Download Coal, oil shale and petroleum

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.
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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).
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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.
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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):
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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).
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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).
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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.
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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.
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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.
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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).
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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).
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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.
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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.
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