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.

Analytical Procedures for Crude Oil Characterization.

Types of hydrocarbons

1) Alkanes

2) Geofossils

3) General info

Summary of Diagenesis, Metagenesis and Catagenesis.