1. Introduction to Petroleum Geology
Week 1 - 3
Course contents
Introduction To Petroleum Geology
Philosophy of the science of petroleum geology and relationship of petroleum geology with other branches of science.
Origin, Migration and Entrapment Of Hydrocarbons
Generation, migration and trapping mechanism of hydrocarbons.
Distribution of source rock over geologic time
LO: At the end of this lecture you will be able to understand the
philosophy & Technology of petroleum geology.

2. Introduction to Petroleum Geology
Subject covers geologic history of petroleum describing how petroleum is generated, migrated and accumulated in the sub-surface, characteristics of reservoir rocks and reservoir dynamics. Course also covers volumetric estimation of in-place hydrocarbon reserves. 
Course contents
Introduction To Petroleum Geology
Philosophy of the science of petroleum geology and relationship of petroleum geology with other branches of science.
Origin, Migration and Entrapment Of Hydrocarbons
Generation, migration and trapping mechanism of hydrocarbons.
Distribution of source rock over geologic time

3. Introduction to Petroleum
Geology
Lesson Outcomes
At the end of three weeks students
should be able understand the relation of petroleum
geology with other branches of science and also the
philosophy of petroleum geology.
should be able to understand how oil generates, migrates
and are trapped in the subsurface reservoirs.

4. Introduction to Petroleum
Geology

5. Petroleum Accumulates
Fundamentals of Petroleum Geology
Petroleum Accumulates
Petroleum Migrates
Petroleum Generates

6. Generation of Petroleum
Abiogenic Theory
The abiotic hypothesis is that the full suite of hydrocarbons found in petroleum can be generated in the mantle by abiogenic processes and these hydrocarbons can migrate out of the mantle into the crust until they escape to the surface or are trapped by impermeable strata, forming petroleum reservoirs.
2. Biogenic Theory: Petroleum is generated by effects of heat
and pressure on the organic remains of living organic matter.

7. Evidences in favour of Abiogenic Theory of Petroleum Generation
Meteorites and other extra-terrestrial bodies
have evidence of presence of methane
All the compounds of petroleum can be prepared by inorganic methods.
Thermodynamically methane can polymerize to
higher homologue at high temperature & pressure (mantle pressure & temperature).
Oil is found in granitic rocks of Vietnam

8. Problems of Abiogenic Theory of Petroleum Generation
Unpredictable.
Does not accept biomarkers.
Cannot explain optical rotation
Can not explain presence of porphyrins
Average carbon isotope composition of petroleum do not support

9. Evidences in favour of Organic Source
Both organic matter and petroleum are made of dominantly Carbon and Hydrogen. Further, both of them also have nitrogen.
2. Optical rotation of plane polarized light is seen in some organic substances and petroleum.
3. Presence of porphyrins in petroleum.
4. Presence of bio-markers in petroleum and
Odd-Even periodicity are well documented in petroleum paraffins and living organisms suggesting organic origin of petroleum.
Palynological studies have also suggested the organic origin of petroleum.

10. Limitations of Biogenic Theory of Petroleum Generation
It is not possible to generate long chain hydrocarbons by polymerization at low temperature–low pressure natural conditions because there is a constant Gf (Gibbs free energy change) increase for every increase in CH2 unit (2.2 kcal/mol).
The average concentration of hydrogen in proportion to carbon is less in organic matter than in petroleum
Presence of helium in some gases cannot be explained by organic theory

11. Source Rock in Petroleum Geology
Week 4 -9
Source Rock in Petroleum Geology
LO: At the end of you will appreciate what are the geochemical
parameters necessary to resolve the petroleum geology problems.
How these parameters are generated and what are the limitations
of each these parameters

12. Shale: Shale breaks into thin pieces with sharp edges
Shale: Shale breaks into thin pieces with sharp edges. It occurs in a wide range of colors that include: red, brown, green, gray, and black. It is the most common sedimentary rock and is found in sedimentary basins worldwide.
Marcellus Shale is a petroliferous black shale deposited during the Devonian in eastern USA. It is also explored as a shale gas resource. This photo shows an outcrop
of the Marcellus in New York State

13. Kimmeridge oil shale burns with Curling gasy flame well above the
Burning rock & noxious fumes
Distilling Oil & water from Kimmeridge
Oil Shale using gas lighter.

14. Source Rock Definition: A rock that is capable of generating
and expelling hydrocarbons to form
commercial oil/gas pools.
Characteristics:
1. Fine grained sedimentary rock with high
TOC and H/C deposited in an anoxic
environment.

15. Model of Petroleum (Wiehe, I.A., 1999)
Petroleum is a colloidal
solution of resins &
asphaltenes in aromatics
and saturates
A – Asphaltene (solute), R – Resins (dispersant)
a – Aromatics (solvent), s – Saturates (non-solvent)

16. Source Rock Parameters
TOC : Total Organic Carbon – Quantity
H/C : Hydrogen to Carbon (molar) – Quantity & Quality
Pyrolysis Data: S1, S2, Tmax, HI, OI, PI – Quantity, Maturity & Quality
Vitrinite reflectance (Vro) - Quality
Visual kerogen analysis - Quality
GC: Whole oil, C15+, Saturates - Quality
Py - GC - Quality
Biomarkers – Quality, Maturity
Isotopes – Quality, Maturity
TOC
H/C
Pyrolysis
Vro
Biomarker
Isotopes
Py-GC
GC, VKA

17. Sedimentary Organic Matter
∞ (py. productivity, bathymetry)
Refractory OM.
(Lignins & Lipids)
Living Organism
Death
Organic Matter (OM)
Leaching
Decomposition
Slow Decomposition
Labile
(Carbohydrates & Proteins)
(Bacterial colonization)
Deposit with
sediments
(Break down of cell material by
intracellular hydrolytic enzymes)
Lost organic
Matter

18. Sedimentary Organic Matter

19. Kerogen formation
Mechanism of kerogen formation from organic matter is still not
known. Earlier, it was believed that the kerogen is formed by
condensation reactions, the same process of coalification.
At present the theories of ‘Algaenan’ and ‘Millard condensation
to form melanoidin’ are in vogue.
Algaenan: Highly aliphatic, non-hydrolysable, insoluble macro-
molecular constituent have been identified in a number of
microalga cells and their selective preservation shown to play
major role in the formation of kerogen. All the algaenans so far
examined comprise a network of long polymethylenic chains,
except L race of Botryococcus braunii that contains C40
isoprenoid chains with lycophane type skeleton.
Melanoidin: Millard (1912) described the condensation
reaction of an amino group and a reducing compound. It is
believed that proteins and lipids react to form kerogen.

20. Kerogen Crum-Brown (1912) first used the term to describe OM of a
Scottish Shale that produced waxy oil upon distillation.
White (1915) & Trager (1924) extended this definition to all
OM in rocks capable of oil generation.
Forsman & Hunt (1958) defined kerogen as dispersed OM of
ancient sediments insoluble in usual organic solvents.
This was later extended by Durand (1980) to all insoluble
sedimentary OM including pure organic deposits such as
humic and algal coals and various asphaltic substances as
well as insoluble OM in recent sediments & in soils.

21. Kerogen
Kerogen formation is the first step of organic transformation after the sedimentation of dead organic matter. After deposition of the organic rich sediments, it gradually changes to source rock during which sediments are converted to rock and organic matter is converted to kerogen. This process is known as the diagenesis of the source rock and during this process small amounts of biogenic methane is also evolved.
Engler (1913) heated oleic acid and other organic material at temperatures below 2500C and obtained paraffin, napthene and aromatic hydrocarbons in entire petroleum range. Later, he described the generation of petroleum from organic matter as a two step process involving bitumen as an intermediate.
Kerogen Bitumen Oil + Gas + Residue

22. Kerogen
Larskaya and Zhabrev (1964) were the first geochemists to demonstrate that the generation of hydrocarbons from the kerogen of shale increases exponentially with depth.
They found extractable organic matter (bitumen) of shale in western ciscaspian region change very little in the temperature range of 200C to 500C after which it increased markedly.

23. Kerogen Kerogen isolation (Durand & Nicaise,1980):
After the rock is ground to fine powder, carbonate minerals
are removed by treatment with HCl in inert N2 atmosphere
at 800C.
Silicates are then dissolved in HF, also in inert N2 atmosphere
at 800C, leaving a kerogen concentrate consisting of kerogen
and small amounts of acid resistant minerals like pyrite.
Each acid treatment is followed by thorough water washing
with special care to ensure dissolution of newly formed
Fluorosilicates. Recovered kerogen is dried at 1000C under
inert N2 atmosphere.
For most of the practical Purpose this kerogen concentrate
is sufficiently pure, however for some special studies
(like sulfur content) inorganic component is removed by
floatation in a heavy liquid like, aquous zinc bromide.

24. Kerogen
Type-I:
Contain alginite, amorphous organic matter, cyanobacteria,
fresh water algae and land plant resins.
H/C > 1.25 & O/C < 0.15
Show great tendency to readily produce liquid hydrocarbons
It derives principally from lacustrine algae and forms only in
anoxic lakes and several other unusual environments
Has few cyclic and aromatic structures.
Formed mainly from proteins and lipids.
Type-II:
Contain alginite, amorphous organic matter, cyanobacteria,
fresh water algae and land plant resins.
H/C < 1.25 & O/C 0.03 to 0.18
Show great tendency to produce a mix of oil & gas.
It derives principally from exinite, cutinite, resinite and liptinite

25. Kerogen Type-III: H/C < 1.0 & O/C 0.03 to 0.3
Material is wood or coal
Tends to produce gas
Derived mainly from plant matter of cellulose & lignin
Type-II-S
Same as Type-II but rich in sulfur
Type-IV
H/C <0.5
It is mostly decomposed organic matter of polycyclic
aromatic hydrocarbons.

26. Algaenan: Highly aliphatic, non-hydrolysable, insoluble macro-
Mechanism of kerogen formation from organic matter is still not
known. Earlier, it was believed that the kerogen is formed by
condensation reactions, the same process of coalification.
At present the theories of ‘Algaenan’ and ‘Millard condensation
to form melanoidin’ are in vogue.
Algaenan: Highly aliphatic, non-hydrolysable, insoluble macro-
molecular constituent have been identified in a number of
microalga cells and their selective preservation shown to play
major role in the formation of kerogen. All the algaenans so far
examined comprise a network of long polymethylenic chains,
except L race of Botryococcus braunii that contains C40
isoprenoid chains with lycophane type skeleton.
Melanoidin: Millard (1912) described the condensation
reaction of an amino group and a reducing compound. It is
believed that proteins and lipids react to form kerogen.

27. P e t r o l e u m Kerogen Bitumen Lipids, Proteins & Carbohydrates
Hydrocarbons &
Protohydrocarbons
In organisms
Bacterial activity & Low temperature chemical reactions
Living Organisms
500C
High Temperature Reactions
Methane
Heavy Oil
Light Oil & Gas
Gas
Pyrobitumen
2000C
2500C
Diagenesis
Catagenesis
Metagenesis

28. Organic Diagenesis is the biological, physical
and chemical alteration of the organic debris
before pronounced effect of temperature. It covers
temperature range upto 500C.
Catagenesis is the stage in which increasing
temperature cause kerogen to thermally decompose
to bitumen to oil, condensate and gas. It covers
temperature range of 500C to 2000C.
Zone of higher temperature from 2000C to 2500C
in which small amounts of methane is formed and
remaining organic matter is converted to pyrobitumen
Is called Metagenesis.

29. Diagenesis The quantity of petroleum generated is determined
mainly by the amount of hydrogen in the organic
matter in the sediment. It follows that strongly
reducing environments such as stagnant lakes or
silled basins preserve and enhance the quantity
and hydrogen content of OM; whereas oxidising
environments lower it.
OM deposited in sediments consists of:
Carbohydrates, Proteins, Lipids, Lignins and
Chitin, Waxes, Resins, Pigments, Fats & Oils.

30. Diagenesis Some of them are consumed by burrowing organisms;
Some may be complexed with mineral matter and some
is attacked by microbes that use enzymes to degrade
biopolymer into simple monomers from which they
were originally formed.
Some degraded bio-monomers undergo no further
reaction but others condense to form complex high
molecular weight geopolymer which along with
undegraded biopolymer become the precursor of
KEROGEN.

31. Diagenesis During Diagenesis under reducing conditions, this
Oil
Window
Immature
Post mature
for oil
During Diagenesis under reducing conditions, this
complex mixture of geo- and biopolymers and
monomers undergo a whole series of low temperature biological & chemical reaction that result in the formation of more hydrocarbon like material through the loss of oxygen, nitrogen and sulfur. 10 20 30
Depth
Mg of HC / 100 mg of TOC

32. Anoxic < 0.1 ml/L Suboxic 1.0 to 0.1 ml/L Oxic > 1.0 ml/L
Sediment
Laminated
Micro – Macro
Burrowed
Coarse
Bioturbation
% TOC
H/C of OM
OM Type
3 to 20
1 to 3
0.05 to 1.0
1.6
1.2
0.8
I and II
II and III
III and IV

33. Catagenesis It is the stage of reaction of OM at higher temperature
at a greater depth. Over time, these high temperatures
cause thermal degradation of kerogen to produce
petroleum.
Engler (1913) heated mixture of oleic acid and other OM
at a temperature below 2500C and obtained petroleum.
Later, he described kerogen is first converted to bitumen
as an intermediate. Miknis et al. (1987) confirmed this
proposition.
Kerogen Bitumen Petroleum

34. Oil Window : The depth interval in which a petroleum source
rock generates and expels most of its oil is called the oil
Window. Most oil windows are in the temperature range of
600C (1400F) to 1600C (3200F).
The stratigraphic intervals above, within and below the oil
window are known as immature, mature and post mature for
oil generation. Post mature for oil is mature for gas window.
Gas Window : The depth interval in which a petroleum
source rock generates and expels most of its gas is called
the gas window. Most gas windows are in the temperature
range of 1000C (2120F) to 2000C (3920F).

35. Metagenesis
This is the last stage of significant thermal alteration of OM.
Here methane generation diminishes and graphitic structure
begins to form. Metagenesis occurs at the temperature range
Of 2000C (3920F) 2500C (4820F).
At such temperatures, atomic H/C of kerogen falls to less
than 0.4, typical of the kerogen in phyllite.
High temperature end of organic thermal alteration overlaps
with low temperature beginning of inorganic thermal alteration.

36. Migration of Petroleum
Geological Framework
Short or Long Migration
Primary Migration
Secondary Migration
Capillary Pressure
Buoyancy
Dissolved Gas effects
5. Tilted Oil-Water contact

37. Geological Framework:
Nearly every petroleum pool exists within an environment of water.
The gas and oil are chiefly immiscible in water and both have lower density than surrounding water.
The microscopic shape and size of pores, the tortuous path of permeability and chemical character of the rock varies.

38. Geological Framework
4. The minimum time for oil & Gas to generate, migrate and accumulate is probably less than one MY.
5. The fluid pressure within the reservoir rock may also vary within the life of the reservoir, depending on the geological history of the region. They have been observed to range from one atmosphere to 1000 atmosphere or greater and they may have fluctuated up or down many times

39. Geological framework:
6. Temperature of the reservoir rock may vary 50 – 1000C although extremes up to 1630C is known.
The geologic history of the trap may vary widely – from a single geologic episode to a combination of many phenomena extending over a long period of geologic time.
8. Reservoir rocks that contain petroleum differ from one another in various ways: They range in geologic age from Precambrian to Pliocene; in composition from siliceous to carbonate; in origin from sedimentary to igneous; in porosity from 1 to 40% and in permeability from one millidarcy to many darcies.

40. Migration of Petroleum
Short or Long Migration:
The best evidence of short migration are the pools in isolated sand
lenses.
2. There are several good reasons for believing long distance migration:
Common occurrence of oil and gas seepage.
Production of oil and gas from pools.
A structural trap may not form until long after the reservoir rock
is in place.
Primary Migration:
Defined as the migration of petroleum from the source rock to the carrier bed.
Earlier theories believed oil and gas came out of source rock with squeezing
Water (Hydrodynamic theory by Munn(1909); Hydraulic buoyancy theory by
Rich(1921); Mrazec(1910);Daly(1917); Sedimentary compaction theory by
King(1899); Monnet(1922); Lewis(1924) and the Compaction – hydraulic
Theory by Cheney(1940)

41. Secondary Migration
In order to evaluate the conditions under which oil migration can occur it is
necessary to estimate the difference of capillary pressure at the leading and rear
end of the migrating oil body. The geometry of an isolated oil globule in a pore
when there is no effective force tending it to cause migrate is shown in Fig.A
The capillary pressure is
2γ cosØ r
Pc =
Fig.A
Which is approximately same at every corners. Fig.B shows the distorted
Shape of this globule as it is just before breaking through the constriction
At point A and is migrating to the next pore. In this condition the capillary pressure
at the foremost and rear end are -
2γ cosØ rp
Pc =
2γ cosØ rc
Pc = rp
Fig.B

42. Secondary Migration If we take an average, rc = rp/3, then
Therefore,
ΔPc = 2γ CosØ (1/rc – 1/rp)
Assume, for an average porous sand rc of the pore connecting capillaries is
between ½ and ¼ of rp of the pores, then
ΔPc = 2γ CosØ /rp or ΔPc = 6γ CosØ /rp)
If we take an average, rc = rp/3, then
ΔPc = 4γ CosØ/rp
If contact angle is 600, then cosØ = ½ and ΔPc = 2γ/rp

43. Secondary Migration
Consider now the possibility of creating this ΔPc from flowing formation water.A normal hydrodynamic gradient of 10ft/mile can produce 0.1dyne/cm2 for coarse sand 0.02 dynes/cm2 for fine sand. An extreme gradient of 100ft/mile will produce 1.0dyne/cm2 for coarse and 0.2 dynes/cm2 for fine sand.

44. Capillary Pressure Difference Required for Migration (dynes/cm2)
γ (Dyne/cm2)
V. coarse sand (rp=0.02cm)
Coarse Sand
(rp =0.01cm)
Av. Sand
(rp=0.005cm)
Fine Sand
(rp=0.002cm)
V.Fine Sand
(rp=0.001cm) 30
3,000
6,000
12,000
30,000
60,000 25
2,500
5,000
10,000
25,000
50,000 20
2,000
4,000
8,000
20,000
40,000 10
1,000 5
500 1
100
200
400

45. Buoyancy
Upward movement due to buoyancy begin where sufficient local concentration of oil & gas has developed.

46. Buoyancy The force of buoyancy acts to trap hydrocarbon in two ways :
when HC entrained in flowing water reach an anticlinal area their buoyancy causes them to resist further movement.
The oil & gas migrate up dip by buoyancy till buoyancy or capillary pressure no longer exceeds Pd.

47. Buoyancy Buoyancy opposed Buoyancy spplimented by hydrody-
namic force
Buoyancy spplimented
by hydro-dynamic force
Buoyancy spplimented
by hydro-dynamic force

48. Effect of water flow
directed up dip &
through a barrier zone of
higher displacement
pressure
Effect of water flow
directed down dip &
through a barrier zone of
higher displacement
pressure

49. Effect of gas in migration
The importance of gas in the movement of oil through reservoir was long ago pointed by Johnson (1912).
Thiel’s Experiment (1920):
Crude oil diluted with 1/3rd kerosene +
sea water acidized with 0.5% HAc +
20mesh quartzite was placed in a 1” dia
4’ length tube bent in the form of anticline.
4” of both ends of tube were filled with
crushed dolomite and finally ends were
sealed. CO2 generated by reaction of
dolomite with HAc moved up the tube
carrying oil with it. Similar experiment with
no gas resulted no concentration of oil.
Dolomite
QZ + HAc
+ Crude
Oil
Gas
This was supported by Emmons & Mills Experiment

50. All the theories involve movement of large quantity of water with dispersed
oil and gas.
Oil and Gas in solution of reservoir waters is cited as evidence. The solubility
of natural gas in water ranges from 4 cft/barrel at 400 psi that goes to
22 cft/barrel between 2000 to 6000psi. Lighter components of oil are soluble
in water, the amount increase with pressure. At atmospheric pressure the
solubility is 0.014% volume.
Water squeezed out of clays & Shales:
If water containing oil & gas is squeezed out of clay & shale into permeable
reservoir rock, then it must displace water that is already present in the
permeable rock. This would cause a flow of water through the reservoir rock
to the surface. As the water moves through the reservoir, the entrained
petroleum may be carried along in a miscible phase until enough petroleum
Accumulates in phase continuity to develop buoyancy.

51. Normal Water Circulation:
At the time of diagenesis the pore spaces of the reservoir are filled with water.
Regional circulation pattern develop and continually change as fluid pressure
gradient change. Fluid pressure may change due to:
Diastrophism, ii. Mountain building, iii. Erosion, iv. Deposition,
Recharge from meteoric waters, vi. Osmosis, vii. Faulting,
viii. Folding, ix. Cementation affecting permeability may change direction
x. Chemical deposit and xi. Igneous intrusion
The present concept of mechanism of primary migration suggests petroleum
globules develop excess pressure in the pores of shale and generate micro-
cracks in the rock through which globules come out. Once the globules come
out, pore pressure also get reduced and micro-cracks are annealed.

52. Secondary Migration:
Defined as the migration of petroleum from the carrier bed to the trap.
Entrained Particles –
Microscopic and sub-microscopic particles of petroleum hydrocarbon
entrained in the moving water would be carried along until obstructed
by the structure or separate and aggregate till buoyancy get effective.
Capillary Pressure:
The basic requirement for the large patches of oil in water wet reservoir is
that the capillary pressure of the oil-water interface exceeds the
displacement pressure. For any specific combination of oil, water and pore
the displacement pressure Pd is a constant value. On the other hand,
capillary pressure is dependent on buoyancy, pressure gradient, and the
length of the oil phase. Whenever these forces are sufficient to cause
capillary pressure to exceed Pd the oil will enter and pass through the pores.

53. Reservoir Rock
Reservoir Rock is defined as the rock having appreciable porosity to trap the hydrocarbons and sufficient permeability for the oil to flow during migration and production.
Characteristically, these are coarse grained clastic sedimentary rocks or porous limestones or fractured igneous or metamorphic rocks.

54. hydrocarbons from the trap.
Seal Rock
Seal Rock is defined as the rock that prevent further vertical and lateral migration of the
hydrocarbons from the trap.
Characteristically, these are fine grained impermeable sedimentary rocks.

55. Hydrocarbon Traps Hydrocarbon Traps are:
Structural: If trapping is exclusively due to structural style, or
Stratigraphic: If trapping is exclusively due to stratigraphic disposition, or
Combination: If trapping is neither due to structure & nor due stratigraphic disposition alone.
Structural Traps: Folds, Faults
Stratigraphic Traps: Lenticular Sands, Channel fills
Combination Traps: Up-dip pinchouts

56. PAB 1023 Petroleum Geoscience
Structural Traps
Structural traps are formed usually by tectonic forces.
An anticline is where rocks are folded or bent upwards. Hydrocarbons migrate up the flanks of the anticline and are trapped in the crest.
Faults occur where there is movement along a joint or fracture. Offset of the beds could result in an impermeable layer being on top of a permeable layer.
PAB 1023 Petroleum Geoscience

57. PAB 1023 Petroleum Geoscience
Structural Traps :
PAB 1023 Petroleum Geoscience

58. Structural Traps Terminology
PAB 1023 Petroleum Geoscience

59. PAB 1023 Petroleum Geoscience
Six trapping and two non-trapping configurations against a fault, depending on whether the fault is normal or reverse, on the direction of dip of the beds relative to the fault plane, and on the amount of displacement of the reservoir.
PAB 1023 Petroleum Geoscience

60. PAB 1023 Petroleum Geoscience
Sealing Faults
An investigation into the sealing qualities of faults affecting roll-over anticlines in the Niger Delta, where the reservoirs overlie overpressured shales (bulging).
Where a reservoir is full to spill-point against a fault, and where an oil-water contact is continuous across a fault, it is presumed that the fault is non-sealing; elsewhere it appears to form a trap. The difference is believed to be due to clay being smeared into the fault plane, where there is enough of it in the section, as the fault moved
PAB 1023 Petroleum Geoscience

61. PAB 1023 Petroleum Geoscience
Sealing Faults
PAB 1023 Petroleum Geoscience

62. PAB 1023 Petroleum Geoscience
STRUCTURAL TRAP
A review of 200 giant oilfields (those containing 500 million barrels or more) emphasize the importance of structural, essentially anticlinal, traps in both number and size.
The number of structural field of this size may partly reflect the fact that structural traps are easier to find than the others, but the oil reserves they contain show clearly that generally they are also bigger.
PAB 1023 Petroleum Geoscience

63. PAB 1023 Petroleum Geoscience
STRUCTURAL TRAP
The trouble, from our present-day point of view, is that in most parts of the world the larger anticlines have now been drilled. What our efforts are increasingly directed towards, therefore, are the more obscure and generally smaller prospects.
PAB 1023 Petroleum Geoscience

64. PAB 1023 Petroleum Geoscience
Stratigraphic Traps
Rock layers changing from a good reservoir to non-reservoir due to change in rock type (pinch-out), reservoir quality (diagenesis), or removal (erosional unconformity)
PAB 1023 Petroleum Geoscience

65. PAB 1023 Petroleum Geoscience
Pinch Out
Sometimes due to a lateral change in the environment of deposition a lens of permeable sand is surrounded by less permeable siltstones and shales, forming a pinch out trap.
This commonly happens in stream environments where sand is deposited along the stream channel which is surrounded by a flood plain characterized by finer grained sediments.
PAB 1023 Petroleum Geoscience

66. PAB 1023 Petroleum Geoscience
Channel Trap
PAB 1023 Petroleum Geoscience

67. PAB 1023 Petroleum Geoscience
Unconformity
Unconformities are another type of stratigraphic trap.
They represent a gap in the geologic record, in other words a period of erosion and/or nondeposition.
They can result in a permeable reservoir rock being truncated and overlain by an impermeable unit.
PAB 1023 Petroleum Geoscience

68. PAB 1023 Petroleum Geoscience
hydrodynamic trap
Oil, attempting to escape to surface up a reservoir, is held against an unevenness of its upper surface by water flowing in the opposite direction. There is no structural or stratigraphic closure.
Note that the oil-water contact is tilted down in the direction of water flow.
PAB 1023 Petroleum Geoscience

69. PAB 1023 Petroleum Geoscience
Diapiric Traps
Caused by upward movement of sediments that are less dense than those overlying them
Salt
Clay
PAB 1023 Petroleum Geoscience

70. Salt Dome Associated Traps
PAB 1023 Petroleum Geoscience

71. PAB 1023 Petroleum Geoscience
Seal
A seal is a fine-grained rock that prevents the oil migrating to the vertical migration (which happens in many parts of the world - leading to natural oil seeps).
The seal is an important component in a prospect.
PAB 1023 Petroleum Geoscience

72. PAB 1023 Petroleum Geoscience
SEAL
Common seals include
salt evaporites, chalks provides an effective seal, but
clay-rich mudrock, shale represent most seals.
Siltstones (very fine-grained)
PAB 1023 Petroleum Geoscience

73. PAB 1023 Petroleum Geoscience
HOW WE QUANTIFY SEAL?
Analysis of seals involves assessment of their thickness and extent, such that their effectiveness can be quantified.
Knowledge of sequence stratigraphy is crucial for better understanding of seal.
PAB 1023 Petroleum Geoscience

75. Pyrolysis
Pyrolysis is the technique of heating in absence of oxygen. It is usually carried in an atmosphere of helium or nitrogen. In this process the available organic matter in the rock (in the form of kerogen) is cracked down to smaller fragments. Since formation of petroleum takes place deep inside the earth, it is expected to be formed by pyrolysis cracking. But the actual environment of kerogen cracking for generation of petroleum is not yet known. Therefore, following varieties of pyrolysis techniques have been attempted.
Dry pyrolysis Hydrous pyrolysis
3. Closed system pyrolysis Closed anvil pyrolysis

76. Pyrolysis
Dry pyrolysis is carried out using dry samples of carbonate free rock or kerogen. Samples are made carbonate free by prolonged treatment of samples with dilute hydrochloric acid and then thoroughly water washed and dried. The most commonly used dry pyrolysis instrument is Rock-Eval pyrolyser, introduced by IFP sponsored Vincii Laboratory, France. This instrument pyrolyses the sample in nitrogen or helium environment using desired programmed heating conditions. This programmed heating condition is a facility to simulate heating as per thermal history of the basin. This instrument is fitted with a flame ionization detector (FID) to detect the released hydrocarbons.

78. The instrument is heated at 3000C before any sample is introduced
The instrument is heated at 3000C before any sample is introduced. When the sample is introduced at 3000C, it is believed all the available bitumen in the rock is released as S1 (P1) peak. The instrument is then heated as per program till 6500C (RK-Eval 2). The hydrocarbons generated by cracking in this process is recorded as S2 (P2) peak. The instrument also holds a CO2 trap. This trap accumulates all the CO2 generated from beginning to end and releases as S3.

79. Intensity S1 S2 S3
3000C
6500C
Time / Temperature

80. Interpretation
S1 is thus representative of adsorbed hydrocarbons in the rock. It may be available due to generation in the source rock or it may be adsorbed in the reservoir rock or it may also be adsorbed in the carrier bed while migration.
High S1 is therefore interpreted as a good source rock, if appreciably matured; or a good reservoir rock or may be a carrier bed indicating positive migration path.

81. S2 is representative of cracked hydrocarbons available by programmed cracking of kerogen. High S2 therefore represents high amount of kerogen in the rock suggesting a possible good source rock. Tmax is the temperature corresponding to maximum of S2 generation. This also indicates the maturity of the corresponding source rock. This is because a highly matured source rock is supposed to start cracking at elevated temperature compared to low matured kerogen.

82. source rock and its peak generation, Tmax, is also supposed to be high
source rock and its peak generation, Tmax, is also supposed to be high. S3 is the amount of CO2 generated from start to the end of the pyrolysis program. This CO2 is generated using oxygen from the oxygen bearing radicals (-COOH, -CHO, -CO-, -O- etc) in the compounds of kerogen. High amount of S3 thus represents high amount of such oxidised radicals and in turn suggest more oxygenated environment of kerogen deposition.

83. Pyrolysis results also generate three more derived parameters – hydrogen index (HI), oxygen index (OI).and production index (PI).
HI = 100(S2 / TOC) --- (1)
OI = 100(S3 / TOC) --- (2)
PI = S1/ (S1+S2) (3)
S2 is believed to be the cracked hydrocarbon produced from kerogen and therefore, higher S2 represent higher produced hydrocarbon.

84. Produced hydrocarbon is essentially a function of carbon & hydrogen
Produced hydrocarbon is essentially a function of carbon & hydrogen. Therefore, division of S2 with TOC is expected to be function of hydrogen. Similarly, S3 / TOC is a function of oxygen and is called oxygen index.
Production index is the ratio of S1 and (S1+S2). Assuming S1 be the generated bitumen and S2 be the potential, PI suggests fraction of the total potential generated.

85. Limitations: Although Rock-Eval is used very frequently for source rock analysis but it has got serious limitations for which it is not considered as confident source rock evaluator but it is used as source rock screening aparatus. The following limitations should be borne in mind during interpretation of data:.
The reliability of S2 peak depends on the assumption that at 3000C all the free hydrocarbons will expel as S1 from kerogen, leaving only kerogen decomposition to form S2 at higher temperatures. Expulsion however depends on the vapour pressure. A C24H50 free hydrocarbon has a boiling point of 3900C STP (Ferris, 1955). Consequently it comes off as S2 in stead of S1.
Three straight chain paraffins, C16H34, C22H46 and C24H50 were mixed with calcite and pyrolysed (Tarafa, 1983). C16 peak came off as S1 but C22 was split between S1 and S2 and most of C24 came off as S2 peak. It was concluded that free hydrocarbons containing 24 or more atoms of carbon come off as S2 and would result higher HI.

86. Because of the same earlier reason S1 is also to be considered with suspision. Further, S1 may be high in reservoir rocks and carrier beds due to migratory hydrocarbons. It becomes difficult to distinguish autochthonous generated hydrocarbons from allochthonous migratory hydrocarbons.
Hydrogen index (HI) does not necessarily represent the amount of hydrogen concentration in the source rock. This is because FID measures the number of C-C bonds in hydrocarbon.Therefore, hexane and benzene both should have equal HI but actually, hexane has got H/C=2.33 and benzene has H/C=1.0. This suggests all the high HI values do not correspond to high concentration of hydrogen in the sample, rather it may be due to high aromaticity of the organic matter in the sample.
Whereas both S1 and S2 are not confident, then the derived parameters like, HI, Tmax and PI are also not dependable.

87. Remark as possible Source Rock
Complete the table given below with remarks of possible source rock.
Lithology
TOC S1 S2
Tmax HI PI
Remark as possible Source Rock
1. Shale
0.68
0.15
429
2. Shale
1.19
0.17
1.36
438
3. Shale
0.98
0.06
1.47
433
4. Shale
0.9
0.08
1.2
439
5. Shale
0.43
0.01
0.21
440
6. Shale
1.01
7. 80% Sh, 20% silt
0.86
0.38
2.86
8. 90% Sh, 10% silt
0.62
0.32
2.53
9. Shale
0.36
0.18
1.1
10. Shale
1.4
2.8
450