ME 463
Petroleum Engineering
Petroleum
Petroleum Formation
Petroleum Migration
Petroleum Accumulation
What is petroleum
Petroleum is a mineral substance composed of hydrocarbons and
produced from the natural accumulations of organic matter of a faunal
and/or floral provenance.
Petroleum is a gaseous, liquid or semisolid substance, present in the
pore space of porous rocks, referred to as reservoir rocks.
Gases:
Liquids:
Solids:
Visco-plastic solids:
Methane, ethane, propane, butane + others
Oil, Crude oil
Refined to derive petroleum products such as
gasoline, diesel fuel.
Coal, Kerogen, Gas hydrates (ices of gas)
Tar
The Conversion of Organic Matter to Petroleum
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When an organism (plant or animal) dies, organic matter is buried
and remains buried under anoxic conditions for 100-400 millions
years.
Over the years, layers of silt, sand and other sediments settled over
the buried organic matter resulting increase of pressure and
temperature.
The organic matter in sediments, subjected to increased temperature
and pressure is converted into petroleum hydrocarbons.
Not all of the organic carbon (OC) in sedimentary rocks converted into
petroleum HC. A portion of the Total Organic Carbon (TOC) consists of
Kerogen. The composition of the organic matter strongly
influences whether the organic matter can produce coal, oil or gas.
Basic components of organic matter in sediments • PROTEINS •
CARBOHYDRATES • LIPIDS (Fats) • LIGNIN
All of these + Time + Temperature + Pressure = KEROGEN
The Conversion of Organic Matter to Petroleum
▪ Organic matter was buried before decomposition takes place. The lack
of oxygen (anoxic conditions) is an essential factor since it prevents
the decomposition of the organic matter which is then transformed
to oil.
▪ The only elements essential to the transformation of organic matter
(OM) into petroleum are hydrogen and carbon. Thus the nitrogen
and oxygen contained in the OM must somehow be removed while at
the same time preserving the hydrogen-rich organic residue. The
amount of organic matter in the source rock is important as 75% of
organic matter is converted in to petroleum.
▪ Once the organic material is buried within the sea floor, transformation
begins. Tissot (1977) defined three major consecutive phases in the
evolution of organic matter in response to burial:
▪ Diagenesis
▪ Catagenesis
▪ Metagenesis
Diagenesis
o This phase occurs in the shallow subsurface at near normal
temperatures and pressures. This is a process of compaction under
mild conditions of temperature and pressure. It takes place at depths
from shallow to perhaps as deep as 1,000 meters and at temperatures
ranging from near normal to less than 60oC.
o It includes both biogenic decay, aided by bacteria, and abiogenic
reactions. When organic aquatic sediments (proteins, lipids,
carbohydrates) are deposited, they are very saturated with water and
rich in minerals.
o Through chemical reaction, compaction, and microbial action during
burial, water is forced out and proteins and carbohydrates break
down to form new structures that comprise a waxy material known as
“kerogen” and a black tar like substance called “bitumen”.
o The net result of the diagenesis of organic matter is the reduction of its
oxygen content, leaving the hydrogen : carbon ratio largely
unaltered.
o All of this occurs within the first several hundred meters of burial.
Catagenesis
o This phase occurs in the deeper subsurface as burial continues and
temperature and pressure increase. As temperatures and pressures
increase (deeper burial) the process of catagenesis begins, which is the
thermal degradation of kerogen to form hydrocarbon chains.
o Importantly, the process of catagenesis is catalyzed by the minerals that
are deposited and persist through marine diagenesis.
o The conditions of catagenesis determine the product, such that higher
temperature and pressure lead to more complete “cracking” of the kerogen
and progressively lighter and smaller hydrocarbons. The Catagenesis
phase becomes dominant in the deeper subsurface as burial (1,000 - 6,000
m), heating (60 - 175oC), and deposition continues.
o Petroleum formation, then, requires a specific window of conditions; too hot
and the product will favor natural gas (small hydrocarbons), but too cold
and the plankton will remain trapped as kerogen.
o Petroleum is released from kerogen during catagenesis—first oil and later
gas. The hydrogen: carbon ratio declines, with no significant change in
the oxygen:carbon ratio.
Metagenesis
o This third phase occurs at even higher temperatures and pressures
verging on metamorphism.
o The last hydrocarbons, generally only methane, are expelled.
o The hydrogen : carbon ratio declines until only carbon is left in the
form of graphite.
o Porosity and permeability are now negligible.
Petroleum Formation Process Flow
Maturation of Kerogen
▪ On average, the composition of organic matter in sediment is as
follows:
▪ 40% Proteins
▪ 40% Carbohydrates
▪ 10% Lipids
▪ 10% Lignin
▪ These materials are supplied by: Trees, Herbaceous plants, Fungi,
Algae, Protozoa, Bacteria, and Faeces
▪ All of these + Time + Temperature + Pressure = KEROGEN
Kerogen Classification
• The extreme types of disseminated organic matter correspond to the
class of Kerogen formed. It can be classified based on the ratios of H/C
and O/C as follows:.
• Type I kerogen
• Type II kerogen
• Type III kerogen
• Type IV kerogen
Maturation of Kerogen
Type I Kerogen
▪ Rich in lipids particularly aliphatic chains with derivates of oils, fats, &
Waxes
▪ Derived from algae present in fresh water lakes & lagoons.
▪ High proportion of H:C ratio (1.6- 1.8) and low O:C ratio (0.06)
▪ Oil prone; yields high (up to 80%).
Type II Kerogen
▪ Most prolific global source rocks
▪ Rich in lipid
▪ It is an admixture of
▪ Marine material - phytoplanktons , zooplanktons, algae
▪ Terrestrial (plant) material- spores, pollen, and cuticle
▪ Intermediate H:C (about 1.3) & intermediate O:C (0.1)
▪ Oil & gas prone; yields 40—60%
Maturation of Kerogen
Type III Kerogen
▪ Rich in lignin derived from woody
land plant debris
▪ The debris occurs abundantly in
coals
▪ Low H:C ratio (< 1.0) & high O:C
ratio (0.15)
▪ Low yield for oil but gas prone
▪ Low in aliphatic compounds but
rich in aromatic compounds
Type IV Kerogen
▪ High in carbon and very low in
hydrogen
▪ Often termed “dead-carbon”
▪ No effective potential to generate
petroleum
Hydrogen Index: mg of HC/g
TOC
Oxygen Index: mg of CO2/g TOC
Maturity Parameter of Kerogen
▪ Temperature, is the first most important factor for thermal
maturation and determines the resultant hydrocarbon type.
▪ Time is the second most important factor for thermal maturation.
▪ Maturation Indicators are important:
• To recognize and evaluate potential source rocks for oil and gas by
measuring their contents in organic carbon and their thermal
maturities
• To correlate oil types with probable source beds through their
geochemical characteristics and the optical properties of kerogen in
the source beds
• To determine the time of hydrocarbon generation, migration and
accumulation
• To estimate the volumes of hydrocarbons generated and thus to
assess possible reserves and losses of hydrocarbons in the system.
Maturity Parameter of Kerogen
▪ Petroleum geologist use several maturation indicators to
evaluate potential hydrocarbon accumulations.
▪ SCI (Spore Coloration Index) and TAI (Thermal Alteration Index) are
maturation indicators that measure the color of palynomorphs. Color changes as
a function of maturity.
▪ Vitrinite Reflectance (Ro) is a measure of the percentage of incident light
reflected from the surface of vitrinite particles in a sedimentary rock as referred
%Ro.
Formation of Petroleum from Organic Matter
Migration of Petroleum Hydrocarbons
Preconditions for Petroleum Accumulation
As a general rule, the origin of petroleum is never in the
reservoir accumulation from which it is produced. Instead,
petroleums have experienced a long series of processes prior to
accumulation in the reservoir.
Petroleum accumulation forms in sedimentary basins and can
be discovered by exploration, if the following geological
conditions are met:
▪ Occurrence of Source Rocks which generate petroleum's
under proper subsurface temperature conditions.
▪ Sediment Compaction leading to expulsion of petroleum from
the source and into the reservoir rocks (primary migration).
▪ Occurrence of Reservoir rocks of sufficient porosity and
permeability allowing flow of petroleum through the pore
system (secondary migration).
Preconditions for Petroleum Accumulation
▪ Structural configurations of sedimentary strata whereby the
reservoir rocks form traps, i.e. closed containers in the
subsurface for the accumulation of petroleum.
▪ Traps are sealed above by impermeable sediment layers (cap
rocks) in order to keep petroleum accumulations in place.
▪ Correct timing with respect to the sequence by which the
processes of petroleum generation/migration and trap formation
have occurred during the history of a sedimentary basin.
▪ Favorable conditions for the preservation of petroleum
accumulation during extended periods of geologic time, i.e.
absence of destructive, such as the fracturing of cap rocks
leading to dissipation of petroleum accumulations, or severe
heating resulting in the cracking of oil into gas.
Fig. 1. Main geological conditions and geochemical processes required
for the formation of petroleum accumulations in sedimentary basins: 1)
petroleum generation in source rocks; 2) primary migration of
petroleum; 3) secondary migration of petroleum; 4) accumulation of
petroleum in a reservoir trap; 5) seepage of petroleum at the Earth’s
surface as a consequence of a fractured cap rock.
Petroleum Migration Evidence
▪ Oil and gas do not generally originate in the rocks in which
they are found. Oil and gas migrate into reservoir rocks at
depth some time after burial and HC generation:
▪ Oil and gas is often found in solution pores and fractures that
must have formed after the burial and lithification of the host
rock (i.e., during Diagenesis).
▪ Oil and gas are trapped in the highest structural culmination,
or stratigraphic pinch out of a permeable rock unit, which
implies upward and lateral migration.
▪ Oil, gas and water occur as stratified bodies according to their
densities in porous and permeable reservoir rock. This implies
they were free to migrate laterally and vertically.
Petroleum Source Rocks
Petroleum source rocks/beds are fine grained, clay-rich
siliclastic rocks (mudstones, shales) or dark coloured carbonate
rocks (limestones, marlstones), which have generated and
effectively expelled hydrocarbons.
A petroleum source rock is characterized by three essential
conditions:
▪ It must have a sufficient content of finely dispersed
organic matter of biological origin;
▪ This organic matter must be of a specific composition, i.e.
hydrogen-rich; and
▪ The source rock must be buried at certain depths and
subjected to proper subsurface temperatures in order to
initiate the process of petroleum generation by the
thermal degradation of kerogen.
• Based on empirical evidence, minimum concentration levels of
1.5% and 0.5% total organic carbon (TOC) in source rocks of
siliclastic and carbonate lithologies respectively.
• This minimum concentration of organic carbon in source rocks
is controlled by the relationship between the quantity of
petroleum generated and the internal storage capacity of the
rocks in terms of their porosity. If too little organic matter is
present, the small quantities of petroleum generated will not
exceed the storage capacity of the rock, i.e. no petroleum
expulsion will take place.
• Most source rocks which have effectively generated and
expelled commercial quantities of petroleum have TOC
concentrations in the order of 2-10%.
Table: Organic
Richness of Source
Rock
Fig. 2. Petroleum source
rocks of siliclastic lithologies
often
display
a
well
expressed fine stratification
and lamination:
A, seen in an outcrop view
B, seen in a thin section
under a microscope
Petroleum Migration Classification
Primary Migration:
▪ Mature hydrocarbons first have to migrate out of the source rock
which is in general a fine-grained rock having low permeability.
▪ During burial, this rock gets compacted and its interstitial fluid
become overpressured with respect to surrounding rocks that have
higher permeabilities and from which fluids can migrate with
greater ease upwards.
▪ Therefore, a fluid pressure gradient develops between the source
rock and the surrounding, more permeable rocks called reservoir
rocks.
▪ This causes the fluids - the water and the hydrocarbons - to migrate
along the pressure gradient, usually upwards, although a
downward migration is possible. This process is called primary
migration, and it generally takes place across the stratification.
Primary Migration Mechanisms
1. Migration by Diffusion. Because of differing concentrations of the fluids
in the source rock and the surrounding rock there is a tendency to diffuse.
2. Migration by molecular Saturation: Saturated hydrocarbons are
preferentially expelled, while NSO compounds that is unsaturated remain
preferentially within the pore space of the source rock.
3. Migration along microfractures in the source rock. During
compaction the fluid pressures in the source rock may become so large that
spontaneous “hydrofracing” occurs.
4. Oil-phase migration. OM in the source rock provides a continuous oil-wet
migration path along which the hydrocarbons diffuse along pressure and
concentration gradient.
5. An additional mechanism to provide pressure for the expulsion of petroleum
is due to some volume expansion with conversion of solid labile kerogen
into liquid and gaseous hydrocarbons plus residual inert kerogen.
Secondary Migration
Primary Mechanism
▪ As soon as the petroleum has crossed the source/reservoir bed contact
and entered the reservoir rock, quite different physical
conditions prevail.
▪ Significantly higher porosities, permeabilities and pore sizes
allow for the formation of oil droplets and small continuous oil
stringers, i.e. a network of interconnected oil-filled pores.
▪ Their movement occurs as a discrete oil phase controlled by the
interplay of driving and counteracting resisting forces
(England et al., 1987). The main driving force is buoyancy which is
due to the density contrast between petroleum hydrocarbons and
water. Oil densities can vary between 0.5 and 1.0 g/cm3) natural gas
densities are much less than 0.5 g/cm3 while pore waters have
densities varying between 1.00 and 1.20 g/cm3 depending on their
salinity.
Secondary Migration
▪ A second driving mechanism can be hydrodynamic forces. If pore waters
are flowing actively, the passage of oil droplets through bottle necks in the
pores is facilitated. The resisting force of capillary pressures counteracts
these driving forces. If a rock has very narrow pore throats, capillary
displacement pressures get so high that they cannot be exceeded by the
buoyancy of the oil stringer or gas bubble, and entrapment occurs.
▪ Distances and directions of secondary petroleum migration vary
depending on the type and configuration of the sedimentary basin and the
spatial relationships between interbedded sandstones and shales, as well as
the abundance of fractures and faults.
▪ Short migration distances occur in sedimentary sequences with
intensive interbedding of source rock-type shales and reservoir sandstones.
Lateral migration distances of kilometres or tens of kilometres are common
(the Eastern Venezuela Basin), where longest migration distance known
worldwide is the Western Canada Basin (1000 km).
▪ A statistical study of hundreds of oil fields from locations worldwide has
shown that about 60% of them migrated vertically from source to reservoir,
while about 40% involved considerable lateral movement
Direction of fluid migration on the flank of
an anticline into the highest possible place
of the reservoir layer
Direction of fluid migration into
stratigraphic - or better: combined
- traps
Fluid
migration
in
an
interbedded
sand/shale
sequence
Petroleum Hydrocarbon Accumulation
▪ The updip migration of
petroleum along inclined
carrier beds continues as
long as it does not
encounter
structural
configurations where the
reservoir strata form traps.
▪ Traps are containers in the
subsurface where petroleum
accumulates.
▪ The most common traps are culminations of folds called
anticlines.
▪ As petroleum is lighter than water due to buoyancy within its
environment of water-filled pore spaces the subsurface
container is filled with petroleum from the top downwards.
▪ Petroleum displaces the pore water there, starting from
the top of the culmination and expanding into the flanks of
the anticline.
▪ The contact between the oil-saturated and the watersaturated pore spaces is always sharp and, in most cases,
horizontal.
▪ Provided that the incoming petroleum has an adequate
gas/oil ratio and favorable pressure conditions, gas
desorption will occur and a free gas phase will separate from
the oil which accumulates in the apex of the structure due to
the highest buoyancy forming a so-called gas cap.
▪ The gas-oil contact is equally sharp and horizontal as oilwater contact
▪ Most petroleum fields consist of an oil zone, the thickness of
which is referred to as the oil leg or oil column, overlain by a
gas cap. In these cases, the gas is called associated gas.
▪ Non-associated gas denotes an accumulation of gas without
an oil leg, i.e. a natural gas field.
▪ There are also oil fields without gas caps. In these cases, the
solubility of gas in oil under the prevailing pressure regime is
not exceeded, i.e. the gas remains dissolved in oil
Petroleum System
▪ Of the total amount of petroleum generated in the source rocks at great
depths in hypothetical sedimentary basin, 75% is expelled in the course of
primary migration into nearby high- porosity/permeability carrier beds.
▪ During secondary migration, about 50% of the petroleum which has
entered the carrier beds remains in the form of impregnations.
▪ About 40% has, at an earlier stage in the history of this sedimentary basin,
accumulated in reservoir traps, while the remaining 10% is on its
secondary migration route bypassing all traps and eventually leaking out at
the Earth’s surface. This process is called petroleum seepage.
▪ About 25% of the original petroleum accumulated gets lost by cap rock
leakage occurring at a slow rate over long periods of geologic time. Of the
remaining petroleum, another 25% gets lost in the course of chemical,
physico-chemical and bacterial processes.
▪ In summary, only about 10% of the petroleum generated in the source
rocks of this hypothetical basin can be discovered by exploration and
produced for economic usage. For example: the La Luna-Misoa petroleum
system of Venezuela and the Arabian/Iranian Basin in the Middle East.
More common cases are even less such as in the order of 2-5%, such as several
petroliferous basins in the USA and Australia.
Petroleum System
Petroleum Alteration
Those petroleum accumulations which are discovered and produced by the oil
industry have survived extended periods of geologic time. During these periods,
the physical and chemical conditions of the accumulation in the reservoir can
have changed. Since petroleum is thermodynamically metastable under
geological conditions, it responds to these changing conditions by adjusting its
composition, i.e. the original composition is altered. Geological processes which
lead to compositional alteration, and their effects on oil density, expressed in
degrees according to the rule formulated by the API (American Petroleum
Institute), are schematically illustrated in the following fig.
Changes in petroleum composition due to Biodegradation
In areas where there are high hydraulic head conditions (groundwater
recharge areas at high altitudes), meteoric waters penetrate along high
porosity/high permeability strata deeply into sedimentary basins. They
are oxygenated and carry bacteria. Wherever these waters flow past
petroleum accumulations, they cause biodegradation and water
washing effects. Compounds which have higher solubilities in water,
such as benzene and toluene, are preferentially removed. Several
species of bacteria degrade and consume petroleum hydrocarbons in a
very specific way. Depending on favorable microbial growth conditions,
the molecular composition of reservoir petroleum is altered to an
increasing extent. With increasing degrees of biodegradation, the
following effects are observed:
• Decreasing concentrations of wet gas and gasoline in favor of
kerosene-range components
• Decreasing wax contents due to removal of long- chain n-alkanes.
• Decreasing gas/oil-ratios (GOR).
• Decreasing API gravities (increasing densities).
• Increasing concentrations of asphaltenes.
• Increasing contents of sulphur and nitrogen.
• Increasing viscosities.
Changes in petroleum composition due to thermal alteration
Petroleums like kerogen react sensitively to increasing thermal
conditions. Reservoir oils which get buried deeper and exposed to higher
thermal regimes undergo compositional changes with maturation. The
overall trend concerns a progressive increase in the proportion of
low molecular weight components at the expense of their heavier
counterparts. This compositional evolution with rising subsurface
temperatures is mainly achieved by cracking reactions. Mediumgravity oils are converted into light oils and condensates and ultimately
into natural gas accumulations
Gas Hydrates
▪
▪
Very special cases of gas accumulations occur in the form of so-called gas
hydrates. These are solid, ice-like compounds whereby water molecules are
arranged in crystal lattices forming cages. Methane molecules are
arranged inside these cages.
1 m3 of gas hydrate contains 164 m3 of methane.
▪ Gas hydrates form in high pressure, low temperature environments
where sufficient gas and water are present. The hydrate formation
requirements restrict the occurrence of natural gas hydrates to two types of
geologic locations:
▪ under permafrost in the polar continental shelves and
▪ in sediment beneath the ocean floor.
▪ The blue sections in the generic curves illustrate regions in
permafrost and oceanic sediment where the pressure and
temperature conditions and the concentration of methane gas
are within the hydrate formation and stability zone. These
curves are based on pressure-temperature phase equilibrium data
▪ There is a general consensus that the origin of the methane
concentrated in naturally occurring hydrates is either microbial
(generated by anaerobic decomposition of organic matter) or
thermogenic (generated by thermal decomposition of organic
matter).
▪ Predictions are that gas hydrates will indeed become an
important energy resource in the future when conventional oil
and gas resources have much declined. This assumption is based on
estimates of enormous quantities of gas hydrates hidden under
the deep ocean floors and in arctic permafrost regions. It is estimated
that more energy resources are present on Earth in the form of
methane hydrates, than exist from the sum of all of the presently
known fossil fuel resources (oil, gas, and coal).
▪ Optimistic estimates claim that there is twice as much methane
available from gas hydrates
▪ Two of the main challenges to utilizing methane hydrates as an
energy resource are recovery and production. In order to exploit
the large volumes of trapped gas within gas hydrates, hydratebearing sediment must first be made accessible by drilling deep
wells into the oceanic and permafrost reservoirs. Following drilling,
methane production can be accomplished by thermal stimulation,
depressurization, or inhibitor injection (injection of inhibitors
such as methanol to destabilize the hydrate). After hydrate
dissociation, the released gas must be isolated and collected.
▪ To date, large-scale production of methane from gas hydrates
has not been demonstrated due to economic and safety issues.
In order for the potential of methane hydrates to be fully recognized,
improvements in hydrate technology must be achieved. Hydrate
research groups in the United States and Japan expect to have
made these advances by 2016.