C_6–14 fraction continues to crack to C_1–5 gases plus pyrobitumen at higher temperatures and prolonged heating time and the δ ¹³C_ethane–δ¹³C_propane difference becomes greater as oil cracking progresses. There is considerable overlap in product generation and product cracking. Oil cracking products accumulate either because the rate of generation of any product is greater than the rate of removal by cracking of that product or because the product is a stable end member under the experimental conditions. Oil cracking products decrease when the amount of product generated from a reactant is less than the amount of product cracked. If pyrolysis gas compositions are representative of gases generated from oil cracking in nature, then understanding the processes that alter natural gas composition is critical.     

Occurrence of a regular C25 isoprenoid hydrocarbon in tertiary sediments representing a lagoonal-type,saline environment

A regular C₂₅ isoprenoid alkane (2,6,10,14,18-pentamethyleicosane) has been isolated from highly saline Tertiary sediments. The isolation utilized elution chromatography, urea adduction and gas chromatography; identification was based on the mass spectrum. This C₂₅ isoprenoid may represent a biological marker, possibly typical for a lagoonal-type, saline environment.