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5 Coal, oil shale and petroleum 5.1 Introduction Organic matter can be found in most sedimentary rocks; sandstones contain about 0.05%, limestones contain around 0.3%, and mudrocks contain about 2%. This organic matter originated through photosynthesis, where plants manufacture carbohydrates from carbon dioxide and water using sunlight for energy and chlorophyll as a catalyst. From these carbohydrates, all types of organic matter in plants and animals can be produced. They might be buried with sediments to be later either broken down (decomposed) in the presence of oxygen into carbon dioxide and water (the reverse of photosynthesis) and thus disappear from the sedimentary record. Or, if there is a deficiency in oxygen, the organic decomposition is incomplete and quite stable organic compounds can be developed and preserved in the rock record. The preservation of organic matter takes place in anoxic (reducing) environments, such as stagnant lakes, stratified marine basins, swamps and bogs (mires). Under these reducing conditions, anaerobic decomposition takes place to produce hydrocarbons and other more complex organic compounds during diagenesis and metamorphism. The organic–rich sediments and sedimentary rocks (organic deposits) include oil shales, peat, lignite, brown coal and hard coal, as well as oil and natural gas derived from some of these organic-rich deposits. All of these organic–rich deposits can be termed fossil fuels that have immense significance to humans. 5.2 Modern organic deposits There are three types of organic deposits accumulating at the present time: humus, peat and sapropel. Humus is fresh, decaying organic matter occurring mainly in the upper part of soil profiles. Decay products are mainly humic acids that help in leaching rock fragments and clays. Humus is oxidized with time, thus it is not preserved in sediments. Peat is a dense mass of plant remains, which accumulate in waterlogged, boggy swamps and marshy regions, generally termed mires. The anaerobic conditions prevent the complete breakdown of the organic matter. Peat forms at all latitudes, in equatorial regions, in tropical rainforests and mangrove swamps, among others. Most coals come from peat derived from trees and leaves through compaction and alteration, so that tens of meters of peat are required to form one meter of coal. Sapropel refers to organic material that accumulates subaqueously (below water) in shallow to deep marine basins, lagoons and lakes. The organic matter is derived mainly from phytoplankton, which live in the upper photic zone. Fine–grained terrigenous clastic sediment can be deposited with the sapropelic organic matter. 1 Anaerobic conditions are required for preservation of the sapropel material unless very high rate of sedimentation or restricted water circulation or water stratification are involved. 5.3 Ancient organic deposits Organic matter in the sedimentary rocks could be: 1- Phytoclast, is the recognizable plant fragment such as wood, leaf or cuticle, etc. 2- Bitumen, is the liquid or solid hydrocarbon that is soluble in organic solvents, such as acetone or carbon-tetrachloride. 3- Asphalt, is the solid or semi-solid bitumen. 4- Kerogen, refers to the organic matter that is largely insoluble in organic solvents; it is a geopolymer consisting of long-chain hydrocarbons of high molecular weight. 5- Petroleum that consists of crude oils, chiefly short- and long-chain hydrocarbons, and gases, mainly methane, which migrated into porous rocks from source rocks. 5.4 Formation of coal and rank of coal Most coals are humic coals, formed by in situ accumulation of woody plant material (peat) in forest swamps. Humic coals form a natural series from peat through brown coal (lignite) and bituminous coals to anthracite. The changes from plants to coal are called coalification or carbonification. They are controlled mainly by temperature of burial, thus are also called organic metamorphism. Various microbiological, physical and chemical processes take place during coalification, all contributing towards the rank of coal. Rank of coal is a measure of degree of coalification or level of organic metamorphism. The initial stages of coalification take place during peat formation; the processes are mainly microbial, with little alteration of the original plant material. In soft brown coal (lignite) many plant fragments are readily seen, together with their original cell structure. A process of “gelification” during the formation of sub-bitumenous coal causes homogenization and compaction of plant cell walls, and this leads to the formation of vitrinite, one of the main constituents of bituminous coal. With increasing rank the carbon content increases and the volatile content decreases (Tab. 5.1, Fig. 5.1). 2 Tab. 5.1: The rank stages of coal with values of various parameters used to estimate rank. Fig. 5.1: Graph showing broad relationship between hydrogen and carbon content of coal with increasing rank. The volatiles include combustible gases, such as hydrogen, carbon dioxide and methane, and condensible substances, mainly water. Low-rank, volatile-rich coals burn easily with a smoky flame, whereas high-rank, volatile poor coals are more difficult to ignite, but burn with a smokeless flame. The carbonized residue remaining after removing the volatiles is called coke. Humic coals are classified according to their rank into the following classes (Tab. 5.1): a- peat, b- lignite (soft brown coal), c- sub-bituminous coal (hard brown coal), d- bituminous coal (hard coal), e- semi-anthracite, f- anthracite, and g- graphite, formed by metamorphism of anthracite. 3 The rank of coal can be measured by several parameters, including: the amount of carbon, hydrogen, oxygen, volatiles and moisture; the colorific value (amount of heat produced by burning); and the reflectance of vitrinite (Tab. 5.1). The rank of coal depends upon the depth of burial that determines the temperature, and the length of time that the coal has been subjected to. The rank of coal increases with depth as can be seen from Fig. 5.2. Fig. 5.2: An example of Carboniferous coal from Germany that illustrates the increase of coal rank with depth on the basis of volatile matter and carbon contents. With coals of different ages buried to the same depths, the older coals have a higher rank. 5.5 Coal petrology Coal consists of organic constituents and inorganic constituents. 5.5.1 Organic constituents In the study of coal petrology a polished surface of the coal sample is prepared to be studied by the reflected-light microscope, with oil immersion objectives for increased contrast. For the microscopic constituents of coal, the term maceral is used, analogous to the minerals of rocks. There are three types of macerals (Tab. 5.2): 4 Tab. 5.2: The principal macerals in coal 1- The vitrinite macerals (Fig. 5.3) include collinite and telinite which are derived from wood fragments that accumulated in stagnant, anaerobic water and were soon buried. Fig. 5.3: Photomicrographs showing the various macerals. A: liptinite (darkest areas), vitrinite (medium grey) and inertinite (very bright, light-grey); B: Vitrinite and thin streaks of inertinite (light grey color); C: Inertinite (semifusinite) and vireinite: D: Liptinite consisting of compressed microspores, vitrinite and inertinite (semifusinite, the very light layer). 5 2- The inertinite macerals include fusinite and semifusinite that are derived from wood tissues so that cell structures are preserved. Also they include sclerotinite that form from fungal remains, and micrinite that represent the thermal decomposition of resin. 3- The liptinite macerals include sporinite, derived from spores; cutinite, derived from cuticle; resinite, derived from resin; and alginate, derived from algae. With increasing rank, the whole coal becomes homogeneous and the macerals lose their identities. The four common microlithotypes forming the microscopic bands and layers in hard coal and composed of the various macerals described above are: vitrite, fusite, clarite and durite (Tab. 5.3). Tab. 5.3: The lithotypes and microlithotypes of coal, together with the principal macerals forming the microlithotypes. 5.5.2 Inorganic constituents Quartz grains, clay minerals and some heavy minerals are the main sedimentary inorganic constituents of coal. Kaolinite is the main clay mineral as many coals formed in tropical swamps, where this clay mineral is dominant in these regions. But with burial kaolinite is converted into illite, so in higher rank coals illite is more abundant. Early diagenetic nodules may be found in coals that are composed of siderite, ankerite, dolomite and calcite and pyrite. Pyrite is common in coals and is mainly derived from the activities of sulphate-reducing bacteria. 5.6 Occurrence of coal In the geologic record, coals were formed in humid climatic areas from the Devonian onwards, when plants evolved and proliferated. They were formed mainly in deltaic environments as thin (less than 3 m) but persistent seams, and in continental basins around lakes and in rift basins as very thick seams (hundreds of meters). 6 5.7 Oil shales Oil shales are diverse group of rocks which contain organic material that is mostly insoluble in organic solvents, but can be extracted by heating (distillation). The organic matter is mainly kerogen, but some bitumen may occur. The quantity of oil that can be extracted ranges from about 4% to 50% of weight of the rock, which means yielding 50 to 700 liters of oil per ton. Oil shales contain a substantial amount of inorganic material consisting of quartz silt and clay minerals. Some oil shales are actually organic-rich siltstones and mudstones, whereas others are organic-rich limestones, such as the Jordanian oil shales that are really bituminous limestones. Much of the organic matter in oil shales is finely disseminated and so altered that the organisms from which it formed cannot be identified. In many oil shales the remains of algae and algal spores are common so that the organic matter is assumed to be of algal origin. Fine-grained higher plant debris and megaspores also may be an important constituent. As with the formation of coal, anaerobic conditions are required to prevent oxidation of organic matter and to reduce the bacterial degradation, unless the rate of organic productivity is very high, when accumulation can take place in an oxidizing environment. Many oil shales formed in stratified water bodies where oxygenated surface waters permitted plankton growth, and anoxic bottom waters allowed the preservation of the organic matter. The kerogen in oil shales is mainly type I, that is it has a high H/C and low O/C ratio (Fig. 5.4), and is derived largely from algal lipid matter (fats and fatty acids), rather than carbohydrates, lignins or waxes. 7 Fig. 5.4: Van Krevelen diagram showing kerogen types I, II, and III and their evolution paths with increasing burial as oil, wet gas and dry gas are generated. Some kerogen in oil shales may be type III, formed from vascular plant debris. Certain metals, such as V, Ni, U and Mo are enriched in oil shales. Oil shales were deposited in lacustrine environments such as the Eocene Green River Formation of the western USA, or in marine environment such as the Jordanian oil shale. 5.8 Formation of kerogen Kerogen is a very complex geopolymer of high molecular weight formed from the diagenesis of organic matter. There are four major groups of organic compounds in living organisms: carbohydrates, lignin, protein and lipids. Their elemental composition is shown in Tab. 5.4. Tab. 5.4: Average composition of main organic compounds in organic matter compared with typical petroleum and kerogen. From Tab. 5.4 it appears that the composition of lipids is closest to kerogen. 8 In oxidizing environments, organic matter is broken down by aerobic bacterial activity and oxidation to CO2, and NH3 and H2O. But in reducing environments anaerobic bacteria decompose organic matter (especially carbohydrates, through fermentation and other processes) to new and residual organic compounds, and CH4 and CO2. The material left over from microbial-bacterial activity recombines by polycondensation and polymerization to form organic compounds, such as fulvic and humic acids. During shallow burial, depths of tens to hundreds of meters, and over several millions of years, these organic compounds are converted to insoluble humin. Further burial, with decreasing O/C and N/C ratios, leads to the formation of kerogen. The composition is very variable, but the kerogen of the Eocene Green River Formation is represented as C215H330O12N5S. With further burial, but still in the realm of catagenesis, the composition of kerogen is modified through decrease in the O/C and H/C ratios as oil and gas are generated as will be seen below. Kerogen in polished sections is a structurless organic material, usually occurring in bands and stringers parallel to stratification. Immature (shallow-burial) kerogen is a yellowamber color, but with increased burial and evolution (maturation). It takes on a brown and then black color. 5.9 Petroleum 5.9.1 Composition and occurrence The generation of petroleum is one of the stages in the alteration of certain types of organic matter buried in sediments. It is formed through increasing burial and temperature, thus its generation is part of the general process of organic matter diagenesis and metamorphism. Petroleum consists of crude oil and gas. Crude oils are mainly carbon (average 85 wt%) and hydrogen (13 wt%), in the ratio of 1.85 hydrogen atoms to 1 carbon atom. Minor elements, S, N and O generally constitute less than 3% in most oils (Tab. 5.4), and phosphorus and vanadium also may be present. The S, N and O values vary considerably, and sulphurous oils, known as sour oils with up to 7% S, are distinguished from low-sulphur sweet oils. Hydrogen is a much lighter element than the others, so that the specific gravity of oil, which is easily measured, does indicate the H content. A higher H content gives a lower specific gravity, for example a 14% H oil has a specific gravity of 0.86, whereas an oil of 12% H has a specific gravity of 0.95. Petroleum is composed of a great number and variety of simple and complex hydrocarbon compounds, from the smallest methane (CH4), with a molecular weight of 16, to the largest asphaltene molecules with molecular weights in the thousands. 9 The common hydrocarbon compounds in petroleum belong to the alkane-paraffin (CnH2n+2), naphthene-cycloalkane (CnN2n) and arene-aromatic (CnH2n-6) homologous groups. Compounds with sulphur, nitrogen and oxygen include the thiols, thiophenes, pyridines, quinolines, carboxylic acids and phenols. Natural gas occurs as a gap to oil reservoirs, in solution in oil (released when pressure decreases) and as a reservoir fluid alone. Dry gas mostly consisting of methane (CH4) and ethane (CH6) is distinguished from wet gas, with more than 50% propane (C3H8) and butane (C4H10). Wet gas is usually closely associated with oil, whereas dry gas is more associated with coal deposits and derived from deeply buried source rocks. H2S, CO2, and N2 may form a significant component of natural gas, and He is also present. Water occurs in most oilfields and is typically a brine, much more saline than seawater. At the present time about one-third of the world„s oil comes from the Middle East: Saudi Arabia, Iran, Iraq and the UAE. There are major oilfield “giants” in the USA, Canada, Russia, Venezuela, Nigeria, Libya, Mexico, Western Europe, North Sea and Indonesia, and many other countries have smaller oilfields. 5.9.2 Formation of petroleum Petroleum is derived from source rocks and then migrates into reservoir rocks, which are typically sandstones and limestones. The porosity and permeability of reservoir rocks are obviously very important. An impervious seal is required to prevent upward escape of petroleum from the reservoir and common cap rocks in oilfields are mudrocks and evaporites. To contain the petroleum some form of trap is necessary. Many traps are structural, involving folds (domes and anticlines), faults and salt diapirs, whereas others are depositional, arising from the geometry of the reservoir sandstone body or limestone mass and its overlying cap rock. Following is discussion of these steps of petroleum formation. Petroleum is derived from the maturation of organic matter deposited in fine-grained marine sediments. Organic-rich sediments can be deposited in anoxic silled basins, on shelf margins in association with upwelling, and on the sea floor at times of oceanic anoxic events. Many marine hydrocarbon source rocks formed at times of high organic productivity of marine plankton, coinciding with transgressive events and high-stands of sea level (Fig. 5.5). 10 Fig. 5.5: Schematic distribution of source rocks through time, relative to the first order global sea-level curve, and of crude oil reservoirs through time. Diagenesis of the organic matter begins very early at shallow burial depths, and substantial amounts of methane can be produced through bacterial fermentation. This marsh gas normally escapes to the atmosphere, but it might be trapped. Burial diagenesis of the deposited organic matter leads to the formation of kerogen, as discussed above. Burial to temperatures of 50-80 ºC causes thermocatalytic reactions in the kerogen, and in types I and II, cycloalkanes and alkanes are generated, two of the main constituents of crude oil. When this process takes place, the source rock is said to be mature. With increasing temperature, more and more oil is generated until a maximum is reached, and then the quantity decreases and an increasing amount of gas is formed (Fig. 5.6). 11 Fig. 5.6: Hydrocarbon generation with depth from organic matter, mainly kerogen contained in sediments. The precise depth at which hydrocarbons evolve depends on the geothermal gradient, the burial history, and type of kerogen present. The principal phase of oil generation takes place at a temperature around 70-100 ºC; in areas of average geothermal gradient this is at depths of 2-3.5 km (this is the oil window). The gas produced is wet initially, but above 150 ºC only methane (dry gas) is generated. Time also is a factor in source-rock maturation; higher temperature/greater burial depths are required for oil generation from younger rocks, compared with older rocks, which can thus reach maturity at lower temperature (Fig. 5.7). Fig. 5.7: Schematic representation of the relationship between time after burial of source rocks and the temperatures for oil and gas generation. 12 Some organic compounds in organic matter, the porphyrins, for example, are very resistant to diagenetic alteration and are found in hydrocarbon source rocks as well as crud oils. These geochemical fossils or biomarkers can be very useful in correlating an oil with its source rock. At higher temperatures, the biomarkers begin to break down so that they can also give an indication of the maturity of the source rock. In the search for petroleum, use can be made of the color of pollens and spores (palynomorphs) in the source rock to see if the stage of petroleum generation has been reached. With rising temperature and higher level of organic metamorphism, palynomorphs change color from yellow to brown when crude oil is evolved, and to black when dry gas is generated. An indication of burial temperature also can be obtained from the vitrinite reflectance of phytoclasts and the color of conodonts (Tab. 5.5). Other tests for source-rock maturity are the determination of H/C and O/C ratios, UV fluorescence and pyrolysis. 13