Abstract Direct measurements of porosities from Tertiary and Cretaceous shales in the Texas-Louisiana Gulf Coast show that in many areas shale porosity is either constant or increasing at the depths where high overpressures occur andwhere hydrocarbons are being generated. In the absence of a decrease in porosity with sediment load (depth), gasgeneration becomes the principal cause of overpressures and hydrocarbon expulsion. Gulf Coast shale porosities decrease exponentially in normally compacting shales only down to porosities of about 30%, after which the decrease is linear until a constant porosity is reached. These linear trends are believedto be related to the high quartz content (74%) of the clay-size fraction (=4 microns). The depths at which shales reach relatively constant porosity values appear to depend on the internal surface areas of the shales. Shales containing minerals with small, internal surface areas, such as finegrained quartz andcarbonates, stop compacting at porosities around 3%, whereas shales containing minerals with large surface areas, such as smectite and illite, stop compacting around 10%. This interval of no compaction usually is reached at depths around 3 to 4 kilometers (temperatures of 85° to 110°C) prior to the development of deep high overpressures and the generation of large quantities of hydrocarbons in the Gulf Coast. Model studies indicate that gas generation is the dominant process creating these deep overpressures. The porosity-depth profiles that show a linear decrease with depth followed by a constant porosity do not conform to the hypothesized exponential profiles used in many modeling programs today. This means that more direct shale porosity measurements are needed to confirm the type of profiles that actually exist and should be used in any basin modeling program.

Abstract Carbonate rocks commonly have been discounted as important source rocks because of their lower organic-carbon content and lower catalytic activity in comparison to shales. However, carbonate source rocks contain mostly sapropelic organic matter, which yields a higher percentage of oil earlier than the more humic organic matter of shales. Furthermore, carbonate source-reservoir sequences are at many places overlain by the perfect seal, evaporite, during the time of oil generation and accumulation. In contrast, many sandstone-shale sequences tend to leak petroleum during and after accumulation. The richest source rocks in the world are the argillaceous and siliceous carbonates in formations such as the Green River of Utah, the La Luna of Venezuela, and the Nordegg of the Western Canada basin. Carbonate rocks like the Cretaceous Austin Chalk of south Texas, which contains 60–90% CaC0 3 , act as both source and reservoir rock. Light-hydrocarbon analyses and pyrolysis data both support the concept that most of the oil in the Austin Chalk is autochthonous.

Abstract Methane concentrations in the Black Sea average 0.1 ml/l at depths below 500 m and about 7 × 10 −4 ml/l in surface waters. The concentration gradient is causing an upward flux of about 47 ml of methane/m 2 /year across the interface between the deeper hydrogen sulfide waters and shallow oxygenated surface waters. The unsaturated hydrocarbons (ethylene and propylene) are present in the surface waters at twice the concentration of the saturated hydrocarbons (ethane and propane). In the deeper waters, the saturated hydrocarbons exceed the unsaturated hydrocarbons by several orders of magnitude. The methane appears to be originating from microbiologic degradation of organic matter in the sediments. Sediment gases taken from as deep as 800 cm in some cores were found to contain 92 percent methane with a δC 13 of about —68. Small amounts of ethane, propane, and butane also are being formed with the methane. A layer of sediment containing about 20 percent organic matter is present at about 50 cm in both the east and west basins of the Black Sea. This organic matter was found to be very high in aromatic hydrocarbons and asphaltic compounds and very low in paraffin hydrocarbons. The paraffins showed a strong predominance of odd-chain lengths in the carbon range from C 23 to C 33 . This organic matter is believed to be partly land derived.

Abstract A trap is of no value unless it has oil or gas in it. Prospecting, therefore, should include efforts to determine if petroleum was generated by the enclosing rocks and if it was likely to have collected behind the barriers that constitute the trap. Observations can be made to see if the rocks and fluids contain traces of hydrocarbon which would suggest that they are source rocks. Oil seeps from breached traps around the margin of a basin commonly suggest that similar traps may contain oil downdip. The key to stratigraphically trapped oil is the presence of barriers to fluid flow. Such barriers can be located by discontinuities in the patterns of fluid pressures. In mountainous areas, meteoric water commonly has gained access to strata which have regional continuity of permeability. Abrupt changes in water composition in these areas indicate barriers where stratigraphic factors may have preserved the petroleum.

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

Abstract Kerogen was isolated, by techniques developed in this study, from 21 rock samples representing a wide variety of ages, lithologies, and environments of deposition. The new techniques make it possible to separate relatively mineral-free kerogen from rocks containing less than one per cent of organic matter. With the recovery of relatively pure kerogen, it becomes possible to make reliable measurements of physical and chemical properties which otherwise would be difficult or impossible to obtain. Rocks deposited under marine conditions appear to contain either of two types of kerogen. One type is remarkably similar to coal in many of its properties, whereas the other is more like the kerogen of oil shales. Although age and lithology show little correlation with kerogen properties, there is evidence that the elemental composition of kerogen is controlled to some extent by the environments under which the rocks were deposited. Metamorphic forces also have affected the properties of kerogen, just as they have in coal. Two metamorphosed rocks yielded anthracite-like kerogen, and in one of these the presence of graphite was indicated by X-ray diffraction. Evidence is also presented that nitrogen occurs in both the organic and inorganic phases of sedimentary rocks. Metamorphic forces do not appear to have changed the nitrogen content of kerogen relative to carbon, except during the late stages of metamorphism. Although most oil probably originated from hydrocarbons in living organisms, some of the observations made in this study offer support for the theory that some oil may have been derived from kerogen.

Abstract Evidence for generation and migration of oil in sediments less than 10,000 years old was found on the flanks of the Pedernales anticline in the delta of the Orinoco River in Venezuela. The gray clay beds contain an average of about 55 parts per million hydrocarbons; the interbedded argillaceous sheet sands that are open to the surface on the flanks of the anticline contain about 40 parts per million. One lenticular sand about 110 feet deep, however, contained free gas and was enriched in hydrocarbons, mostly aromatic, to 160 parts per million. According to carbon-14 age determinations, this sand was deposited about 5,000 years ago. Measurements of excess hydrostatic pressure made in the holes and on undisturbed cores showed that there is a pressure gradient in the muds upward toward the laterally continuous sands and downward toward the Pleistocene unconformity. Both beds are apparently acting as conduits that permit the escape of fluids to their outcrops along the Pedernales structure. It is inferred from these data that in the lenticular sands, hydrocarbons are being filtered out of the moving stream of water by capillary action. This is not true of the continuous sands that are open to the surface.