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79
Chapter 2
THE ORIGIN OF PETROLEUM
Clifford C. Walters
ExxonMobil Research & Engineering Co.
Annandale, NJ 08801
1. HISTORIC OVERVIEW
resource remained a mystery for much of man’s history. Classical literature is
noticeably devoid of insight and even Roger Bacon laments in his 1268
treatise Opus Tertium on the lack of discussion on the origins of oils and
1
petroleum emerged during the Renaissance. In his 1546 text De Natura
eorum quae Effluunt ex Terra, Georgius Agricola, a German physician,
2
and proposed that bitumen, like other minerals, condensed from sulfur.
Andreas Libavius, another German physician, theorized in his 1597 text
Alchemia that bitumen formed from the resins of ancient trees. These early
discussions mark the beginnings of one of the longest running scientific
debates: whether petroleum is formed by abiogenic processes that occur deep
within the Earth, or from sedimentary organic matter that was once living
organisms.
As fossil evidence emerged during the 18th century that coals were
derived from plant remains, many scientists proposed similar origins to
Lomonosov is credited by some to have proposed the theory that liquid oil
and solid bitumen originate from coal through underground heat and pressure
as early as 17573 and certainly by 17634. Various biogenic theories emerged
during the early 19 century suggesting that petroleum was derived directly
from biological remains or through a distillation process5.
Modern theories that petroleum originated from ancient sedimentary,
organic-rich rocks emerged during the 19 century. T.S. Hunt of the
Canadian Geological Survey concluded in 1863 that the organic matter in
th
th
Man has used petroleum since Biblical times, yet the origin of this natural
bitumen by Aristotle and other natural philosophers. Two theories on
expanded on the Aristot lian concept of exhalations from deep within the Earth
explain petroleum. The historic record is somewhat questionable, but Mikhailo
i
some North American Paleozoic rocks must be derived from marine
vegetation or marine animals, and that the transformation of this organic
matter to bitumen must be similar to the processes involved in coal
formation6. Leo Lesquereux, the American father of paleobotany, reached
similar conclusions after studying Devonian shales in Pennsylvania7, as did
Newberry in his study of Devonian shales in Ohio.8 Early 20th century field9
and chemical10 studies of the Monterey Formation by the U.S. Geologic
Survey provided convincing evidence that the oil was derived from diatoms in
the organic-rich shales. Similar studies of organic-rich shales conducted in
Europe during this time arrived at the same conclusion.11,12
Full ascendancy of the biogenic hypothesis began in the mid-20th century
with a convergence of scientific advances in paleontology, geology, and
chemistry. In 1936, Alfred Treibs established a link between chlorophyll in
living organisms and porphyrins in petroleum.13 Additional geochemical
evidence followed with the discoveries that low to moderate maturity oils still
retained hydrocarbon fractions with optical activity14, that the stable isotopes
of carbon of petroleum bear a biological fractionation15, and that oils contain
in addition to porphyrins, a host of hydrocarbons that can be traced back to
specific biological precursors16. Concurrent with these findings were field
studies recognizing that organic-rich strata occur in all petroliferous
sedimentary basins, that this sedimentary organic matter (kerogen) is derived
from biota, that it has been chemically altered from its initial state17,18 and,
that oil and gas is produced from this kerogen as the sediments are buried and
heated.19
Although there is overwhelming evidence for a biogenic origin, some still
advocate abiotic theories. The development of the modern abiogenic concept
is rooted in the mid-19th century. The prolific French chemist Marcelin-Pierre
Berthelot described in 1860 experiments where n-alkanes formed during the
acid dissolution of steels.20 Dmitri Mendeleev reasoned in 1877 that surface
hydrocarbons.21 Mendeleev’s abiotic theory, further refined in 190222, was
viewed initially as particularly attractive as it offered an explanation for the
growing awareness of the widespread occurrence of petroleum deposits that
suggested some sort of deep, global process.
Advocates of abiotic origin theories dwindled under the mounting
evidence for a biogenic origin of petroleum. By the 1960’s, there was little
support for an abiotic origin, except among a small group within in the
Former Soviet Union. First proposed in 1951 by Nikolai Kudryavtsev23 and
advanced over the years in numerous Soviet publications,3 a modernized
verison of Mendeleev’s hypothesis emerged. This theory relies on a
thermodynamic argument, which states that hydrocarbons greater than
methane cannot form spontaneously except at the high temperatures and
80 Walters
waters could percolate deep within the Earth, react with metallic carbides
forming acetylene, which could then condense further into larger
pressures of the lowest most crustal depths. The theory ignores the fact all of
life relies on being in thermodynamic disequilibrium with its environment.
In the West, astronomers have been the most vocal advocates for abiotic
petroleum. Carbonaceous chondrites and other planetary bodies, such as
asteroids, comets, and the moons and atmospheres of the Jovian planets,
certainly contain hydrocarbons and other organic compounds that were
generated by abiotic processes.24 Sir Fredrick Hoyle reasoned in 1955 that as
the Earth was formed from similar materials, there should be vast amounts of
abiogenic oil.25 In more recent years, Thomas Gold is the strongest promoter
for abiotic petroleum.26,27 Against the advice of nearly all geochemists and
petroleum geologists, Gold convinced the Swedish government to drill two
deep wells (Gravberg 1 in 1986-1990 and Stenberg 1 in 1991-1992) into
fractured granite under the Siljan ring, the site of an ancient meteorite crater.
The wells failed to find economic reserves and evidence for even trace
amounts of abiotic hydrocarbons is controversial.28
Geochemists do not deny the existence of abiogenic hydrocarbons on
Earth. Small amounts of abiotic hydrocarbon gases are known to be generated
29, 30
the thermal decomposition of siderite in the presence of water,31 and during
magma cooling as a result of Fischer–Tropsch type reactions.32 However,
commercial quantities of abiotic petroleum have never been found and the
contribution of abiogenic hydrocarbons to the global crustal carbon budget is
inconsequential.33
2. THE PETROLEUM SYSTEM
The accumulation of economic volumes of petroleum (oil and/or gas) in
the subsurface requires that several essential geological elements and
processes be present at specific time and space.3435 Source rocks generate and
expel petroleum when sufficient thermal energy is imparted to the
sedimentary organic matter (kerogen) to break chemical bonds. This heating
is induced usually by burial by overburden rock. Once expelled, petroleum
migrates either along faults and/or highly permeable strata. Accumulations
form only when high porosity strata (reservoir rocks) are charged with
migrating petroleum and the petroleum is prevented from further migration.
These petroleum traps are formed only when geologic movements result in
subsurface topographies (structural and stratigraphic) that block migration and
when the reservoir rocks are covered by low permeability strata (seal rocks).
The mere presence of these geologic elements is insufficient to form
petroleum reserves. Traps must be available at the time of oil expulsion and,
once charged, their integrity must be preserved until exploited. These
elements and processes constitute the Petroleum System (Figure 1).
81
The Origin of Petroleum
by rock-water interactions involving serpentinization of ultramafic rocks,
overburden
seal
reservoir
source
underburden
basement
++
Top Oil Window
Top Gas Window
oil migration
gas migration
stratigraphic
trap
Fault-bound
traps
anticlinal
trap
Figure 1. Elements of a Petroleum System. All petroleum systems contain: 1. at least one
formation of organic-rich sediments that has been buried to a sufficient depth by overburden
rock such that petroleum is generated and expelled, 2. Pathways (permeable strata and faults)
that allow the petroleum to migrate, 3. Reservoir rocks with sufficient porosity and
permeability to accumulate economically significant quantities of petroleum, and 4. Sealing
rock (low permeability) and structures that retain migrated petroleum within the reservoir rock.
The top and bottom of the oil window is approximated as a function of burial depth. In actual
basins, these depths are not uniform and vary as a function of organic matter type, regional heat
flow from basement, in thermal conductivity of the different lithologies, and burial history
(e.g., deposition rates, uplift, erosion, and hiatus events).
A rigorous discussion of the origin of petroleum should encompass all of
the interrelated elements of the petroleum system. Such a discourse is beyond
the scope of this review, which will focus only on the deposition of organic-
rich strata and the generation of petroleum from these sources. The reader is
referred to Exploring for Oil and Gas Traps, a publication of the American
Association of Petroleum Geologists, for a complete discussion of all aspects
involved with defining the petroleum system for effective exploration.36
Books by Tissot and Welte37 and Hunt38 provide detailed discussions of the
principles of petroleum geochemistry, and a recent paper by Peters and
Fowler39 is an excellent review of the application of modern geochemical
techniques to exploration and production practices.
3. DEPOSITION OF ORGANIC-RICH SEDIMENTARY
ROCKS
Petroleum source rocks are water-deposited sedimentary rocks that
contain sufficient amounts of organic matter to generate and expel
commercial quantities of oil and/or gas when heated. Such organic-rich
strata were deposited throughout Earth’s history, in nearly all geologic
environments, and in most sedimentary basins. Source rocks, however,
82 Walters
typically represent only a minor amount of basinal strata and are formed only
when specific conditions exist.
Three general factors control the deposition of organic-rich sediments:
productivity, dilution, and preservation (Figure 2).40,41,42 Biological
productivity determines the amount of organic matter that is contributed to
sediments. Dilution refers to the amount of inorganic minerals that mixes
active debate as to which factor was the most important in forming organic-
rich sediments.43 It is now recognized that these three factors are inherently
interrelated in a highly complex, and variable manner.
Sedimentary
Organic
Carbon
Biological
Productivity
photosynthesis
Sediment
Dilution
Terrigenous clastics
evaporates
Skeletal matter
Preservation
Aerobic/Anaerobic
Decomposition
Redox conditions
Nutrient Flux
Transport
Uplift
Erosion
Secondary
Biotic Input
Climate, Sea Level,
Tectonics, Volcanism,
Hydrates
Figure 2. Three major factors, primary productivity, preservation, and dilution, determine
whether organic-rich source rocks are deposited. These factors are interrelated and influenced
by a number of geologic conditions.
83
The Origin of Petroleum
with the organic matter. Once deposited, the organic matter must be
preserved in a form that may later generated petroleum. There was once an
Photosynthetic organisms, which include aerobic cyanobacteria, algae,
phytoplankton, land-plants, and some anaerobic bacteria, provide most of the
initial organic matter by fixing CO2 into biomass. The contribution of organic
matter by non-photosynthetic chemotrophs is minor, except in some unusual
environments, such as the deep-sea hydrothermal vents. Most of the non-
photosynthetic biosystems, such as methanotropic communities44, rely on
recycled carbon that was fixed originally by photosynthetic organisms. Many
factors moderate the biota and the primary productivity (e.g., such as nutrient
input from rivers and coastal upwellings, pCO2, temperature, and turbidity)
that are influenced by global climatic and tectonic conditions.
Figure 3. Generalized redox cycle for organic carbon. Production of new organic matter by the
photosynthetic fixation of CO2 (primary productivity) can occur with (aerobic) or without
oxygen (anaerobic) as a byproduct. Respiration and other processes result in the nearly
complete oxidation of this organic matter back to CO2. A small amount of the organic matter
in sediments escapes biological recycling and is preserved in rocks. Eventually, this carbon is
recycled to the surface as CO2 by geologic processes, such as subduction and venting, erosion
and weathering – or more recently, by the combustion of fossil fuels.
Much of the primary organic matter created by photosynthetic or
chemosynthetic autotrophs undergoes degradation by other organisms during
the secondary production of organic matter. Heterotrophic organisms in the
water column, sediments, and rock continually degrade and rework primary
aquatic and terrigenous organic matter (Figure 3). Aerobic respiration is very
rapid and efficient and primary organic matter may pass through a chain of
84 Walters
water and mud dwelling animals, protozoa, and bacteria, until fully consumed
and returned to the atmosphere/hydrosphere as CO2. Anaerobic bacteria also
degrade organic matter either by fermentation or by respiration using terminal
electron acceptors other than O2 (e.g., nitrate, sulfate, iron). These microbial
metabolisms are generally slower and may be curtailed by limited nutrient and
electron acceptors within the sediment porewaters. Consequently, some of
sedimentary organic matter, both from primary and secondary biogenic
sources, may escape recycling and become preserved in lithified rock. Hence,
anoxic conditions enhance the preservation of oil-prone organic matter and
promote the deposition of potential source rocks (Figure 4).
Figure 4. Oxic (left) and anoxic (right) depositional environments generally result in poor and
good preservation of deposited organic matter, respectively (after Demaison and Moore,
198045). The solid horizontal line separates oxic (above) from anoxic (below). In oxic settings,
bottom dwelling metazoa bioturbate the sediments and oxidize most organic matter. In anoxic
settings, especially where the oxic-anoxic boundary occurs in the water column, bottom-
dwelling metazoa are absent and sediments are not bioturbated.
The amount of oxygen in bottom waters or sediments is determined by it
rate of influx from the photic zone (via circulation and/or diffusion) and its
rate of consumption (biological oxygen demand). Topographical barriers,
currents, or water stratification due to temperature and salinity gradients may
limit water circulation and diffusion. A high supply of primary organic matter
raises the biological oxygen demand, rendering pore waters, and even the
lower water column, anoxic. This mechanism is seen in terrigenous
environments with high input of land-plant material (e.g. swamps, and coastal
85
The Origin of Petroleum
plains), and in lake and marine environments with high nutrient influx (e.g,
seasonal rains and overturn of water columns, and upwelling zones).
In anoxic marine environments, the most prevalent organisms are bacteria
that utilize sulfate and produce H2S. If not precipitated as pyrite by iron from
clays and other clastic minerals, H2S may react with organic matter,
2
sequestering, euxinic conditions (waters with free H2S) occur. The transition
between oxic and euxinic waters may occur within the sediments or water
column. Some strata with excellent source potential were deposited where
euxinic conditions extended into the photic zone.46 Biological activity may
also be restricted by hypersaline conditions that occur in playa lakes, lagoons,
and restricted marine settings.
Sedimentation rate influences both the preservation and concentration of
organic matter. The inorganic materials may be clastic (eroded clays and
sands), chemical precipitates (carbonates, salts), or biogenic (siliceous and
carbonate shells). Organic matter may be removed from biological recycling
by rapid burial, such as in deltaic settings. However, preservation is offset by
dilution and the resulting rocks may be relatively low in organic carbon.
Similarly, sediments resulting from high primary productivity, such as
diatomaceous cherts, may be have an upper limit in organic carbon because of
high autodilution. In general, sedimentary rocks with the highest
concentrations of organic matter are deposited under conditions of moderate
to high influx of primary organic matter, anoxic (possibly euxinic) bottom
waters, and low sedimentation rates.
4. KEROGEN FORMATION AND THE GENERATIVE
POTENTIAL OF SOURCE ROCKS
Although derived from biochemicals, the sedimentary organic matter in
source rocks, is markedly different in structure and chemical composition.
Living organisms are composed mostly of proteins, nucleic acids, and lipids.
Structural materials, such as lignin and cellulose, and various resins are fairly
well-defined biopolymers composed of a limited number of monomers. With
the exception of some halophilic green algae and a few bacteria47, only trace
amounts of hydrocarbons are produced directly as biomass by most living
organisms. In contrast, immature sedimentary rocks contain only low
concentrations of the functionalized biochemicals. Most of the organic
carbon is bound in a condensed, insoluble macromolecular material, termed
been called a “geopolymer” but this is a misnomer, as the term implies that
there is a repetition of distinct monomers and some structural order. Kerogen
has no unique molecular structure and can only be defined in terms of bulk
elemental composition and average molecular distributions.
86 Walters
incorporating sulfur. If the production of H S is greater than its rate of
kerogen, which has comparatively few functional groups. Kerogen has
Proteins,
Polysaccharides
Nucleic acids
Functionalized
lipids
Low-Molecular
Weight
Biomolecules
Biomacro-
molecules Hydrocarbons
Amino acids
sugars
nitrogen bases
Hydrolysis
Microbial
Degradation
CO2, NH3
BIOSYNTHESIS
Kerogen
Bioresistive
macro-
molecules
Selective
Preserv ation
Sulfurization
Condensation
Sulfurization
Condensation
Humic acids
Fulvic acids
Humin
Bitumen
Selective
Preservation
Resistive
lipids
Selective
Preservation
Selective
Preservation
Hydrocarbons
NSO compounds
Thermal
Decomposition
Thermal
Decomposition
BIOMASS
DIAGENENSIS CATAGENESIS
Microbial Recycling Microbial Recycling
Bitumen
Defunctionalization
Thermal
Decomposition
Figure 5. Kerogen is formed during diagenesis by the selective preservation of bio-resistive
macromolecules and from the incorporation of lower-molecular weight species. Modified from
Tegelaar et al. (1989)49.
Optically, kerogen is often described as mixtures of amorphous organic
matter and macerals, morphologically distinct particles that are mostly
derived from land-plants. The amorphous matter was once thought to be
derived from the complete breakdown of biological macromolecules that then
re-assembled in a random fashion with low molecular-weight biochemicals
(e.g., lipids).48 We now realize that there are biological macromolecules that
are alkyl-rich and resist microbial recycling.49 These bio-macromolecules
(e.g., cutan, sporopollenin, tannins, and algaenan) may constitute only a small
fraction of the initial biomass, but are selectively preserved and enriched
during early diagenesis (Figure 5). They provide a core for the incorporation
of functionalized low molecular-weight biochemicals, such as membrane
lipids and the breakdown products of less resistant bio-macromolecules. A
small fraction of this material may remain soluble, which along with biogenic
87
The Origin of Petroleum
hydrocarbons and lipids that resist incorporation, becomes the bitumen that
can be extracted from immature source rocks using organic solvents.
Kerogen formation begins at the point when living cells die and their
biochemicals are exposed to the geologic environment. Microbial processes
are mostly responsible for the breakdown of biological macromolecules and
the recycling of lower molecular-weight biochemicals, resulting in the
selective preservation of the more bio-resistive compounds. Low temperature
chemical reactions further alter kerogen through the loss of functional groups
(e.g., –NH3, –COOH), sulfur incorporation, condensation, cross-linking, and
aromatization. The processes and thermal regime under which kerogen
forms, termed diagenesis, occurs under mild thermal conditions (<80°C).
110
%TOC
100
1000
500
200
0.5 2520 50
Oil Prone
Gas &
Oil Prone
Gas Prone
Poor
Potential
Moderate
Potential
Good
Potential
Excellent
Potential
Range of Typical
Oil-prone
Source Rocks
0.8
1.2
Atomic H/C
Rock-Eval Hydrogen Index
Oil Shales
World Class
Source Rocks
Coaly
Shales
Figure 6. The quantity and quality of kerogen determines the generative potential of a source
rock. Boundaries for the classifications of generative potential are approximate. Typical marine
source rocks from productive basins contain ~2 to 6% TOC. Basins with world class reservoirs
may contain source units with appreciably higher amounts of carbon. Expulsion of oil may be
geochemists to rapidly screen rocks for their generative potential, heats a ground sample and
2
infrared detector. These responses can be calibrated to a rough approximation of the kerogen
H/C and O/C atomic ratios.
The quantity and quality of organic matter preserved during diagenesis of
sediment determines the generative potential of the source rock and whether it
will be prone to expel oil or gas. Quantity is determined by amount of
organic input, the degree to which it is preserved (either as primary or
88 Walters
difficult from rocks with <1-2% TOC. The hydrogen content of the organic carbon determines
the quality of the expelled hydrocarbons (during metagenesis). Kerogens with high H/C ratios
tends to generate oil, while those with low H/C ratios tend to generate gas. The Hydrogen Index
is based on the Rock-Eval instrumentation. This pyrolysis method, commonly used by petroleum
measures the pyrolyzate response on a flame ionization detector and a CO response by an
secondary biogenic matter), and by its dilution with inorganic mineral matter.
Typical oil-prone, marine source rocks contain 2-5 wt.% total organic carbon
(TOC), but strata in the range of 10-20% are known to occur in high yield
petroleum systems (Figure 6). Oil shales, many of which are lake deposits,
contain over 10% TOC. Coals are >80% TOC, and may be dilute with
varying amounts of clastic minerals to yield coaly shales with a wide range of
carbon content.
Kerogen quality is mainly a function of hydrogen content – kerogens with
high H/C ratios (> 1.2) are oil-prone, while those with lower H/C ratios (0.5
to 0.8) tend to generate mostly gas. Biogenic input of organic matter and the
manner of its preservation determine the hydrogen content of kerogen. Some
algae and bacteria are extremely rich in membrane lipids and aliphatic
biopolymers, such as algaenan. Sediments that receive this input have the
potential to be hydrogen-rich (kerogen H/C >1.5). Conversely, land-plant
lignins have low H/C ratios and sediments that received only this input are
hydrogen-poor (kerogen H/C ratios < 1.0). The hydrogen, sulfur, and oxygen
content of kerogen can be modified greatly during deposition and diagenesis.
Oxic conditions favor rapid and fairly complete heterotophic consumption of
primary organic matter. The organic matter remaining in the sediments tends
to be oxidized or inert. Anoxic conditions conserve, or even enhance, the
initial H/C ratio of the primary organic matter via selective preservation
and/or contributions from secondary biota. Euxinic conditions promote the
incorporation of sulfur, resulting in high S/C ratios.
There are many schemes that attempt to classify kerogen types by their
morphology, maceral and palynological assemblages, and/or bulk chemical
composition. The most widely used is a modification of a method developed
for coals50, whereby the H/C and O/C ratios are plotted (Figure 7). Kerogens
are assigned designations as being Type I, II, III, or IV depending where they
fall on the plot. Type I and II are oil-prone, Type III is gas-prone, and Type
IV is inert carbon.
This classification scheme can be sub-divided further by considering the
variation in sulfur content (Table 1). Since the incorporation of sulfur into
sedimentary organic matter involves the generated of H2S by sulfate reducing
bacteria, kerogens with high S/C ratios (0.04 to > 0.10) are found mostly in
marine (non-clastic) rocks where euxinic conditions may prevail. Type I
kerogens are deposited typically in continental lakes, which have no contact
with marine waters and lack a ready supply of sulfate. Consequently, sulfur-
rich Type IS kerogens arise only in unusual geologic settings where older
evaporite beds (e.g., gysum or anhydrite) are exposed and dissolved into
normally fresh lake water.51
89
The Origin of Petroleum
Figure 7. van Krevelen type diagram showing the distribution of kerogen types and some of
their precursor macerals in relationship to their H/C and O/C atomic ratios. A substantial
portion of their oxygen content is lost during diagenesis. Oil generation occurs during
catagenesis, whereby the H/C ratio of the residual kerogens decrease. When the H/C ratio is <
0.5, the residual kerogens are capable of generating only methane.
Type II kerogens are deposited primarily in marine settings dominated by
photosynthetic organisms. During early diagenesis, this organic matter may
react with H2S produced by sulfate-reducing bacteria that thrive in marine,
anoxic waters and sediments. H2S also reacts with iron and other metals,
forming inorganic sulfides. Consequently, marine Type II kerogens may
have varying sulfur content. Marine shales and mudstones, which contain
iron oxides and iron-rich clays, yield low-sulfur Type II kerogens and pyrite.
Carbonate, evaporite, and chert deposits, which are iron-poor, yield high-
sulfur Type IIS kerogens.
90 Walters
Type III kerogens form in swamps and coastal plains. As these
depositional environments may or may not have marine influence, the sulfur
content of coals can vary, but is generally low. Type III kerogens are
frequently allochthonous; that is, they are transported by fluvial systems into
delta and nearshore marine sediments where they may mix with locally
produced (autochthonous) Type II kerogens. Most Type III kerogens are
dominated by vitrinite, a land-plant maceral that has a low H/C ratio and is
gas-prone. Some coals, however, contain oil-prone material (Type IIIC) that
are derived from associated algae or from the selective preservation of
cutinous macromolecules. Many oils from Southeast Asia are generated from
Tertiary coaly shales that contain this type of kerogen.
Table 1. Kerogen types, their occurrence and bulk chemistry (at end of diagenesis)
Type Depositional Setting Primary Biotic
Input
H/C O/C S/C
I Lakes, restricted
lagoons
green algae
cyanobacteria
dinoflagellates
> 1.4 < 0.1 < 0.02
IS Lakes with a source of
sulfate (rare)
green algae
cyanobacteria
>1.4 < 0.1 > 0.04
II Marine shales marine algae,
phytoplankton
1.2 - 1.4 ~ 0.1 0.02 - 0.04
IIS Marine carbonates,
evaporites, silicates
marine algae,
phytoplankton
1.2 - 1.4 ~ 0.1 > 0.04
III Coals, coaly shales,
deltas
vascular land-
plants
0.7 - 1.0 > 0.1 < 0.021
IIIC Coastal plains (oil-
prone coals)
vascular land-
plants, algae
1.0 to 1.2 > 0.1 < 0.021
IV Inert carbon due to
oxidation or advanced
maturity
All possible < 0.5 < 0.15 < 0.022
1 Coals generally are low in sulfur. Depositional settings with marine influence may result in
coals with S/C > 0.02.
2 Some inert pyrobitumens may have higher S/C ratios as a result of secondary sulfur
incorporation.
5. GENERATION AND EXPULSION OF OIL AND GAS
During catagensis, kerogen thermally cracks and produces bitumen. Weak
C—S and C—O bonds break preferentially during the early stages of
catagenesis producing bitumen that is highly enriched in polar (NSO)
compounds. With additional heating (~90-140°C), C—C bonds break within
the evolved polar compounds and from residual kerogen, yielding a
hydrocarbon-rich fluid that is then expelled from the source rock’s mineral
matrix. With additional thermal stress, kerogen yields primarily condensate
and then wet gas (C1-C6). Catagenesis is complete when the kerogen has
expended its capacity to generate C2+ hydrocarbons (~150-175°C).
Metagenesis may then take place under still more severe thermal alteration,
91
The Origin of Petroleum
where only methane is produced as methyl-groups are cleavage from highly
condensed, aromatic structures.
30 80 130 180 230 280
Temperature, °C
0
20
40
60
80
100
% Fraction
Kerogen
Heavy Oil
Light Oil Wet Gas
Methane
0
5
10
15
20
25
42 44 46 48 50 52 54 56 58 60 62 64 66
1°C/Ma heating rate
Type II
1.2
0.5
1.0
1.1
0.9
0.8
0.7
0.6
H/C
4.0
3.61.81.3
Figure 8. Example of a kerogen decomposition kinetic model with predictions of expelled fluid
composition. The rate of kerogen conversion is assumed to follow a series of parallel first order
kinetic reactions defined by the Arrhenius equation, k = Ae-(E/RT), where k is the rate coefficient,
A is a constant termed the frequency factor, E is the activation energy, R is the universal gas
constant, and T is the temperature. The kerogen model was derived by fitting the yield curves
of pyrolyzates that evolved from a marine shale source rock containing Type II kerogen heated
at several different heating rates under anhydrous conditions. In this case, the model was fitted
using a fixed frequency factor, A = 1 x 1014 sec-1. The evolved products are predicted from a
more advanced model that accounts for expulsion and secondary cracking of retained bitumen
and residual kerogen.
Oil generation is a kinetic process – both time and temperature are
critical52. The kinetic parameters of kerogen decomposition can be
determined by artificially heating immature source rocks using relatively fast
heating rates (~300 to 550°C at ~ 1 to 50 °C/min) or lower isothermal
temperatures (275-350°C for several days) and measuring either product yield
or the residual generative potential. Data are fitted to kinetic models defined
by a series of first order parallel reactions, usually at a single frequency factor.
When geologic heating rates are applied (~1 to 10°C/Ma), the derived kinetic
models yield kerogen maturation results comparable to what is observed in
92 Walters
petroliferous basins.53,54 More advanced models describe the fluid
composition of the expelled products and include secondary cracking
reactions (Figure 8).
Although simple thermogensis adequately describes petroleum generation,
geocatalysis involving reactive mineral surfaces, clays, trace metals, or
organic species have been proposed.55,56 Such processes are highly
speculative, and it is difficult to image how inorganic agents would remain
activated under subsurface conditions or how mass transport limitations
inherent in solid-solid interactions could be circumvented57.
Once generated from the kerogen, petroleum is expelled into mineral pore
spaces (primary migration) and then through permeable rock and faults to the
trap (secondary migration). Oil expelled from a source rock is enriched in
saturated and aromatic hydrocarbons relative to the bitumen that remains
(Figure 9). The factors that control primary expulsion and bitumen
fractionation are largely unknown; and, although there is generally a lack of
experimental or observational evidence for the underlying mechanisms, there
is no shortage of hypotheses. Expulsion models that attempt to account for
these chemical differences generally assume rate-limiting processes occur in
the release of generated hydrocarbons from the kerogen or in the movement
of hydrocarbons within the mineral matrix.
Hypotheses based on kerogen-oil interaction postulate that the expulsion
of oil is controlled by absorption or adsorption of the products onto the
surface of the kerogen,58,59,60 diffusion of the hydrocarbons through the
kerogen61,62,63,64 and/or relative solubility.65 These hypotheses attribute little
importance to movement of petroleum within the source rock mineral matrix
and the efficiency of the release of oil is controlled primarily by the amount of
organic carbon and its composition (see, Pepper & Corvi, 1995; and
references therein53). Expulsion models based on the interactions of
generated products with the source kerogen have gained favor in recent years
as they have the potential to account for compositional differences between
bitumens and expelled oil and for expulsion efficiencies that depend on
kerogen type and richness. This thinking can be traced to observations made
on source rocks66 and to recognition of the absorptive capacity of solid
organic matter as revealed by solvent swelling experiments.67,68,69,70 It is now
clear that Type I and II kerogens and Type III and IIIC coals have sufficient
sorptive properties to explain residual oil concentrations in mature source
rocks.
93
The Origin of Petroleum
saturates
aromatics + thiophenic-aromatics
polars (NSO) + asphaltenes
Expelled Oils
Source Rock
Bitumen Extracts
Type II
(Marine Shales)
Type IIS
(Carbonates)
Figure 9. Comparison of C15+ chemical group type distributions of expelled oil and retained
bitumens for typical Type II (marine shale) and Type IIS (carbonate) source rocks (middle of
the the oil window).
There are many expulsion models that target chemical or physical
processes of oil moving within the source rock mineral matrix as the rate
determining step. Different aspects have been considered to be important in
this movement. Some consider the amount and type of organic matter as
being critical to generating sufficient bitumen to exceed a pore saturation
threshold.71,72,73 Others postulate that the establishment of effective and
continuous migration pathways within the source rocks is critical.74,75,76
Other factors suggested to be key elements in expulsion are: pressure
build-up from generation and compaction and the failure of the rock fabric
resulting in micro-fracturing,77 gas availability and movement of oil in a gas
or supercritical phase,78,79 or movement of oil in an aqueous phase.80,81 For
the most part, the conditions that determine these elements are controlled by
the primary sedimentological conditions in the depositional environment of
the source rock and secondary diagenetic processes. Consequently, the
94 Walters
mechanisms that define oil movement differ according to the lithofacies of the
source rock.
6. COMPOSITION OF PRODUCED PETROLEUM
The molecular and isotopic composition of produced petroleum is
determined by complex chemical, physical, and biological processes.
Generation and expulsion from the source rocks, phase behavior as the
petroleum moves from source to reservoir, reservoir fill history, and
secondary alteration processes all influence oil and gas compositions.
Each source facies generates oil with distinct chemical composition that
reflects biotic input, depositional setting, and thermal history (Figure 10). For
example, lacustrine and coaly source rocks generate waxy, low-sulfur crudes,
while carbonate and evaporite source rocks generate asphaltic, high-sulfur
crudes. These compositional differences are most apparent during the initial
stages of oil expulsion and become less distinct as the source proceeds
through catagenesis where secondary cracking reactions become prevalent.
Although petroleum is derived from biological organic matter, most of the
individual compounds cannot be assigned to a specific biochemical precursor.
Some petroleum hydrocarbons, termed biomarkers, retain enough of their
original carbon structure that a likely biochemical precursor can be assigned.82
The abundance and distribution of biomarkers allow geochemists to infer the
origin and thermal history of oils.
Once generated and expelled from the source rock, petroleum composition
can be further modified during migration and entrapment within the reservoir.
In most petroleum systems, the source formation is at greater temperature and
pressure than the reservoir and migrating petroleum fluid may separate into
gas and liquid phases that can then migrate independently.83,84,85 Petroleum
also interacts with water and the more soluble hydrocarbons may selectively
partition into the aqueous phase.86
Once in the reservoir, secondary processes can alter oil composition.
Biodegradation, the consumption of hydrocarbons by microorganisms, is
likely to occur in shallow, cool reservoirs (<80°C).87,88 This process
selectively removes saturated hydrocarbons, enriching the residual crude oil
in polar and asphaltic material. Biodegradation forms acids and biogenic CH4,
CO2, and H2S. Microbial alteration of crude oils is a relatively fast process
and may occur naturally or result from poor production practices.
Thermochemical sulfate reduction (TSR) is another reservoir alteration
process that can affect oil quality and quantity. It is a chemical redox process
that occurs at relatively high temperatures (>120°C), where hydrocarbons are
oxidized to CO2 and sulfate is reduced to H2S.89,90 The residual oil is depleted
in saturated hydrocarbons and enriched in sulfur-aromatic species. Reservoir
charging and fill history also can alter oil composition. For example, mixing
95
The Origin of Petroleum
of gaseous hydrocarbons with a heavy oil can cause asphaltenes to precipitate,
forming a tar mat.91
Type IIS carbonat e source
API = 17.6 %S = 4.48
Ni = 56 ppm V = 320 ppm
%Sat = 12.4 %Aro = 28.4
%NSO = 37.7 %Asph = 19.7
Pr/Ph = 0.62 CPI = 0.85
n
-C
20
n-
C
16
n-C
15
n
-C
14
n
-C
13
n
-C
12
n-C
11
n
-C
10
n-C
6
n
-C
7
n-C
9
n
-C
8
n
-C
17
n-C
18
n-C
21
n
-C
22
n-C
23
n
-C
24
n-C
26
n
-C
19
Pristane
Phytane
ip
18
n-C
17
Pristane
n
-C
18
Phytane
n
-C
27
n-C
28
n-C
26
n-C
29
n-C
30
n-C
31
n
-C
32
n
-C
33
n
-C
34
Type II marine shale source
API = 39.4° %S = 0.18
Ni = 3 ppm V = 5 ppm
%Sat = 66.4 %Aro = 24.6
%NSO = 8.3 %Asph = 0.9
Pr/Ph = 1.55 CPI = 1.01
n-C
20
n-C
16
n-C
15
n-C
14
n-C
13
n-C
12
n-C
11
n-C
10
n-C
6
n-C
7
n-C
9
n-C
8
n-C
17
n-C
18
n-C
21
n-C
22
n-C
23
n-C
24
n-C
25
n-C
26
n-C
19
Pristane
Phytane
ip
18
ip
16
ip
15
ip
14
ip
13
n-C
5
n-C
17
Pristane
n-C
18
Phytane
Methycyclohexane
n-C
4
Type IIIC coaly sour ce
API = 38.0 %S = 0.17
NI = 8ppm V = 36 ppm
%Sat = 49.0 %Aro = 28.0
%NSO = 20.3 %Asph = 0.7
Pr/Ph = 6.23 CPI = 1.11
n
-C
20
n-C
16
n
-C
15
n-C
14
n-C
13
n-C
12
n-C
11
n
-C
10
n
-C
7
n-C
9
n-C
17
n-C
18
n
-C
21
n-C
22
n-C
19
n
-C
17
Pristane
n-C
18
Phytane
n-C
6
n-C
8
n
-C
23
n-C
24
n
-C
25
n-C
26
MCH
n-C
27
n-C
28
n-C
29
n-C
30
n
-C
31
n-C
32
n
-C
33
n-C
34
Pristane
Cadinanes
Type I lacustrine source
API = 41.3 %S = 0.07
Ni = 4 ppm V = 3 ppm
%Sat = 68.7 %Aro = 13.0
%NSO = 17.8 %Asph = 0.6
Pr/Ph = 2.63 CPI = 1.05
n-C
20
n-
C
1
6
n-C
15
n-C
14
n-C
13
n-C
12
n-C
11
n-C
10
n-C
6
n-C
7
n-C
9
n-C
17
n-C
18
n-C
21
n-C
22
n-C
23
n-C
24
n-C
25
n-C
19
Pristane
Phytane
n-C
17
Pristane
n-C
18
Phytane
n-C
27
n-C
28
n-C
26
n-C
29
n-C
30
n-C
31
n-C
32
n-C
33
n-C
34
n-C
8
Figure 10. Whole-oil gas chromatograms showing examples of oils from different source
kerogens. The grayed area, showing the elution of n-C17, pristane (Pr), n-C18, and phytane
(Ph), is enlarged. Pr/Ph is the pristane/phytane ratio, which is used to infer the depositional
environment (anoxic, hypersaline Pr/Ph<1, oxic water column/anoxic sediments Pr/Ph 1~2,
oxic deposition Pr/Ph>2). CPI is the carbon preference, which is used to infer
carbonate/evaporite source facies <1, and higher land-plant input CPI > 1. API gravity, the
concentrations of sulfur (S), nitrogen (N), nickel (Ni) and vanadium (V) and the C15+ chemical
group-type compositions are influenced by of the organic matter, depositional environment,
and thermal history of their source rocks and by reservoir alteration processes.
The composition of crude oil that arrives at a refinery is not identical to
reservoir fluids. Gas and water is separated at the well head and emulsions
are broken. Consequently, oils lose some light hydrocarbons (<C6) by
evaporation during production and transport. Pipeline and tanker oils are
frequently blends of oils from multiple fields and reservoirs, which
individually may be of varying composition and quality. For these reasons,
testing of subsurface fluids from individual reservoirs is necessary to
determine field economics and design reservoir management practices.
96 Walters
7. SUMMARY
The theory that petroleum originates from sedimentary organic matter that
was once living organisms is consistent will all natural observations,
laboratory analyses and experiments, theoretical considerations, and basin
simulations. The accumulation of economic quantities of petroleum (oil and
gas) requires that a series of processes occur within sedimentary basins.
Organic-rich sediments are deposited only under specific conditions that
promote the production of biota and/or transport of biogenic organic
compounds and the selective preservation of this material. The sedimentary
organic matter converts to kerogen, an insoluble macromolecule with a
composition that reflects the biotic input and chemical alterations
(sulfurization, condensation, defunctionalization, and aromatization) that
occur during diagenesis. Once lithofied, these organic-rich strata have the
potential to generate oil and gas when buried and heated to promote thermal
cracking. Expelled petroleum migrates from the source through fractures and
permeable strata. Economic reserves occur when geological conditions allow
for the accumulation, retention, and preservation of significant volumes of
migrated petroluem. Collectively, these processes describe a petroleum
system.
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new insights. Sedimentary Geology 2001, 140, 143-175.
91 Wilhelms, A.; Larter, S.R. Origin of tar mats in petroleum reservoirs: part II: formation
mechanisms for tar mats. Marine Petrol. Geol. 1994, 11, 442-456.
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The Origin of Petroleum
... Although still controversial, it seems that fossil fuel on our planet have a biogenic origin and they come from organic matter produced, among others, by phytoplankton and accumulated on the ocean floor in a process that started in the Mesozoic age (252-266 million years ago) and took millions of years to form the current deposits (Walters, 2006). Due to the long time required for deposits' formation and for the changes in the conditions that allowed their formation, fossil fuels are considered a not-renewable resource even though their burning still represents the main energy supply for humanity and the main engine of world economy. ...
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Phytoplankton, the ecological group of microalgae adapted to live in apparent suspension in water masses, is much more than an ecosystem's engineer. In this opinion paper, we use our experience as phytoplankton ecologists to list and highlight the services provided by phytoplankton, trying to demonstrate how their activity is fundamental to regulate and sustain Life on our Planet. Although the number of services produced by phytoplankton can be considered less numerous than that produced by other photosynthetic organisms, the ubiquity of this group of organisms, and their thriving across oceanic ecosystems make it one of the biological engines moving our biosphere. Supporting services provided by phytoplankton include almost half of the global primary and oxygen production. In addition, phytoplankton greatly pushes biogeochemical cycles and nutrient (re)cycling, not only in aquatic ecosystems but also in terrestrial ones. In addition, it significantly contributes to climate regulation (regulating services), supplies food, fuels, active ingredients and drugs, and genetic resources (provisioning services), has inspired artistic and craft works, mythology, and, of course, science (cultural services), and much more. Therefore, phytoplankton should be considered in all respects a true biosphere's engineer.
... The data of hydrogen index (HI; mg HC/g TOC) versus oxygen index (OI; mg CO2/g TOC) (table 1) show predominantly kerogen type I and II (Figure 3). On the other hand, the Van-Krevelen diagram based on elemental analysis data (Table 2) Table 2 [3,[22][23][24][25]. Under such conditions, the anaerobic bacteria (sulfate reducing bacteria) have altered sulfur contents of the environment. ...
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Knowing the characteristics of suitable environments for precipitation of oil prone source rocks facilitates oil explorations and leads to development of oil fields. The current study investigates the organic matter properties and sedimentary environment conditions of the Garau Formation in various outcrop sections in Lurestan province from southwest of Iran (High Zagros) with using elemental analysis, visual kerogen analysis and Rock-Eval pyrolysis data. The geochemistry parameters indicate that the Garau Formation is an excellent oil prone source rock and composed of kerogen type I and II. The oxygen index (OI) is very low which reveals that organic matter deposited in an anoxic sedimentary environment and suitable for the preservation of organic matter and hydrocarbon generation. The visual analysis of isolated kerogens from source rock samples indicates the abundance of dark amorphous organic matter (AOM) with small amounts of phytoclasts and pyrite with no palynomorphs. Sedimentation seems to have occurred in deep and reduced parts of a carbonate basin during a rapid transgression. In addition, due to the effect of thermal maturation, the color of amorphous organic matter has darkened. The elemental analysis and Van-Krevelen diagram was shown that the type of organic matter and reveals the thermal maturity of the oil window. Moreover, amount of pyritic sulfur (Sp) and organic sulfur (So) contents have been calculated, and it was reveals that the high content of organic sulfur is a key element in the structure of organic matter.
... The data of hydrogen index (HI; mg HC/g TOC) versus oxygen index (OI; mg CO2/g TOC) (table 1) show predominantly kerogen type I and II (Figure 3). On the other hand, the Van-Krevelen diagram based on elemental analysis data (Table 2) Table 2 [3,[22][23][24][25]. Under such conditions, the anaerobic bacteria (sulfate reducing bacteria) have altered sulfur contents of the environment. ...
Preprint
Knowing the characteristics of suitable environments for precipitation of oil prone source rocks facilitates oil explorations and leads to development of oil fields. The current study investigates the organic matter properties and sedimentary environment conditions of the Garau Formation in various outcrop sections in Lurestan province from southwest of Iran (High Zagros) with using elemental analysis, visual kerogen analysis and Rock-Eval pyrolysis data. The geochemistry parameters indicate that the Garau Formation is an excellent oil prone source rock and composed of kerogen type I and II. The oxygen index (OI) is very low which reveals that organic matter deposited in an anoxic sedimentary environment and suitable for the preservation of organic matter and hydrocarbon generation. The visual analysis of isolated kerogens from source rock samples indicates the abundance of dark amorphous organic matter (AOM) with small amounts of phytoclasts and pyrite with no palynomorphs. Sedimentation seems to have occurred in deep and reduced parts of a carbonate basin during a rapid transgression. In addition, due to the effect of thermal maturation, the color of amorphous organic matter has darkened. The elemental analysis and Van-Krevelen diagram was shown that the type of organic matter and reveals the thermal maturity of the oil window. Moreover, amount of pyritic sulfur (Sp) and organic sulfur (So) contents have been calculated, and it was reveals that the high content of organic sulfur is a key element in the structure of organic matter.
... When the H/C ratio is less than 0,5, the residual kerogens are capable of generating only gas. Walters (2006). LOVECCHIO, J.P. (2011) phytoplankton. ...
Thesis
The present is a basin screening study for the main Palaeozoic basins in South America. The objective is to review and characterize the main source rocks of the Paleozoic basins of South America and highlight the possible potentiality for unconventional hydrocarbons exploration (shale oil / shale gas). The reviewed basins are shown on Fig. 1 and can be classified, considering their geotectonic evolution throughout the Paleozoic era as intracratonic or pericratonic basins. The intracratonic basins (Solimões, Amazonas, Parnaíba, Paraná, eastern Chaco-Paraná) were developed on continental crust. Subsidence started in the Early Paleozoic and during the rest of the Paleozoic they acted mainly as sag basins. The pericratonic basins (Western Chaco-Paraná, Chaco, Beni, Madre de Dios, Ucayali & Marañón) were developed on the Western edge of Gondwana during the Paleozoic, they formed together a broad foreland basin during the Middle Paleozoic (mainly in the Devonian) and afterwards the broad basin became more compartimentalized. The main revied source rocks were identified in the Silurian, Devonian and Permian systems. From all identified source rocks, a group of eight source rocks was selected as potential shale-oil / shale-gas targets for future exploration. These chosen source rocks fullfill the cut-offs of source rock quality established in this study (kerogen type II, TOC > 2%, maturities of 0,5-1,1%Ro for shale-oil and 1,1-3% for shale gas). These source rocks and their main characteristics are listed in the following Table. Pitinga Fm (Amazonas basin), Silurian (Llandoverian-Wenlockian), Kerogen type II, Avg TOC 2 %, Avg thickness 60 m, Maturity: 0.6-2 % Ro Cordobés Fm (Chaco-Paraná basin), Devonian (Pragian-Emsian), Kerogen type I/II, Avg TOC 2 %, Avg thickness 25 m, Maturity: 0.55-? % Ro Tomachi Fm (Madre de Dios basin), Devonian (Eiffelian-Tournaisian), Kerogen type I/II, Avg TOC 3.5 %, Avg thickness 200 m, Maturity: 0.5-1.2 % Ro Jandiatuba Fm (Solimoes basin), Devonian (Frasnian-Tournaisian), Kerogen type II, Avg TOC 4 %, Avg thickness 50 m, Maturity: 0.8-1.5 % Ro Barreirinha Fm (Amazonas basin), Devonian (Late Frasnian-Famennian), Kerogen type II, Avg TOC 3-8 %, Avg thickness 60 m, Maturity: 0.65-1.4 % Ro Pimenteiras Fm (Parnaiba basin), Devonian (Givetian-Frasnian), Kerogen type II/III, Avg TOC 1.5-2 %, Avg thickness 30 m, Maturity: 0.5-1.5% Ro Irati Fm (Paraná basin), Permian (Late Artinskian), Kerogen type I/I, Avg TOC 2 %, Avg thickness 40 m, Maturity: 0.44-2.38% Ro Ene Fm (Ucayali and Marañon basins), Permian (Asselian-Kungurian), Kerogen type II/I, Avg TOC 2-5 %, Avg thickness 70 m, Maturity: 0.42-1.5% Ro
Book
This book focuses on the use of nanoemulsion in enhanced oil recovery, along with a brief information about the emulsion and its types and different physico-chemical properties used to analyse the efficiency of the emulsions and nanoemulsions. The author discussed about the nanoemulsion, classification of emulsions and nanoemulsion and use of nanoemulsions in petroleum industry. A special attention has been laid on nanoemulsion and its advantages over commercial product, physico-chemical properties like emulsification, interfacial tension and wettability alteration study as a screening criteria for application in EOR.
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The need for a proper description of reservoir rocks and reservoir fluids for reservoir appraisal and exploration cannot be over-emphasized. This includes reservoir characterization, reservoir geophysics, reservoir rock description, reservoir geo-mechanics, and petroleum geo-statics. However, of equal importance are the changes that the rock properties undergo over time. It is logical to expect that the current behavior of any particle of matter be controlled by its origin of formation and previous history. In previous chapters, special cases of reservoirs, such as unconventional oil and gas, basement reservoirs have been discussed. For conventional reservoirs, the challenge is to solve governing equations with as few assumptions as possible, including linearization. In this chapter, various methods are presented for predicting reservoir performance, including cases of fluid memory, over-pressurized reservoirs, gas reservoirs, and others.
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Experiments were conducted to distinguish oil cracking in reservoir rock versus source rock. Oil and source rock samples were heated in pressure vessels at 380 °C for 72 hours, which resulted in oil cracking to gas and pyrobitumen with some residual liquid. The oil samples were heated with different minerals (fine-grained quartz, calcium carbonate, montmorillonite, kaolinite and illite) employing different ratios of the oil to the mineral in each case. Heating oil with quartz or calcium carbonate was used to simulate oil cracking in reservoirs, while heating oil with clay minerals was used to simulate oil cracking within source rocks. Based on the experiments, oil cracking in reservoirs versus source rocks can be differentiated by relative concentrations of the prominent C7 hydrocarbons: n-heptane, methylcyclohexane and methylbenzene (toluene) in the liquid products. The light hydrocarbon distribution in the final cracking products is affected by the “matrix effect” from clay minerals and the surrounding medium in reservoirs and source rocks during oil cracking. No relationship between the types of marine source rock or total organic content (TOC) and the distribution of light liquid hydrocarbons generated by catalysis on clay minerals at high temperature was observed. Future studies are needed to evaluate different types of source rock (e.g., terrigenous versus marine, clastic versus calcareous), and the relationship between light liquid hydrocarbon yield and the quantity of each clay mineral.
Book
Full-text available
Shale gas has the potential to transform the U.S. energy-based economy in the electricity, transportation, and chemical sectors. U.S. success can be expected to translate to Europe and other parts of the world. Shale gas production is uniquely enabled by hydraulic fracturing, a technique that has come under heavy scrutiny for its potential to cause environmental damage. In this book, Vikram Rao addresses the issues surrounding shale gas in a balanced fashion. The book is intended to inform both sides of the fracturing debate, where currently rhetoric is overtaking understanding. Tailored for a nontechnical audience—with technical chemistry and geology information couched in sidebars—the book culminates in suggestions for research and guidance for policymaking.
Chapter
Integrated studies of seismic stratigraphy and seismo-tectonics provide a highly effective and indispensable tool used in petroleum exploration. The unified approach helps comprehend basin evolution & evaluation, organises ‘tectono-stratigraphic’ framework for building basin petroleum system modelling (BPSM) and generate and evaluate potential plays and prospects for exploratory drilling. Petroleum system modelling deals with assessing potential of each component required for hydrocarbon discovery, i.e. the source, reservoir, migration, trapping, accumulation and preservation and helps estimate hydrocarbon resource potential for virgin / underexplored basins. The modelling study provides better insight to the hydrocarbon accumulation system and often is used to find new and more hydrocarbon with less risk in matured petroliferous basins. It also incites new geologic play concepts leading to upgradation of prospects and prognosticated resources to re-strategize basin exploration policies. Utility of unified analysis of seismic stratigraphy and seismo-tectonics for basin evolution and hydrocarbon evaluation along with petroleum system modelling is described. The geologic, seismic and geochemical aspects of assessing hydrocarbon source quality and thermal maturity for generation is introduced. Prospect generation and appraisal, estimate of volumetric reserves and techno-economic analysis are highlighted. Since faults play major roles as conduits, seals, and leaks in hydrocarbon migration and accumulation, fault attributes analysis and fault seal integrity studies for traps are also included in the chapter.
Article
Changes in sulfur content and sulfur-isotope ratios with "thermal maturation" have been studied using Big Horn basin (Wyoming) Paleozoic oils as examples of "single source" oils which have attained different stages of maturity as a result of variations in thermal history. With increasing maturity, API°, GOR, S/N, ^dgrC13, and ^dgrS34 all increase, whereas percentage S and percentage N decrease. Except for the increase in ^dgrS34 and S/N, these changes generally are recognized as typical of the thermal-maturation process. Hydrogen sulfide produced in low concentrations by microbial sulfate reduction in shallow reservoirs varies in ^dgrS34 and generally does not appear to change ^dgrS34 of associated oil. Isotopically unrelated H2S and organic sulfur may remain for long times because of negligible reaction between H2S and oil at low temperatures and low H2S pressures. The major new conclusion from this study is that thermal maturation in high-temperature reservoirs (more than 80-120°C) with sulfate present may involve nonmicrobial sulfate reduction with a negligible isotopic fractionation, producing reduced sulfur species with nearly the same isotopic composition as the reservoir sulfate. In this case, sulfurization and desulfurization of oil compete in kinetically controlled processes resulting in isotopic exchange. The ^dgrS34 of H2S and organic sulfur in oils change toward that of reservoir sulfate. Exchange is faster for H2S than for oil. Initial oils with a homogeneous ^dgrS34 distribution with boiling point and compound type become heterogeneous; the lower boiling fractions approach reservoir s lfate values faster than high-boiling fractions. The large increase in S/N ratio with maturation is attributed to percent S being maintained at a significant level by competing sulfurization and desulfurization processes, whereas percent N continues to decrease. The mechanism for high-temperature sulfate reduction is proposed to be the reaction of H2S and SO4= to produce elemental sulfur and polysulfides, which react rapidly to oxidize and dehydrogenate organic compounds and distribute the sulfur between oil and H2S. High concentrations of H2S may accumulate in this case, and oils or condensates may develop abnormally high concentrations of thiols. H2S is a catalyst as well as a product of the reaction; the process, therefore, may be autocatalytic.
Article
It is now generally believed that most petroleum is generated at temperatures between 60 and 150°C, corresponding to depths of burial of 1,500 to 4,500 m. At these depths shale source rocks have lost most of their water and practically all their permeability. If a good source rock still contains 500 ppm hydrocarbon, it probably has expelled a similar amount. If such a rock was subjected to a porosity loss of 10 percent during the time that it gave up 500 ppm by weight, the ratio of hydrocarbons to hydrocarbons plus liquid is 12,000 ppm, or 1.2 percent by volume of the liquid. There is no possibility of dissolving this much oil in water, even with the aid of solubilizers. Much of the shale surface may be wetted by oil, so that the saturation at which oil will flow as a continuous phase may be less than 10 percent. Furthermore, much of the water in the pores is structured and may behave like a solid. For fluid flow it might be considered as part of the solid matrix, and oil then would form a large fraction of the pore liquid. The relative permeability of the shale to oil then would become greater than to water. As compaction of the source rocks proceeds, shales might expel oil preferentially to water.