Petroleum Formation and Occurrence

Production, accumulation and preservation of undegraded organic matter are prerequisites for the existence of petroleum source rocks. The term “organic matter” or “organic material”, as used in this book, refers solely to material comprised of organic molecules in monomelic or polymeric form derived directly or indirectly from the organic part of organisms. Mineral skeletal parts, such as shells, bones, and teeth are not included. First, organic matter has to be synthesized by living organisms and thereafter it must be deposited and preserved in sediments. Depending on further geological events, part of the sedimentary organic matter may be transformed into petroleum-like compounds. It is important to realize that during the history of the earth the conditions for synthesis, deposition, and preservation of organic matter has changed considerably.

We know of the occurrence of petroleum and petroleum precursors (kerogen and bitumen) in Precambrian time (Nonesuch Shale, Michigan, USA). Through the Cambrian and up to the Devonian, mainly marine phytoplankton and bacteria, and to some extent benthonic algae and Zooplankton could have served as source material for petroleum. Thereafter, terrestrial organic matter derived from land plants offers an alternative source. The evolutionary level and kind of contributing source organisms may be of decisive influence on the type and amount of petroleum generated in a certain source rock. Therefore, one must consider the evolution of the biosphere in connection with the formation of petroleum.

The biological productivity of aquatic environments, especially marine environments, is of great importance to the formation of potential oil source rocks. Although the primary productivity of organic matter in aquatic environments is presently in the same range as in subaerial environments — due to the wide-spread occurrence of land plants — the chance for preservation of organic matter in sub-aquatic environments is far greater. In sub-aerial environments, free access of air, together with the presence of moisture, allows growth and action of bacteria, and hence a breakdown and destruction of organic matter. However, in sub-aquatic environments, the deposition of fine-grained sediments limits access of dissolved molecular oxygen. Thus, the activity of aerobic bacteria comes to a halt when the limited amount of oxygen trapped in the sediments is exhausted. In this connection, it is also important to realize that air contains 21% (vol) of oxygen, whereas water normally contains only a few ml of oxygen per 1. Therefore, in practical sense, organic matter is only preserved and fossilized in sub-aquatic sediments.

In the preceding chapters, we have learned that bacteria, phytoplankton, Zooplankton (especially foraminifers and certain crustaceans), and higher plants are the main contributors of organic matter in sediments. Natural associations of these various groups of organisms in various facies provinces thus determine composition and type of organic matter to be deposited and incorporated in sediments.

The accumulation of organic matter in sediment is controlled by a number of geological boundary conditions. It is practically restricted to sediment deposited in aquatic environments, which must receive a certain minimum amount of organic matter. This organic matter can be supplied either in the form of dead or living particulate organic matter or as dissolved organic matter. The organic material may be autochthonous to the environment where it is deposited, i.e., it originated in the water column above or within the sediment in which it is buried, or it may be allochthonous, i. e., foreign to its environment of depositon. Both the energy situation in the water body in question and the supply of mineral sedimentary particles must be such as to allow a particular kind of sedimentation. If the energy level in a body of water is too high, either there is erosion of sediment rather than deposition, or the deposited sediment is too coarse to retain low-density organic material. An example is a beach area with strong wave action. Furthermore, in coarse-grained sediment, ample diffusion of oxygen is possible through the wide open pores. On the other hand, if the level of energy is very low, too little sediment is supplied, and there is, like-wise, no appreciable organic sedimentation. Examples of this type occur in certain parts of the deep sea.

The physicochemical transformation of organic matter during the geological history of sedimentary basins cannot be regarded as an isolated process. It is controlled by the same major factors that also determine the variations of composition of the inorganic solid phase and of the interstitial water of the sediments: biological activity in an early stage, then temperature and pressure. Furthermore, organic-inorganic interaction can occur at different stages of the sediments evolution. Nature and abundance of organic matter may result in different behavior of the mineral phase, shortly after deposition; composition of minerals and structure of the rock may influence composition and distribution of organic fluid phases at depth. An excellent picture of the conditions of deposition and early history of sediments has been given by Strakhov (1962), and will be frequently used in the following paragraphs.

The time covering sedimentation processes and residence in the young sediment, freshly deposited, represents a very special stage in the carbon cycle. The first few meters of sediment, just below the water-sediment contact, represent the interface through which organic carbon passes from the biosphere to the geosphere. The residence time of organic compounds in this zone of the sedimentary column is long compared to the lifetime of the organisms, but very short compared to the duration of geological cycles: a 1-m section often represents 500 to 10000 years. During sedimentation processes, and later in such young sediments, organic material is subjected to alterations by varying degrees of microbial and chemical actions. As a result its composition is largely changed, and its future fate during the rest of the geological history predetermined within the framework of its subsequent temperature history.

Diagenesis in young sediments results in two main organic fractions of very different quantitative importance: kerogen amounts to the bulk of organic matter, whereas some free molecules of lipids include hydrocarbons and related compounds. These molecules have been synthesized by living organisms and get trapped in the sediment with no or only minor change (Fig. II.3.1). They comprise specific compounds of relatively high molecular weight (Fig. II.3.2), and can be considered as fossil molecules, or geochemical fossils. Such molecules will be considered later in greater detail (Sect. 3.3ff.) They represent a first source of hydrocarbons in the subsurface.

The term kerogen will be used here to designate the organic constituent of the sedimentary rocks that is neither soluble in aqueous alkaline solvents nor in the common organic solvents. This is the most frequent acceptance of the term kerogen, and results from a direct generalization to other rock types of the definition by Breger (1961) in carbonaceous shales and oil shales. However, it should be kept in mind that some authors still restrict the name kerogen to the insoluble organic matter of oil shales only, because kerogen originally was applied to the organic material found in Scottish shales, which yielded oil upon a destructive distillation. Such a distinction seems very artificial from a geochemical point of view, as the definition of “oil shale” is itself mostly an economic concept (a rock able to provide commercial oil products by heating) and subject to variations, according to the progress of technology and the fluctuation of petroleum economy.

As sedimentation and subsidence continue, temperature and pressure increase. In this changing physical environment, the structure of the immature kerogen is no longer in equilibrium with its surroundings. Rearrangements will progressively take place to reach a higher, and thus more stable, degree of ordering. The steric hindrances for higher ordering have to be eliminated. They are, for instance, nonplanar cycles (e.g., saturated cycles) and linkages with or without heteroatoms, preventing the cyclic nuclei from a parallel arrangement.

There is a wide variety of natural gas occurrences whose composition and modes of formation may be rather different. However, in this chapter only natural petroleum gas will be considered. While methane (CH₄) is always a major constituent of the gas, other components may be present: hydrocarbons heavier than methane (mostly ethane C₂H₆, propane C₃H₈, butane C₄H₁₀),carbon dioxide CO₂; hydrogen sulfide H₂S,nitrogen, hydrogen, argon, helium,condensate (liquid hydrocarbons dissolved in the gas: they are separated when the gas reaches surface or shallow subsurface positions).

The history of petroleum formation is summarized as a function of increasing burial of the source rock in Figure II.7.1, which represents the abundance and composition of the hydrocarbons generated, and in Figure II.7.2, which shows the correlative evolution of kerogens. The depth scale represented in Figure II.7.1 is based on examples of Mesozoic and Paleozoic source rocks. It is only approximate and may vary according to the nature of the original organic matter, its burial history and the geothermal gradient. Based on the fundamental knowledge presented in the previous chapters, the general scheme of oil and gas formation may be summarized as follows.

When discussing the formation and occurrence of petroleum, it is necessary to include a brief review on relevant aspects of coal formation. Both petroleum and coal originate predominantly from organisms of the plant kingdom and both are subjected to the same geological processes of bacterial action, burial, compaction, and geothermal heating that constitute diagenesis and catagenesis. There are, however, also some essential differences between the modes of coal and petroleum formation. Basically, these differences center around the fact that coal is found at its site of deposition as a solid and relatively pure massive organic substance, whereas petroleum is liquid and migrates readily from its place of origin into porous reservoir rocks. Kerogen is the main precursor material of petroleum compounds. It is finely dispersed and intimately mixed with the mineral matrix in petroleum source beds. Most coals are remnants of terrestrial higher plants, whereas the kerogen of petroleum source beds is generally dominated by phytoplankton and bacteria. Most acknowledged petroleum source beds were deposited in marine environments and most coals formed under nonmarine conditions.

The first mention of the oil shale industry goes back to the seventeenth century, when a British Patent no. 330 was issued in 1694 to Martin Eale, who “found out a way to extract and make great quantities of pitch, tar and oil out of a sort of rock” (Cane, 1967). The first industrial plant was developed in Autun, France in 1838, followed by another exploitation in Scotland, 1850. Since then many countries developed an oil shale industry: Australia (1865), Brazil (1881), New Zealand (1900), Switzerland (1915), Sweden (1921), Estonia (now USSR) (1921), Spain (1922), China (1929), South Africa (1935). The highest point of the development was reached during or immediately after World War II.

Petroleum accumulations are generally found in relatively coarse-grained porous and permeable rocks that contain little or no insoluble organic matter. It is highly improbable that the huge quantities of petroleum found in these rocks could have originated in them from solid organic matter of which now no trace remains. Rather, as discussed in previous sections, it appears that fluid petroleum compounds are generated in appreciable quantities only through geothermal action on high molecular weight organic kerogen usually found in abundance only in fine-grained sedimentary rocks and that usually some insoluble organic residue remains in the rock at least through the oil-generating stage. Hence, it can be concluded that the place of origin of oil and gas is normally not identical with the locations where it is found in economically producible conditions, and that it has had to migrate to its present reservoirs from its place of origin. This migration of petroleum, and the subsequent formation of commercial accumulations, will be discussed in this part of the book.

Most petroleum and gas accumulations are found between the surface and to a depth of about 6000 to 7000 m. The physical and chemical conditions that prevail in source and reservoir rocks change with depth of burial. Most pronounced is the increase of temperature and pressure.

Observed facts with respect to primary migration of petroleum can either be related to time and depth of migration, or to chemical differences, or similarities between the composition of source rock bitumen and related crude oils.

Secondary migration is defined as the movement of petroleum compounds through more permeable and porous carrier beds and reservoir rocks, as opposed to primary migration through dense, less permeable and porous source rocks. Secondary migration terminates in hydrocarbon pools, but tectonic events such as folding, faulting or uplifting may cause redistribution of filled oil or gas pools and thus initiate an additional phase of secondary migration. When this results in a new accumulation it is sometimes called remigration or tertiary migration.

Petroleum is ultimately collected through secondary migration in permeable, porous reservoir rocks in the position of a trap. Any permeable and porous rock may act as a reservoir for oil and gas. They may be detrital or clastic rocks, generally of siliceous material, or chemically or biochemically precipitated rocks, usually carbonates. It is not uncommon that petroleum is found in fractured shales. Occasionally, igneous and metamorphic rocks are hosts for commercial quantities of petroleum, when favorably located in proximity to petroleum-bearing sedimentary sequences. The fundamental characteristic of a trap is its upward convex shape of a porous reservoir rock in combination with a more dense and relatively impermeable sealing cap rock above. The ultimate shape of the convexity may be angular, curved, or a combination of both. The only important geometric parameter is that it must be closed in vertical and horizontal planes without significant leaks to form an inverted container. The strike contours of this inverted container on a structural map must encircle closed areas comprising what is termed closure area or closure of a trap. A rare exception to this rule is true hydrodynamic trapping.

Petroleum originates from the bitumen of source rocks. Migration, however, and especially primary migration, is the cause of considerable changes in composition when bitumen is compared to petroleum. On the one hand, only a small amount of the total dispersed bitumen is mobilized and transferred into carrier or reservoir rocks, and an even smaller amount is accumulated in oil fields. In producing areas the ratio of reservoired oil to dispersed bitumen ranges from 1:10 to 1:10,0009. On the other hand, such drainage is selective, as shown by the gross comparison between the bitumen present in source rocks and the corresponding crude oil in reservoirs. The heaviest and most polar molecules, like asphaltenes, are strongly adsorbed on the source rock and can hardly be expelled into the reservoir. Therefore, the common distribution of petroleum constituents in crude oil parallels the adsorptive behavior of these constituents, i.e., the least polar saturated hydrocarbons are most frequent, then follow aromatics and benzothiophenes, and least abundant are the most polar and most easily adsorbed resins and the least soluble asphaltenes. Even within a given structural type like n-alkanes, light molecules seem to be favored compared to heavy ones.

Various crude oil classifications have been proposed by geochemists and petroleum refiners. The purpose of these is very different, and also the physical or chemical parameters which have been used in the classifications. Petroleum refiners are mostly interested in the amount of the successive distillation fractions (e.g., gasoline, naphtha, kerosene, gas oil, lubricating distillate) and the chemical composition or physical properties of these fractions (viscosity, cloud test, etc.). Geologists and geochemists are more interested in identifying and characterizing the crude oils, to relate them to source rocks and to measure their grade of evolution. Therefore, they rely on the chemical and structural information of crude oil constituents, especially on molecules which are supposed to convey genetic information. In that respect molecules at relatively low concentrations, such as high molecular weight n-alkanes, steroids and terpenes, may be of great interest.

Geochemical fossils are biological markers that can convey information about the types of organisms contributing to the organic matter incorporated in sediments. Thus, they can be used for characterization, correlation, and/or reconstitution of the depositional environment, in the same manner as macro- or microfossils are commonly used by geologists. However, it should be remembered that aside from geochemical fossils, also other molecules may be used for correlation, provided they are characteristic enough.

Regularities in crude oil and gas composition have been observed for a long time. Some of those seem to have a regional significance, e.g., geologists know that crude oils from the Middle East are generally rich in sulfur, while oils from North Africa have a low sulfur content. Other regularities seem to be more general: for instance, in several places of the world, it has been observed that oil density decreases with depth; more generally, geochemists and refiners have observed that crude oil density, sulfur content, and viscosity are closely related.

Petroleum is a very complex mixture of organic compounds and has a high energy content; it is thermodynamically metastable under geological conditions. Petroleum after being pooled in a reservoir is therefore susceptible to alteration. Attention to the importance of alteration was directed by a number of papers (Williams and Winters, 1969; Evans et al., 1971; Bailey et al., 1973a), which investigated heavier crude oils of Western Canada.

The terms “heavy oils” and “tar sands” are trivial names which are not precisely defined in a physical, chemical or geological manner. The terms heavy oils and tar sands are derived from phenomenological features as observed by exploration geologists and reservoir engineers in the field and by refiners. Although it is generally understood that the bitumen-like product in tar sands is an extra-heavy oil, it has to be realized that there is no clear-cut difference between a heavy oil and the bitumen-like product in tar sands.

The derivation of petroleum from nonreservoir rocks is a well-established fact. Rocks that are, or may become, or have been able to generate petroleum are commonly called source rocks. The presence of insoluble organic matter (kerogen) is a primary requisite for an active or a potential source rock.

The objectives in crude oil correlation vary considerably, depending on exploration and production problems. In principle it is desirable to correlate different oils with each other, oils with their source rocks, gases with gases and, if possible, gases with oils and source rocks (Fig. V.2.1). Questions frequently posed to the exploration geologist are the following: is it possible to identify various types or families of oils, condensates or gases occurring in a sedimentary basin? Does each family have a single or multiple origin?is it possible to identify the source rock of a given oil, condensate or gas? Is it possible to detect intra-basinal facies changes in a given source rock that would result in the release of different and identifiable crude oils across the basin?

In the early days of petroleum exploration, wells were drilled where oil or gas seepages indicated the presence of petroleum. Later, with increasing sophistication of geological knowledge, and especially with the advent of exploration geophysics, the decision to drill a well was additionally taken on the basis of the recognition of suitable structures, such as anticlines, fault traps, unconformity traps and reefs. Frequently, the selection of a structure to be drilled was based on intuition and general experience rather than on pertinent information, because very little information was available whether or not a trap would contain hydrocarbons.

The purpose of the evaluation of a sedimentary basin in terms of petroleum exploration is to know the amount of oil and gas that has been generated and accumulated and then to locate it.

Four selected case histories of geologically different petroleum regions will be presented here: the Arabian Carbonate Platform, young delta areas, i.e., the Niger and the Mahakam Delta, the Linyi Basin of China and the Deep Basin of Western Canada. These case histories show the application of the new knowledge about the principles of petroleum generation, migration and accumulation. They demonstrate the understanding of source rock maturation and hydrocarbon generation as part of the geological evolution of a sedimentary basin. Following the considerations about the origin of hydrocarbons in each of the basins described, the most likely pathways and modes of migration into the reservoir rocks and traps are discussed. Finally the quality of the hydrocarbons found in traps is briefly outlined, with the implications with respect to the overall geological setting.

The observed distribution of known reserves of oil and gas has been studied by exploration geologists and also by petroleum economists. The former have considered the distribution in relation to geological history of the earth, and particularly basin types and global tectonics: Brod (1965), Uspenskaya (1966, 1972), Halbouty (1970), Olenine (1977), Meyerhoff (1979), Bois et al. (1980, 1982), Klemme (1980) and Sokolow (1980). Petroleum economists were more interested in predicting ultimate reserves world or national, based on potential future discoveries and/or increase of engineering and economic feasibility of recovery: Desprairies (1977), Nehring (1978), Halbouty and Moody (1979), Desprairies and Tissot (1980) and Boy de la Tour et al. (1981).