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Organic matter accumulation
1. Marine phytoplankton are the main source of the
organic matter in the marine sediments.
2. Phytobenthos are the main source of organic matter in
shallow water (provided sufficient light for
photosynthesis).
3. Bacteria also provide additional source of organic matter
in both cases.
4. Pollen, spores and other plant debris are also important
organic matter source near shore area and deltas.
5. Organic matter is greatest in areas of primary
productivity.
6. High productivity of organic matter means: Less oxygen
(Eh low) + formation of H2S (sulfates reducing bacteria).
7. Less oxygen because decaying organic matter (by
aerobic respiration): CO2 produced.
8. H2S is produced due to anaerobic respiration by bacteria
in minimum oxygen concentration zone.
9. Formation of H2S and less oxygen reduce the rate of
decomposition of organic matter.
10. Organic matter dissolves and/or adsorbed on the
surface of the minerals helps the organic matter to
stabilize.
I. Better protected against biological destruction.
II. Settles more rapidly in the water column.
11. Rate of deposition of mineral particles is inversely
proportional to (constant supply) of organic matter.
Diagenesis (Vitrinite reflection is from 0 – 0.5)
Early diagenesis
1. Aerobic micro-organism consumes free oxygen in upper
most layer of the sediments.
2. Anaerobic organisms in subsiding layer reduce sulfates
to consume oxygen.
3. Energy is provided by decomposition of organic matter
which in the process is converted into Carbon Dioxide,
Ammonia ad Water – Happens mostly in sandy and
muddy sand – most of organic matter is destroyed.
4. Eh decreases and pH increases slightly – H+ increases and
O2 (aq) decreases.
5. At the same time CaCO3 & SiO2 dissolve and re-
precipitates – Destruction of reservoir porosity and
permeability.
Diagenesis
1. The organic matter in sediments move towards
equilibrium.
2. Proteins and carbohydrates are destroyed by microbial
activity & in early diagenesis.
3. The constituents of all complex organic matter
destroyed e.g carbohydrates, lignin, cellulose and
protein starts to form new polycondensed structure –
precursor of kerogen.
4. If deposition of organic matter from plants is massive
compared to mineral contribution Peat and then brown
coal forms – however the most important hydrocarbon
formed so far is methane.
5. In addition to methane, CO2, H2O and some heavy
heteroatomic compounds are produced.
End of diagenesis
1. Organic matter is placed where extractable humic acid is
decreased to least amount.
2. Most of carboxyl groups are lost.
Kerogen is formed in Diagentic stage of evolution of
sediments. And most of the organic carbon is mostly
composed of it.
Catagenesis
1. Bedding causes lower bed to go deeper and deeper as
time passes and sedimentation of the upper bed slowly
build up to the level when lower beds are several kms
deep – Increase in Temperature and Pressure.
2. Temperature may range from 50 to 200 oC and Geostatic
pressure may range from 300 to 1000 or 1500 bars.
3. System goes out of equilibrium under these new
changes.
4. Inorganic changes: Water is expelled from the rocks,
Porosity and Permeability decreases; salinity increases –
sometimes reaches saturation.
5. Organic changes: Kerogen produces first liquid
petroleum +methane; then wet gas and condensate +
Methane.
End of Catagenesis
1. End of Catagenesis is where the disappearance of
aliphatic carbon chains in kerogen is completed &
Ordering of basic kerogen unit begins.
2. Vitrinite reflection is from 0.5 to 2.
3. All the changes to organic matter almost ends here so is
production of petroleum & only limited amount of
methane is produced.
Metagenesis & Metamorphism
1. This is the last stage of evolution of sediments –
Metagenesis i.e before metamorphism.
2. Temperature and Pressure are extreme and rocks may
be exposed to magma.
3. Mineral Changes: Clay mineral lose interlayer water and
crystallinity increase; iron oxides with water also loose
water (goethite to hematite); dissolution and
recrystallization occurs.
4. Organic matter is composed of Methane and carbon
residue only.
5. Residual kerogen is converted into graphite.
6. Vitrinite reflection is 2 to 4.
This page summarize Diagenesis, Catagenesis and
Metagenesis generally.
The Diagentic Pathway from Organisms to Geochemical Fossils and Kerogen.
Detailed diagenesis and kerogen formation
Bacteria degrades the macromolecules of the organic matter into monomers, which provides important source of energy to micro-
organisms. The residue from this becomes polycondensed forming large amount of brown material partly soluble in NaOH look
alike humic acid. With time and increase in burial depth the organic material becomes more insoluble due to a lot of
Polycondensation – loss of superficial hydrophilic functional group – this insoluble material is called Humin – Young sediment. In
ancient sediment insoluble matter is called kerogen.
In young sediments an important part of the humin can be hydrolyzed, however it decreases with depth and thus humin with other
insoluble material such as pollen and pores can be called as a precursor of kerogen as mentioned before. Humin and kerogen are
not the same and kerogen is from where petroleum is produced.
This whole process comes under diagenesis and is from BIOPOLYMERS to GEOPOLYMERS (Kerogen), via fractionation, partial
destruction and re-arrangement of the macromolecular structure. The 3 main steps are:
1. Biochemical degradation
2. Polycondensation
3. Insolubilization
Biochemical degradation
a) Microbial Activity
They can be bacteria, algae, and fungi – are in good number in sediments especially one deposited under moderately water depth.
They normally do consume organic matter for their energy. As depth increases the number of bacteria decreases rapidly.
Photosynthesis becomes impossible. Respiration occurs in oxygen available zones and fermentation in minimum oxygen zone.
Table II.2.1 provides relationship of amount of bacteria and their number. Protein and carbs are hydrolyzed into lesser monomers
– lipids and lignin are subjected to less degradation. Sometimes aerobic respiration may last till all organic compound is destroyed
– this situation is true for waterless environment and abundant amount of oxygen available. However in aquatic scenarios the
condition is different. Fine-grained sediments can act as a closed environment by blocking the water from entering the sediments
under it, this rapidly decrease the oxygen due to respiration until anaerobic respiration takes over. Sulfates are reduced along with
other hydroxides; redox potential (Eh) decrease below zero. In marine environment organic matter undergoes three types of zones;
The cycle of sulfates is shown in Fig. II. 2.2.
1. An Oxidation zone, where all free oxygen is utilized.
2. An anaerobic zone; Sulfates reduction zone, where all the oxygen is stripped from sulphates and other oxygen containing
compounds by Desulfovibrio. Thiobacillus re-oxidizes the hydrogen sulfide (H2S), establishing an equilibrium.
3. Anaerobic methane generation zone, when most of the sulphates are reduced and methane is produced by.
This cycle may not exist if there is no circulation of water (Black sea). In this type of situation O2 may not exist at the bottom of the
water, so Thiobacillus will not live there, hence large amount of H2S and even S itself is produced. Benthic life disappears. Diagenesis
followed by this type of environment may explain the reason for sulphur rich petroleum.
Low molecular weight by product of fermentation by anaerobic bacteria are the precursor of methane – final stage is methane
generation by reduction of CO2 or acetate by methane generating bacteria such as Methanobacteria. In marine environment this
process becomes prominent and boosted once all the sulphate are reduced. This is due to competition of hydrogen b/w
Methanobacteria & Desulfovibrio. Though Desulfovibrio win again Methanobacteria, however with time all sulphates are reduced
lack of sulphate cause Desulfovibrio to lose.
b) Free or hydrolysable organic compound
Macromolecules like protein and polysaccharides are degraded by micro-organism are broken down into simple sugars and amino
acids along with fatty acids and hydrocarbons in the young sediments – are not hydrolysable nor extractable by organic solvents
are considered as humic compounds and humin.
Among the free hydrolysable organic compounds is amino acids. Sugars and amino acids decreases as depth increases as shown in
Fig II. 2.3. This is due to 2 reason: i) consumption by bacteria or ii) they bound in insoluble organic fractions. With these changes
happening free molecules such as sterols, terpenes, etc., undergoes chemical changes in the upper sediments – increasing the
stability of these compounds.
Polycondensation
As mention before most organic part in the young sediments is neither hydrolysable nor extractable by organic solvents, hence
most hydrolysable compounds disappears with depth (bacteria), and the residue becomes new polymeric insoluble structure.
(Humic acid – insoluble in NaOH. Fulvic acid – soluble in acid.) Humic acid results from Polycondensation of organic residue by
microbial activity. The structure of humic acid formed on soil is different than that found on subaquatic sediments (page 82-83
about fulvic and humic acid).
Hydrocarbons are not affected by Polycondensation as they do not have those particular functional group required. However it’s
possible that some kinds of hydrocarbon may get attached to humic acid via weak bonds i.e adsorption or hydrogen bonding. The
abundance of humic and fulvic acids vary – depend on conditions of the environment.
Insolubilization
The decomposition and polycondensation results in macromolecules that accounts for more than 90 % of the total organic matter
in young sediments. With increase in depth humic and fulvic acid converts into insoluble humin. This Insolubilization is a part of
diagenesis. Also fulvic acid becomes lesser than humic acid, i.e their ratio decreases with depth. The organic material becomes
more condensed and becomes darker in color. This is due to increased polycondensation and loss of large amount of hydrophilic
functional group. The organic material becomes more insoluble i.e fulvic acid -> humic acid -> insoluble HUMIN -> KEROGEN.
Whatever path is take by organic matter the result is polycondensation – insoluble in NaOH humin.
Geochemical fossils
When diagenesis happens it results in kerogen, which results for the bulk organic matter, as well as some free molecules of lipids
include hydrocarbons and related compounds. These free molecules have been made by living organisms and get trapped in
sediments with no or only minor changes. These free molecules are called fossil molecules or geofossils recently known as
biomarkers.
a) Quantitative analysis
b) Qualitative analysis
Qualitative composition of hydrocarbon in recent sediments compared to crude oils, provides a confirmation of the fact that
petroleum hydrocarbons are mainly generated later and not directly inherited from organism. Hydrocarbons already present in
the recent sediments are of great importance to us, although they account for very less fraction, but they represent the heritage
and important information from which the crude oil was made and the biological environment of the deposition and degradation
of the organic matter. Hydrocarbons from kerogen that accounts for bulk provide limited information about where they came
from.
Fig. II. 3.4 A and B shows the little sometimes no change in biomarkers from which they are formed.
Summary of Geofossils/Biomarker: Molecules synthesize by a plant or an animal: the molecule being unchanged or minor alteration
to the carbon structure.
With increase in depth these geofossils suffer not only thermal degradation but also dilution with newly formed hydrocarbons from
kerogen degradation.
CPI – Carbon Preference Index
Ratio by weight of odd to even molecules. 𝐶𝑃𝐼 =1
2[
𝑆𝑢𝑚 𝑜𝑓 𝑜𝑑𝑑 𝑛𝑢𝑚𝑏𝑒𝑟 𝑜𝑓 𝐶𝑎𝑟𝑏𝑜𝑛
𝑆𝑢𝑚 𝑜𝑓 𝑒𝑣𝑒𝑛 𝑛𝑢𝑚𝑏𝑒𝑟 𝑜𝑓 𝐶𝑎𝑟𝑏𝑜𝑛]
Kerogen: Composition and classification
The term kerogen will be used here to designate the organic constituent of the sedimentary rocks that is neither soluble in aqueous
alkaline solvents nor in the common organic solvents. This is the most frequent acceptance of the term kerogen. There are various
ways to describe kerogen, sometimes depend on the authors, hence the fraction extractable with organic solvent is called bitumen
and the term kerogen does not include soluble bitumen.
As discussed before precursor of kerogen in young
sediments is also called humin. And the only difference
between them is the important hydrolysable fraction in
humin; this fraction disappears with depth. Kerogen is
the most important form of organic carbon on earth.
It is 1000 times more abundant than coal plus
petroleum in reservoirs and is 50 times more
abundant than bitumen and other dispersed
petroleum in non-reservoir rocks (Hunt, 1972). In
ancient non-reservoir rocks, e.g., shales or fine-
grained limestones, kerogen represents usually from
80 to 99% of the organic matter, the rest being
bitumen. Van Krevelen Diagram shows us important
approach towards H/C vs. O/C ratios for classification of
kerogen. Kerogens taken at various depths from the
same formation normally group along a curve, called
here an evolution path.
a) Type I
High initial H/C and low initial O/C ratio.
Much lipid material especially aliphatic chains.
Low polyaromatic nuclei and heteroatomic bonds
Under pyrolysis at 550 or 600 oC the kerogen
produces are very large yield of volatile and/or
extractable compounds than any other kerogen type.
Therefore high yield of oil
Paraffinic hydrocarbons are dominant over cyclic.
Derived principally from lacustrine algae
b) Type II
Important in many source rocks and oil
shales.
Relative high H/C ratio and low O/C ratio.
Polyaromatic nuclei; heteroatomic
ketones and carboxylic acid groups are more
important than in type I but lower than type
III.
Ester bonds are in rather abundance.
Sulfur is also present in hetrocycles.
Related to marine sediments where organic matter is derived from mixture of phytoplankton, zooplankton and
micro-organisms have deposited under marine reducing environment.
Yield is lower than in type I but still holds commercial shale oil.
c) Type III
Relatively low H/C ratio and high initial O/C ratio.
No ester group.
Few long chains, originated from higher plant waxes.
Some chains of medium length from vegetable fats.
Relatively less favorable for oil generation than type I and type II.
However may provide good gas source rock if buried at sufficient depth.
From (terrestrial) continental plants and contains much identifiable vegetal debris.
d) Type IV: kerogens contain mainly reworked organic debris and highly oxidized material of various origins. They are generally
considered to have essentially no hydrocarbon-source potential.
From Kerogen to Petroleum
As sedimentation and depth of burial increases
temperature and pressure increases and the
change in physical environment cause the
immature kerogen to out of equilibrium.
Rearrangement will take place to reach a higher
and much more stable degree of ordering. The
readjustment in of kerogen in this new physical
condition increase the elimination of functional
groups. Wide range of compounds are formed
including medium to low molecular weight
hydrocarbons, carbon dioxide, water, hydrogen
sulfides and etc. The resultant of all these things is
generation of petroleum (kerogen becoming
more stable in terms of equilibrium). The
characteristics of kerogen remains constant as
long as they are not buried deeply.
The rearrangement of kerogen happens in 3
stages: Diagenesis, Catagenesis and Metagenesis.
Diagenesis
Important decrease of O2, and C increases with
depth. Slight decrease in H/C and marked
decrease in O/C. A little HC generation have
occurred in source rock – large quantity of H2O &
CO2 produced in relation to elimination of O2.
Of Kerogen
Catagenesis
It’s the second stage of degradation of kerogen. Important decrease in hydrocarbon content and of H/C due to
generation and release of HC (Reduction in aliphatic bands – correlated to H/C lowering) and appearance of aromatic
CH bands. Long chains are removed and therefore increase in methyl groups. Catagenesis is main zone of oil generation
and also the beginning of cracking zone, producing wet gas proportional to methane.
Metagenesis
Here is very high geothermal gradient. Hydrogen elimination is now slow and residual kerogen usually consist of 2
carbons out of 3 atoms. Aliphatic and C=O vanishes. At this stage only dry gas is made.
Summary
- Biogenic gas: generated during
diagenesis.
- Thermal gas: generated during
Catagenesis.
- Thermal cracking gas: generated
during late part of Catagenesis and
Metagenesis.
- Non-hydrocarbon gases have
inorganic origin.
The figure on
left
summarize
the
formation of
petroleum
as a function
of depth of
source rock.
Temperature and pressure
Temperature: Increase in depth with burial is due to thermal gradient which is established due to the thermal energy
of the earth. Geothermal gradient vary place to place – depends on many factors: thickness of crust – closeness to the
surface, heat flux- thermal conductivity, fluid flux, heat dissipation of different lithologies, thermal conductivity of the
rocks and sub-surface water flow movement.
- Average geothermal gradient is 25 oC/km.
Hydrostatic pressure: pore fluid pressure under normal conditions
Petrostatic pressure (geo/lithostatic pressure): when pore fluid carry all the above rocks pressure.
Salinity increases as well with burial. Salinity gradient range from 70 mg/lm to 25 mg/lm and can go high as 300 g/l.
Compaction (clastic)
Compaction in sediments cause increase in bulk density and loss of porosity with increase in pressure, temperature
and time.
Depends on:
Material properties of a sediment
Liquid pore fluid can be expelled: compaction cause fluid flow through sedimentary rocks, it is considered an
important factor in migration. This thing is restricted in carbonates.
The transport of fluid happens due to permeability of a rock i.e interconnected pores.
𝑄 = −−𝑘 𝐴
𝜇
∆𝑃
𝐿 , Where Q volume per unit time (m3/s), k is permeability (m2), 𝝁 is the viscosity of the fluid and etc.
Darcy’s law is valid for laminar flow where inertial forces are negligible compared to viscous forces. During viscous flow
there is an interaction b/w liquid moving through the porous rock and the surface or the inner pore space of the rock.
For clastic sediments the loss of porosity initially is exponential however as depth increases it shows less decrease in
porosity. The initial loss is due to the increase in overburden pressure.
Compressive stress is the primary casue of
porosity reduction.
This relationship b/w specific water volume and increasing
depth of burial for different geothermal gradient pointed out
rising temperature is an additional casue for fluid migration in
the sub-surface.
Compaction (carbonates)
Carbonates rocks contains more than 50 % by weight of carbonate mineral and 50 % detrital minerals. Carbonates are
chemically more reactive than silicates and, hence. During compaction behave differently than clastic sediment. .
Chemical processes dominate the porosity and permeability reduction of carbonate, whereas physical and
mechanical processes for clastic rocks. . With increasing burial, recrystallization converts initially fine-grained
sediments into coarse-grained rocks. In this way. Finely disseminated bitumen and other foreign material such
as clay minerals become concentrated at grain boundaries and in intergranular spaces. This is an important step in
bitumen concentration in carbonate rocks.
Pore diameter and internal surface area
During sedimentary compaction and resulting porosity reduction there is also a marked decrease in pore diameter
especially in fine grained clastic sediments.
With increase in depth of burial in clastic pore becomes more and more flat.
General trend of increase in grain size also with increase in depth.
Possible Modes of Primary Migration
The transportation of petroleum can occur in different ways depending on the:
1. Separate oil and gas phase
2. Individual gas molecules or gas bubbles
3. Colloidal and miceller solution
4. True molecular solution
The 2 main driving forces are temperature and pressure – concentration gradient as well i.e is diffusion.
Interfacial tension is the boundary b/w 2 different fluid phases.
A large increase in pore pressure is sufficient (maybe) to overcome the capillary pressure or even to exceed the
mechanical strength of the rock and will/can also induce micro-cracks. The main cause of the pressure build-up are:
Thermal expansion of water.
Specific volume increase by organic matter by generation of gaseous and liquid hydrocarbons from kerogen.
Partial transfer of geostatic stress field from solid rock matrix to enclosed pore fluids, resulting in an overall increase
in pore pressure. This transfer is due to the conversion of solid kerogen into liquid or gaseous compounds.
Micro-fracture term is mostly associated to shale and tight carbonates deep buried, compacted, low permeability rocks.
Importance of clay dehydration and primary migration and Primary migration
Clay dehydration of smectite that can retain water in interlayer in the process of conversion to illites mainly under the
influence of temperature.
The development of a shale source rock requires smectite-containing organic mud and its subsequent alteration to
illites with deep burial and abnormal high fluid pressure may be caused by a volume increase of water desorbed from
smectite during the change to illite. Large scale water release due to dehydration and subsequent fluid movement in a
source rock-type sediment containing petroleum hydrocarbons may initiate primary migration. This water in clay that
is released have low density than free water and thus cause decrease in volume. Another thing is if there would be no
drainage system for the dehydrated water it would not initiate primary migration. At the end of the after studies by
various authors COMPACTION plays an important role in primary migration. It was frequently considered that
expandable clays initiate or are mainly/fully responsible for primary migration. Therefore there is no evident
relationship between primary migration and expandable clay minerals exist or can be concluded though it plays
important role where it can.
Clay minerals helps in better preservation of organic matter (expandable clays), and/or can act as catalyst. There are
few coincidences where release of water from clays helped.
The movement from source rock to reservoir rock is primary controlled by adsorption and desorption phenomenon
along the migration paths.
The chances for migration of
petroleum compounds
dissolved in and moved by
compaction water are probably
the greatest but sufficient
porosity for additional porosity
must exist for more compaction
yet deep buried enough to
produce hydrocarbons from
generation.
Summary for primary migration
There is no reason to assume that there is one mechanism for primary migration for all petroleum accumulations as
can be seen in the above diagram. The mechanism for primary migration changes depending on many factors such as
subsurface conditions mainly related to the depth of burial.
In shallow depths like 1000 to 1500 meters solution migration is seen to be more favored as compared to an oil-phase
migration. Solution migration also plays an important role at higher temperature but only to certain light hydrocarbons.
The dominant and most effective primary migration is hydrocarbon-phase migration, in form of oil phase and gas phase
after that and for gases diffusion.
Water flow is not needed as a driving force for migration and in fact hinders. Micro-fracture allows the release of
hydrocarbons from compacted, dense and relatively impermeable source rocks – shale and carbonates.
Secondary migration
Secondry migration is movement of petroleum through more permeable and porous carrier bed i.e reservoir rock. This
migration ends where a pool of petroleum forms but external disturbances such as tectonic movement can cause the
secondary migration to re-happen – still secondary migration and these events can be folding, faults and etc. this re
secondary migration is also known as tertiary migration.
Oil and gas pools form at the highest possible place where the secondary migration happens as petroleum generally
have less density than water in pore spaces and terminates when met with a less permeable rock layer. The main
driving force is buoyancy through the water saturated pore space.
The formation of oil and gas pool requires a decrease in the pore opening size to prevent multi-phase flow. Capillary
pressure generally opposes the movement. There is a difference b/w hydrodynamic, hydrostatic and no
flow/equilibrium conditions.
Water flows under hydrodynamic gradient modifies the buoyant rise of petroleum. The 3 parameters that controls the
secondary migration are:
1. Buoyant rise of oil and gas in water saturated rocks
2. Capillary pressures that determines the multi-phase flow
3. Hydrodynamic fluid flow.
In primary migration hydrocarbon phase flow is more important than solution migration and other, hence the in
secondary migration initial influence is due to the mode of primary migration.
When hydrocarbons leave the source rock (less porous, dense, fine grained), they enter the larger pores of reservoir
rock – large globules of oil/gas forms. Larger bodies of oil may move upwards due to buoyancy (oil stringer concept),
but tiny droplets may not due to more resistance to flow i.e higher surface energies/unit volume.
When oil droplet is in water it forms the compacted spherical shape and is influenced by an external water molecules
forces which makes it a bit compact. This forces b.w the water and the oil is called interfacial tension, and oil droplet
tend to assume the smallest possible surface area. This oil and water interfacial tension resist the distortion in the
shape of oil droplet and therefore retards the passage through the pore throat with diameter smaller than the size of
oil droplet. The force required to squeeze the oil droplet through the pore throat is called capillary pressure – to be
specific injection pressure. However under certain and right conditions buoyant forces could be high enough to
overcome the capillary pressure – that resist the secondary migration.
Buoyant forces increase with density difference b/w pore water and oil (𝜌𝑤 − 𝜌𝑜) and with increasing height of the oil
column. Oil trapped in reservoir rock under hydrostatic conditions represent an equilibrium b/w Buoyant forces and
capillary pressure in the seal rock.
The following equation shows the equilibrium conditions:
2𝛾 (1
𝑟𝑡−
1
𝑟𝑝) = 𝑧𝑜𝑔(𝜌𝑤 − 𝜌𝑜)
Where 𝛾 represent interfacial tension b/w water and oil in dyne/cm. rp is reservoir rock pore radius and rt is seal rock
pore radius.
The maximum height of an oil column which can be held in place is called critical height zc (replace zo).
𝑝 = 2𝛾 (1
𝑟) The equation shows that as excess pressure inside the oil globule increases as the radius of curvature
decreases – if buoyant force is greater enough to force the globule upward through pore throat and the globule must
be distorted. The pressure at the upper side of the globule is greater than that of lower end of the globule in the pore
throat. The capillary pressure opposes the buoyant force until the radius of curvature inside the distorted oil globule
are equal at the both ends (upper and lower ends). Once the globule have reached this stage it have moved halfway
through the throat and now buoyant force is dominant and the globule rises till it can doing this again and again until
the process ends ‘cause of seal rock is met. This phenomenon is shown on next page – fig. III. 4. 1.
This phenomenon can be also useful b/w source rock and resvoir rock. The equation shows the buoyant forces greater
than capillary pressure (ideal condition):
[𝐶𝑎𝑝𝑖𝑙𝑙𝑎𝑟𝑦 𝑝𝑟𝑒𝑠𝑠𝑢𝑟𝑒] 2𝛾 (1
𝑟𝑡−
1
𝑟𝑝) > 𝑧𝑜𝑔(𝜌𝑤 − 𝜌𝑜) [𝐵𝑢𝑜𝑦𝑎𝑛𝑡 𝑓𝑜𝑟𝑐𝑒]
Any flow of water depending on its direction can hinder or facilitate the secondary migration. Water flow is related to
hydrodynamic gradient is in upward direction it will favor buoyant force as can be seen by the diagram below.
Hydrodynamic gradient can of significant value for secondary migration, especially
for initial phase.
If this process happens in horizontal direction buoyant forces are negligible and
driving mechanism can only be due to water flow. We introduce the term
hydrodynamic gradient ‘m’, along the length ‘l’. as shown below.
As buoyancy now can be
neglected. Left hand side
represents the driving force
due to water flow.
This happens when stringer is inclined by angle Ѳ.
Note: Larger the size of oil globule, more the buoyant force can act on it and easier the migration. And distance covered
by secondary migration is 10 km to 100s kms.