Development of methods to collect and analyze gasoline range (C5–C12) hydrocarbons from seabed sediments as indicators of subsurface hydrocarbon generation and entrapment

Gasoline range hydrocarbons (C₅–C₁₂) are usually associated with petroleum generation, yet few surface geochemical surveys have attempted to evaluate the gasoline range hydrocarbons in near-surface marine sediments. This is due to the difficulty in capturing and analyzing this volatile range of hydrocarbons with minimum loss and evaporative fractionation. In this study, a Headspace Solid Phase Microextraction (HSPME) method was developed and evaluated for the purpose of capturing the gasoline range of hydrocarbons within unconsolidated sediment using a solventless protocol.     

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.     

Geochemical characterization of adsorbed light gaseous alkanes in near surface soils of the eastern Ganga basin for hydrocarbon prospecting

This study aims to assess the hydrocarbon potential of Ganga basin utilizing the near surface geochemical prospecting techniques. It is based on the concept that the light gaseous hydrocarbons from the oil and gas reservoirs reach the surface through micro seepage, gets adsorbed to soil matrix and leave their signatures in soils and sediments, which can be quantified. The study showed an increased occurrence of methane (C₁), ethane (C₂) and propane (C₃) in the soil samples. The concentrations of light gaseous hydrocarbons determined by Gas Chromatograph ranged (in ppb) as follows, C₁: 0–519, C₂: 0–7 and C₃: 0–2. The carbon isotopic (VPDB) values of methane varied between ?52.2 to ?27.1‰, indicating thermogenic origin of the desorbed hydrocarbons. High concentrations of hydrocarbon were found to be characteristic of the Muzaffarpur region and the Gandak depression in the basin, signifying the migration of light hydrocarbon gases from subsurface to the surface and the area’s potential for hydrocarbon resources.     

On the depth,time and mechanism of origin of the heavy to medium-gravity naphthenic crude oils

Paraffinic crude oils are designated ‘primary’ because their composition is very close or identical to that of the hydrocarbons extracted from the corresponding oil source rocks. Heavy and medium-gravity naphthenic crude oils, on the other hand, typically are quite different compositionally from hydrocarbon mixtures in either mature or immature shales.The normal paraffin carbon number odd/even ratio 2C₂₉/(C₂₈ + C₃₀) of all the heavy to medium-gravity crude oils which could be analysed are in exactly the same range as is observed for the primary paraffinic crude oils, namely 0.95–1.42. The naphthene indices of the medium to heavy gravity naphthenic crude oils and of the primary paraffinic crude oils from the same area are identical or close. These facts are significant because both the n-paraffin carbon number odd/even ratio and the naphthene index of shale hydrocarbons are strongly depth and subsurface temperature dependent. The facts observed demonstrate beyond question that, in the same area, the paraffinic precursors of the heavy to medium-gravity naphthenic crude oils are generated and expelled in the identical depth range, and from the same mature relatively deep oil source beds as the primary paraffinic crude oils. Later, during and/or after a generally upward migration into oil reservoirs, the primary crude may be transformed compositionally into a naphthenic crude oil.In none of the five widely scattered oil basins studied are medium to heavy naphthenic crude oils found at temperatures greater than a limiting subsurface temperature. The abruptness of the temperature cutoff of the change in oil compositions in all five oil basins, as well as the average value of the cutoff temperature of 66°C (150°F), leaves no doubt that the mechanism of this crude oil transformation process is microbial.Optical activity, which was observed in narrow saturate hydrocarbon fractions of the 80–325°C range of all microbially transformed crude oils, but not in the primary untransformed oils, is strong additional evidence for the microbial nature of the crude oil transformation process. The observed optical activity is explained by the microbial digestion at different rates of optical antipodes present in the primary paraffinic crude oils.To gain perspective the vast scale of the microbial oil transformation process in nature is pointed out. Billions of tons of heavy to medium-gravity naphthenic crude oils, originating from the microbial transformation of primary paraffinic oils, are present in oil fields and tar sands all over the world.     

Evaluating the timing of oil expulsion: about the inverse behaviour of light hydrocarbons and oil asphaltene kinetics

This paper deals with natural temperature records in the heavy (asphaltenes) and the light fractions (C₇—light hydrocarbons) of petroleum. Two sets of marine oils formed from different source rocks and petroleum systems were studied using asphaltene kinetics and light hydrocarbon analysis. Both fractions have been reported to contain information about the temperature the respective oils have been exposed to in the subsurface. These indicated temperatures generally correspond to the conditions in the source rock when expulsion occurred. Bulk kinetic analysis of reservoir oil asphaltenes as well as light hydrocarbon (LH) analysis (of dimethylpentanes) were used here in order to evaluate the expulsion temperatures. Surprisingly, when considering information coming from both fractions, an inverse trend between LHs expulsion temperatures (Ctemp) and asphaltenes (Tasph.) can be observed—high T_asph (asphaltene temperatures) occur with low LH C_temp (light hydrocarbon expulsion temperatures) and low T_asph can be observed when Ctemp is high. These differences are of fundamental importance for the use of such geochemical data in calibrating numerical basin models. The reason for this inverse behaviour is possibly due to the different expulsion behaviour of light hydrocarbons and the heavy fraction of oils, especially when the source rocks contain only moderate amounts of organic matter. In addition it has to be considered that the temperature predictions obtained using asphaltene kinetic analysis are related to the onset temperature of petroleum expulsion, while light hydrocarbons provide, at best, average expulsion temperatures.     

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.     

Carbon isotopes of organic matter from the upper Jurassic oil shales from the Volgian-Pechora shale province and its accumulation mechanisms

The isotopic composition of carbon from the organic matter of late Jurassic oil shales from the Volgian-Pechora shale province is studied. The existence of a dependence between C_org content in the rock and the isotopic composition of kerogen carbon is ascertained. The content of the heavy carbon isotope increases with increasing C_org. This dependence is accounted for by the progressive accumulation of isotopically heavy hydrocarbons of the initial organic matter due to sulfurization. The data on the isotopic composition of individual n-alkanes of bitumen in the rocks and the data on the absence of isotopic fractionation between thermobitumen and the residual kerogen from oil shales from the Volgian-Pechora shale province obtained by treating shale in an autoclave in the presence of water are presented first in this paper.     

Geochemistry of low-molecular weight hydrocarbons in hydrothermal fluids from Middle Valley, northern Juan de Fuca Ridge

Hydrothermal vent fluids from Middle Valley, a sediment-covered vent field located on the northern Juan de Fuca Ridge, were sampled in July, 2000. Eight different vents with exit temperatures of 186-281 °C were sampled from two areas of venting: the Dead Dog and ODP Mound fields. Fluids from the Dead Dog field are characterized by higher concentrations of ΣNH₃ and organic compounds (C₁-C₄ alkanes, ethene, propene, benzene and toluene) compared with fluids from the ODP Mound field. The ODP Mound fluids, however, are characterized by higher C₁/(C₂ + C₃) and benzene:toluene ratios than those from the Dead Dog field. The aqueous organic compounds in these fluids have been derived from both bacterial processes (methanogenesis in low temperature regions during recharge) as well as from thermogenic processes in higher temperature portions of the subsurface reaction zone. As the sediments undergo hydrothermal alteration, carbon dioxide and hydrocarbons are released to solution as organic matter degrades via a stepwise oxidation process. Compositional and isotopic differences in the aqueous hydrocarbons indicate that maximum subsurface temperatures at the ODP Mound are greater than those at the Dead Dog field. Maximum subsurface temperatures were calculated assuming that thermodynamic equilibrium is attained between alkenes and alkanes, benzene and toluene, and carbon dioxide and methane. The calculated temperatures for alkene-alkane equilibrium are consistent with differences in the dissolved Cl concentrations in fluids from the two fields, and confirm that subsurface temperatures at the ODP Mound are hotter than those at the Dead Dog field. Temperatures calculated assuming benzene-toluene equilibrium and carbon dioxide-methane equilibrium are similar to observed exit temperatures, and do not record the hottest subsurface conditions. The difference in subsurface temperatures estimated using organic geochemical thermometers reflects subsurface cooling processes via mixing of a hot, low salinity vapor with a cooler, seawater salinity fluid. Because of the disparate temperature dependence of alkene-alkane and benzene-toluene equilibria, the mixed fluid records both the high and low temperature equilibrium conditions. These calculations indicate that vapor-rich fluids are presently being formed in the crust beneath the ODP Mound, yet do not reach the surface due to mixing with the lower temperature fluids.     

Organic geochemistry of the Vindhyan sediments: Implications for hydrocarbons

The organic geochemical methods of hydrocarbon prospecting involve the characterization of sedimentary organic matter in terms of its abundance, source and thermal maturity, which are essential prerequisites for a hydrocarbon source rock. In the present study, evaluation of organic matter in the outcrop shale samples from the Semri and Kaimur Groups of Vindhyan basin was carried out using Rock Eval pyrolysis. Also, the adsorbed low molecular weight hydrocarbons, methane, ethane, propane and butane, were investigated in the near surface soils to infer the generation of hydrocarbons in the Vindhyan basin. The Total Organic Carbon (TOC) content in shales ranges between 0.04% and 1.43%. The S₁ (thermally liberated free hydrocarbons) values range between 0.01–0.09 mgHC/gRock (milligram hydrocarbon per gram of rock sample), whereas the S₂ (hydrocarbons from cracking of kerogen) show the values between 0.01 and 0.14 mgHC/gRock. Based on the T_max (temperature at highest yield of S₂) and the hydrogen index (HI) correlations, the organic matter is characterized by Type III kerogen. The adsorbed soil gas, CH₄ (C₁), C₂H₆ (C₂), C₃H₈ (C₃) and nC₄H₁₀, (nC4), concentrations measured in the soil samples from the eastern part of Vindhyan basin (Son Valley) vary from 0 to 186 ppb, 0 to 4 ppb, 0 to 5 ppb, and 0 to 1 ppb, respectively. The stable carbon isotope values for the desorbed methane (δ¹³C₁) and ethane (δ¹³C₂) range between −45.7‰ to −25.2‰ and −35.3‰ to −20.19‰ (VPDB), respectively suggesting a thermogenic source for these hydrocarbons. High concentrations of thermogenic hydrocarbons are characteristic of areas around Sagar, Narsinghpur, Katni and Satna in the Son Valley. The light hydrocarbon concentrations (C₁–C₄) in near surface soils of the western Vindhyan basin around Chambal Valley have been reported to vary between 1–2547 ppb, 1–558 ppb, 1–181 ppb, 1–37 ppb and 1–32 ppb, respectively with high concentrations around Baran-Jhalawar-Bhanpur-Garot regions (Kumar et al., 2006). The light gaseous hydrocarbon anomalies are coincident with the wrench faults (Kota – Dholpur, Ratlam – Shivpuri, Kannod – Damoh, Son Banspur – Rewa wrench) in the Vindhyan basin, which may provide conducive pathways for the migration of the hydrocarbons towards the near surface soils.     

Light hydrocarbons in subsurface sediments

The major features and numerous compositional details of the indigenous C₂–C₇ hydrocarbon suites of argillaceous sediments are systematically temperature dependent. The relative concentrations of alicyclic compounds exhibit a consistent maximum at subsurface temperatures close to 170°F (77°C) without regard to the chemical nature of the bulk of the kerogen, whether rich or poor in hydrogen, though this strongly affects the specific yield. A continuous increase in relative alkane content follows at higher temperatures. Indices of paraffinicity may be devised. One such, termed the ‘heptane value’ (essentially the percentage of n-heptane in the b.p. range 80.7–100.9°C), possesses a linear association with temperature, provides an index of catagenesis, and frequently provides a means of appraising paleotemperatures. Regressions of heptane value on temperature are compared in two composite stratigraphic sections dominated by kerogens representing two extremes of composition. The regression coefficients differ by 7%. Yields of light hydrocarbons increase exponentially in these sections by more than three orders of magnitude along sub-parallel, temperature-dependent curves. These similarities infer universally similar generating reactions and compositionally similar suites of light hydrocarbons at given subsurface temperatures, regardless of kerogen type, particularly for sections which underwent burial and heating during the Tertiary period.     

Elemental and organic geochemistry of Gondwana sediments from the Krishna–Godavari Basin,India

Elemental and organic geochemical studies have been carried out on the Gondwana sediments, collected from the outcrops of Permian and Jurassic–Cretaceous rocks in the Krishna–Godavari basin on the eastern coast of India, to understand their paleo and depositional environment and its implications for hydrocarbon generation in the basin. Amongst the studied formations, the Raghavapuram, Gollapalli and Tirupati form a dominant Cretaceous Petroleum System in the west of the basin. Raghavapuram shales and its stratigraphic equivalents are the source rock and Gollapalli and Tirupati sandstones form the reservoirs, along with basaltic Razole formation as the caprock. Major element systematics and X-ray diffraction study of the sandstones indicate them to be variably enriched with SiO₂ relative to Al₂O₃ and CaO, which is associated, inherently with the deposition and diagenesis of the Gondwana sediments. Post-Archean Average Shale normalized rare earth elements in shales show enrichment in most of the samples due to the increasing clay mineral and organic matter assemblage. A negative europium and cerium anomaly is exhibited by the REE's in majority of rocks. Composed primarily of quartz grains and silica cement, the Gollapalli and Tirupati sandstones have characteristics of high quality reservoirs. The shales show a significant increase in the concentration of redox sensitive trace elements, Ni, V, Cr, Ba and Zn. The total organic carbon content of the shales ranges between 0.1 and 0.5 wt%. Programmed pyrolysis of selected samples show the Tmax values to range between 352–497 °C and that of hydrogen index to be between 57–460 mgHC/gTOC. The organic matter is characterized by, mainly, gas prone Type III kerogen. The n-alkane composition is dominated by n-C₁₁–C₁₈ and acyclic isoprenoid, phytane. The aromatic fraction shows the presence of naphthalene, anthracene, phenanthrene, chrysene and their derivatives, resulting largely from the diagenetic alteration of precursor terpenoids. The organic geochemical proxies indicate the input of organic matter from near-shore terrestrial sources and its deposition in strongly reducing, low oxygen conditions. The organic matter richness and maturity derived from a favorable depositional setting has its bearing upon the Gondwana sediments globally, and also provides promising exploration opportunities, particularly in the Raghavapuram sequence of the KG basin.     

Thermal maturity and organic composition of Pennsylvanian coals and carbonaceous shales, north-central Texas: Implications for coalbed gas potential

Thermal maturity was determined for about 120 core, cuttings, and outcrop samples to investigate the potential for coalbed gas resources in Pennsylvanian strata of north-central Texas. Shallow (< 600 m; 2000 ft) coal and carbonaceous shale cuttings samples from the Middle-Upper Pennsylvanian Strawn, Canyon, and Cisco Groups in Archer and Young Counties on the Eastern Shelf of the Midland basin (northwest and downdip from the outcrop) yielded mean random vitrinite reflectance (R_o) values between about 0.4 and 0.8%. This range of R_o values indicates rank from subbituminous C to high volatile A bituminous in the shallow subsurface, which may be sufficient for early thermogenic gas generation. Near-surface (< 100 m; 300 ft) core and outcrop samples of coal from areas of historical underground coal mining in the region yielded similar R_o values of 0.5 to 0.8%. Carbonaceous shale core samples of Lower Pennsylvanian strata (lower Atoka Group) from two deeper wells (samples from ~ 1650 m; 5400 ft) in Jack and western Wise Counties in the western part of the Fort Worth basin yielded higher R_o values of about 1.0%. Pyrolysis and petrographic data for the lower Atoka samples indicate mixed Type II/Type III organic matter, suggesting generated hydrocarbons may be both gas- and oil-prone. In all other samples, organic material is dominated by Type III organic matter (vitrinite), indicating that generated hydrocarbons should be gas-prone. Individual coal beds are thin at outcrop (< 1 m; 3.3 ft), laterally discontinuous, and moderately high in ash yield and sulfur content. A possible analog for coalbed gas potential in the Pennsylvanian section of north-central Texas occurs on the northeast Oklahoma shelf and in the Cherokee basin of southeastern Kansas, where contemporaneous gas-producing coal beds are similar in thickness, quality, and rank.     

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.     

裂谷盆地的火山热液活动和油气生成

我国东部裂谷盆地主力烃源岩中均不同程度地发育有玄武岩和辉长岩等基性火成岩,并且伴有规模不等的热液活动。火山热液活动会给烃源岩带来热量,促使有机质快速生烃和异常成熟。玄武岩活动期间的热液作用为烃源岩提供了大量矿物质和养料,使周围泥质岩富含碳酸盐和有机质,可以形成优质烃源岩;热液活动向烃源岩提供了大量过渡金属元素,作者的实验证明了过渡金属对有机质生烃具有强烈的催化作用,使烃源岩在较低温度下生成较多数量的油气;火成岩周围的烃源岩可以提前进入生烃门限。     

Classification and thermal history of petroleum based on light hydrocarbons

Classifications of oils and kerogens are described. Two indices are employed, termed the Heptane and IsoheptaneValues, based on analyses of gasoline-range hydrocarbons. The indices assess degree of paraffinicity. and allow the definition of four types of oil: normal, mature, supermature, and biodegraded. The values of these indices measured in sediment extracts are a function of maximum attained temperature and of kerogen type. Aliphatic and aromatic kerogens are definable. Only the extracts of sediments bearing aliphatic kerogens having a specific thermal history are identical to the normal oils which form the largest group (41%) in the sample set. This group was evidently generated at subsurface temperatures of the order of 138°–149°C, (280°–300°F) defined under specific conditions of burial history. It is suggested that all other petroleums are transformation products of normal oils.     

The organic matter of a gulf coast well studied by a thermal analysis-gas chromatography technique

A thermal analysis-gas chromatography technique, previously described by Whelan et al. has been used to analyze cuttings from a Continental Offshore Stratigraphic Test (COST No. 1) drilled in the Gulf Coast of the U.S.A. The data allowed an evaluation of the degree of maturation of the organic matter and provided an accurate determination of the depth of the threshold of intense oil generation at 3048 m (10,000 ft.). Qualitative changes of hydrocarbons in the C₇–C₁₄ range were determined by gas chromatography and confirmed by gas chromatography-mass spectroscopy. These data are discussed in terms of generation and migration processes. The catagenetic evolution results in a strong tendency for a proportional increase in n-alkanes. Mass transfer phenomena may be responsible for updip movement of the lighter hydrocarbons.     

Biological marker compounds as indicators of the depositions! history of the Maoming oil shale

The Eocene Maoming oil shale from Guangdong Province occurs as a laterally uniform stratigraphic section, typically 20–25 m thick, from which the aliphatic hydrocarbon constituents of six representative samples were investigated using GC and C-GC-MS. The sediments evaluated included the basal lignite, a vitrinite lens from the overlying claystone, and four intervals from the massive oil shale bed. As expected, the lignite and vitrinite differ markedly from the oil shales. The lignite is dominated by bacterial hopanoids and components of higher plant origin, including C₂₉ steroids and triterpenoids such as oleanenes. Visually, the oil shale samples show corroded and degraded phytoclasts, spores, wispy particles of fluorescent organic material attributable to dinoflagellates and, especially in the uppermost sample, colonial algal bodies. The distributions of biological markers in the oil shales show many features in common, notably a dominance of dinoflagellate-derived 4-methylsteroids, and a significant proportion of higher-plant derived n-alkanes with marked odd-over-even carbon number predominance. Overall, they exhibit several features that resemble characteristics of the Messel shale. The hydrocarbons of the lowest shale horizon suggest that there may have been a gradual transition between deposition of the original peat and the subsequent oil shales. The aliphatic hydrocarbons of the uppermost shale are dominated by a number of C₃₁ and C₃₃ botryococcane homologues and other unusual branched alkanes possibly derived from green algae. All of the samples are immature. Overall, molecular and microscopic examination of the stratigraphic succession of the Maoming oil shale suggests a shallow, lacustrine environment within which peats were deposited. This lake subsequently deepened to support abundant algal populations, especially dinoflagellates, culminating in a dominance of botryococcoid algae.     

Asphalts, heavy oils, ozocerite and gases in the Dead Sea Basin

Solid, liquid and gaseous hydrocarbons occur throughout the Dead Sea Basin (Israel and Jordan) both in surface exposures and in drillings. The unaltered asphalts and heavy oils are characterized by very high sulfur content (ca. 11%) with δ³⁴S = +5% and δ¹³C = −28% to −29%, low content of n-paraffins, pristane to phytane ratio of 0.5 and by containing almost exclusively VO-porphyrins. The distribution of n-paraffins in samples from deep sources shows a smooth enveloped miximizing at C_15–20. Surface and shallow samples show clear evidence of biodegradation. The ozokerite, known only from the east side of the basin, is composed primarily of long chain n-paraffins with a maximum at C₃₉. The gases known from the southern margin of the basin are composed mostly of methane.The source for the bitumens is unknown. Two hypotheses are discussed. The first is that the asphalts and heavy oils represent an alteration products of crude oil which migrated into the basin or which might have been generated in the basin itself. The second hypothesis favors an origin from low temperature alteration of organic matter from a thermally immature source.     

Biogeochemistry of Mono Lake,California

Modern sediments of Mono Lake show marked variation in lipid composition with depositional environment. Constituents derived from the drainage basin, characterized by high molecular weight alkane hydrocarbons (C₂₅–C₃₁), and the steroids β-sitosterol and brassicasterol, predominate in near-shore environments. In the deepest part of the lake, sediments exhibit a combination of externally-derived constituents, and lipids derived from the lake biota; the latter characterized by low molecular-weight alkanes and alkenes (C₁₅–C₁₇), phytane, and the steroids ergost-7-en-3β-ol and 24-ethylcholest-7-en-3-β-ol. Steranes, 4-methylsteranes, and the C₁₈ and C₁₉ isoprenoids appear to be forming in the intensely reducing bottom sediments at the present time.The compositions of samples from the Pleistocene succession of Mono Basin suggest that sample-to-sample variation within the same stratum is negligible so long as unweathered samples from the same depositional environment are compared. Sediments having equivalent lithologies may or may not have similar compositions, but sediments having similar fossil contents do show similar lipid compositions. Subaerial weathering of sediments causes a marked decrease in the amount of extractable organic material, as well as distinct changes in its hydrocarbon composition. Specifically, weathered sediments exhibit a decrease in relative content of low molecular weight hydrocarbons and a relative increase in nC₂₂.Organic composition of sediments from the Pleistocene stratigraphie column cannot be correlated with depth of burial. Compositional changes with stratigraphie position are probably related to paleo-ecological factors such as population or productivity rather than depth of burial. Lithology and organic composition provide mutually-corroborating evidence regarding glacial advances in the adjacent Sierra Nevada Mountains. During glaciations, the lake sediments are rich in sandstones, and the organic composition shows a predominance of externally-derived debris, with no evidence for contributions from the lake biota.     

The genesis of the asphalt in the Dead Sea area

The hydrocarbon occurrences of asphalts, heavy oils and oil shales in the Dead Sea area and the possible genetic relation between them have been studied. The similarity in organochemical characteristics, i.e., the elemental composition of asphaltenes, the distribution pattern of the saturated hydrocarbons and the predominance of V (over Ni)-porphyrins in both the oils and the asphalts indicate a close relation between them. On the other hand, dissimilarities in the same organochemical characteristics in both the asphalts and the oil shale exclude the hypotheses that asphalt was generated and expelled from the oil shales or that the shales were contaminated by oils. Water washing and biodegradation are considered to be the processes through which preferential depletion of hydrocarbons occurred, altering the oils to asphalts. The burial of the degraded asphalt to a relatively great depth resulted in a secondary generation of small amounts of light saturated hydrocarbons in these asphalts. The oils, which are thought to be the precursors of the asphalts, have either been flushed into the Dead Sea depression from the surrounding elevated areas or have seeped upwards from deep local accumulations in the graben.