Use of Rock-Eval pyrolysis

Use of Rock-Eval pyrolysis in the petroleum
exploration and production
Realized by
Hawari Salim
1

CONTENTS
GENERAL INTRODUCTION
Chap I. ORIGIN, COMPOSITION AND TYPES OF ORGANIC MATTER
I.1. ORIGIN OF ORGANIC MATTER
I.2. COMPOSITION OF SEDIMANTRY ORGANIC MATTER
I.2.1. Kerogen
I.2.2. Bitumen
I.3. TYPE OF ORGANIC MATTER
I.4. EVOLUTION OF ORGANIC MATTER
I.4.1. Diagenesis
I.4.2. Catagenesis
I.4.3. Metagenesis
I.5. PETROLEUM CHEMICAL COMPOSITION
I.5.1. Definition of petroleum
I.5.2. Composition of petroleum
Chap II. THE PETROLEUM SYSTEM CONCEPT
II.1. Definition of petroleum system
II.2. Elements of petroleum system
II.2.1. Source rock
II.2.2. Reservoir Rock
II.2.3. Cap rock or seal
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II.2.4. Trap
II.3. Processes of petroleum system
II.3.1. Maturation
II.3.2. Migration
Chap III. The Rock-Eval pyrolysis
III.1. Introduction
III.2. Definition of pyrolysis
III.3. Principle of Rock-Eval pyrolysis
III.4. Rock-Eval I
III.5. Rock-Eval II
III.6. Rock-Eval III
III.7. Rock-Eval 6
Chap IV. Areas of application of Rock-Eval pyrolysis
IV.1.Introduction
IV.2. Exploration areas
IV.3. Production areas
IV.4. Environmental areas
IV.5. organic matter recent
IV.6. Limit of use of Rock-Eval: influence of the mineral matrix
Chap V. Case of study
GENERAL CONCLUSION
REFERENCES
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LIST OF FIGURES
Figure I-1: Figure I-1: Van Krevelen diagram showing different types of organic matter …....12
Figure I-2: general scheme of the evolution of the organic fraction …………………………...13
Figure II-1: Cap rock…………………………………………………………………………..17
Figure II-2: Different types of trap structures…………………………………………………..18
Figure II-3: Diagram illustating Petroleum system ingredients………………………………..19
Figure III-1: Schematic cross section of the first commercial Rock-Eval I …….………........22
Figure III-2: Schematic cross section of the Rock-Eval II …………………………………...23
Figure III-3: Schematic cross section of the Rock-Eval III …………………………………..24
Figure III-4: Schematic cross section of the Rock-Eval 6 …………………...…………........24
Figure III-5: Pyrogramme showing different Rock-Eval pyrolysis of organic matter.………...25
Figure IV-1: PP/TOC illustrating the quantitative and qualitative assessment of source rock
evolution of single rock characteristics………………………………………………………….27
Figure IV-2: Tmax/Production Index plot showing stage of thermal maturity of source
rock……………………………………………………………………………………………...28
Figure IV-3: Type and degree of organic matter………………………………………………28
Figure IV-4: Examples of appling Rock-Eval 6 to the study of reservoir rocks……………...30
Figure IV-5: Examples off applying Rock-Eval 6 to the study of contaminated soils………..31
Figure IV-6: Influence of mineral matrix on hydrocarbon yield ……………………………….33
Figure V-1: Geochemical log of CBBD cross section the Bou Dabbous Rock-Eval pyrolysis
data……………………………………………………………………………………………….36
Figure V-2: Quantitative and qualitative assessment of the Bou Dabbous formation from CBBD
cross section……………………………………………………………………………………...37
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Figure V-3: HI/OI diagram showing the type of the Bou Dabbous organic matter from
CBBD cross section…………………………………………………………………….38
Figure V-4: HI/Tmax diagram showing the type and the maturity stage of the Bou
Dabbous organic matter from CBBD cross section…………………………………….39
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LIST OF TABLES
Table I-1: Different kerogen types ………………………….……………………….…………12
Table I-2: The hydrocarbon weight % values are averages…………………………..…………14
Table II-1: The mains categories of source rocks……………………………………..………..16
Table V: Rock-Eval pyrolysis and TOC results of Bou Dabbous formation outcropping at CPBD
cross section)…...35
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GENERAL INTRODUCTION
History of Organic Geochemistry: Organic geochemistry is the fruit of questions about the origin
of petroleum, and for the time being, its development has been closely linked to that of
petroleum exploration. It only became an autonomous science shortly after 1960. The years
1965-1985 were extremely productive: during this period, the mechanisms of the formation of
oil and natural gas fields were clarified, and many biomarkers, testimony of the organic origin of
oil, were identified. The knowledge of kerogens, the raw material for the formation of oil, also
made decisive progress, and tools to aid petroleum exploration were created, such as oil-source-
rock correlation methods, Rock-Eval, and mathematical models simulating the formation and
migration of oil. A rapprochement took place at the same time with coal science and an
extension of organic geochemistry to various fields such as organic sedimentology, the
microbiology of sediments and the formation of orebodies. In the coming years, organic
geochemistry will continue to play an important role in the exploration and production of oil, and
of fossil fuels in general, but its long term future probably lies in the study of interactions of the
products of man’s activity, in particular organic pollutants and greenhouse gases, with the
geosphere, in relation with the search for sustainable development and the understanding of
mechanisms of climatic changes.
In the present work, we will present an overview of the using of Rock Eval pyrolysis technique
in petroleum industry activities.
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Chapter I: ORIGIN, COMPOSITION AND TYPES OF ORGANIC MATTER
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I.1. ORIGIN OF ORGANIC MATTER
After the death of living organisms most of their remains is reused in the life cycle of organic
carbon, except a very small fraction (1%) that accumulates in sediment (Durand., 1980 Tissot,
and Welte., 1984). The degradation of these materials goes through several stages of evolution
that span varying geological time.
The main organisms that are at the origin of the organic material are the phytoplankton,
zooplankton, plants and bacteria.
These bodies consist of lipids, proteins and carbohydrates. The lignin is also one of the major
constituents of higher plants. Among these constituents are fats and lignin which escape most
readily to cycle organic carbon.
For that matter can escape the life cycle, it needs an anoxic environment favorable to its
preservation. An aquatic environment is considered anoxic if it contains less than 0.1 ml/l
dissolved oxygen (Rhodes and Morse, 1971).
The organic matter settles to the bottom of the sea, lakes and deltas. A sedimentary basin is
formed by the accumulation of layers of sediment. As to measurement of the landfill there is an
increase of pressure and temperature. The first is a mechanical consequence of the accumulation
of sediments and the second is due to the existence of internal heat source grounded. The rise in
temperature is translated by a geothermal gradient that depends on time and regions. The current
average gradient is estimated at 30°C/km (Salle and Debyser, 1976).
I.2. COMPOSITION OF SEDIMANTRY ORGANIC MATTER
I.2.1. Kerogen
Kerogen is defined as sedimentary organic matter that is insoluble in water, alkali, non-oxidizing
acids, and organic solvents (such as benzene/methanol, toluene, and methylene chloride). It is
usually accompanied by a smaller fraction of soluble organic matter, called bitumen. Kerogen,
an inhomogeneous macromolecular aggregate, constitutes 90 percent or more of organic matter
in sedimentary rocks (much of the remainder being dispersed bitumen). Kerogen is by far the
most abundant form of organic carbon on Earth; it is three orders of magnitude more abundance
that coal, petroleum, and gas, and four orders of magnitude more abundant than the living
biomass. Kerogen has the interesting and significant property that upon heating in the laboratory,
a procedure known as pyrolysis, it breaks down to produce a variety of hydrocarbons similar to
those found in natural petroleum. However, kerogen varies widely in its petroleum potential.
Kerogen that is rich in aliphatic compounds, generally derived from aquatic and marine algae,
has good petroleum potential and is called sapropelic Kerogen. Kerogen derived principally from
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the remains of higher plants is rich in aromatic compounds, sometimes called humic kerogen and
has poor petroleum potential.
Carbon and hydrogen are the main constituents of Kerogen. Hydrogen concentrations range from
5 to 18 % (atomic), depending on type and degree of evolution. Oxygen concentrations typically
range from 0.25 to 3%, again depending on type and degree of evolution. Besides C, H and O,
Kerogen typically contains 1-3% N and 0.25-1.5% S (though the latter can be higher). A variety
of trace metals, notably V and Ni, are also found in Kerogen.
I.2.2. Bitumen
The fraction of sedimentary organic matter that is soluble in carbon disulfide is called bitumen
and includes solids, liquids, and gases. At the end of diagnosis, bitumen generally constitute less
than 3 to 5 percent of the total organic carbon (the remainder being kerogen), though this figure
is occasionally higher. During subsequent thermal evolution, however, the fraction of bitumens
increases at the expense of kerogen (see below). Bitumen consists primarily of 2 fractions:
asphaltenes, and maltenes. These fractionations are defined, like humic substances, by thier
solubility. Maltenes are soluble in light hydrocarbons such as hexane, whereas asphaltenes are
not. Asphaltenes appear to be structural similar to kerogen, consisting mainly of aromatic nuclei
link by aliphatic units. They can be thought of as small fragment of kerogen. Maltens can be
subdivided in to petroleum, which consists of a variety of hydrocarbons, and resins. Resins and
asphaltenes, unlike hydrocarbons, are rich in heteroatoms such as N, S, and O. Resins tend be
somewhat richer in hydrogen (H/C atomic ~ 1.4) and poorer in N, S, and O (7-11wt %) than
asphaltenes (H/C atomic ~ 1.2, N, S, O~8 -12%). Both have molecular weights greater than 500
and several thousand.
The hydrocarbon fraction consists of both aliphatic and aromatic components. The aliphatic
component can further be divided into acyclic alkanes, referred to as paraffins, and cycloalkanes,
referred to as naphthenes. The lightest hydrocarbons such as methane and ethane are gases at
room temperature and pressure; heavier hydrocarbons are liquids whose viscosity increases with
the number of carbon. The term oil refers to the liquid bitumen fraction. Pyrobitumens are
materials that are not soluble in CS2 but break down upon (pyrolsis) into soluble components.
I.3. TYPE OF ORGANIC MATTER
Petroleum is basically the fossil fuel. Hydrocarbon C and H are the components that make up
different types of fuel example oil, gas and coal. Well the generation of hydrocarbon type is
given by a specific type of Kerogen.
Different type of Kerogen produces different type of hydrocarbon (Table I-1 and Fig. I-1).
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• Type I Kerogen: This type of Kerogen comprises mainly lacustrine algae and gives
mostly oil and less gas (H/C > 1.25, O/C < 0.15) and is ranked as “Oil prone”.
• Type II Kerogen: mostly gas and less oil (H/C < 1.3, O/C ~ 0.03 - 0.18) and is ranked as
“oil and gas prone”.
• Type III Kerogen: This type of kerogen has the terrestrial (land) plants and as generates
mainly gas and less oil (H/C < 1, O/C ~ 0.03 - 0.3) and is ranked as “Gas prone”.
• Type IV Kerogen corresponds to oxidized organic matter
Table I-1: Different kerogen types (McCarthy and al., 2011)
Figure I-1: Van Krevelen diagram showing different types of organic matter
I.4. EVOLUTION OF ORGANIC MATTER
The generation of petroleum by kerogen maturation depends on a combination of temperature, as
a function of the depth of burial, and time. Kerogen is mostly formed in shallow subsurface
environments. With increasing burial depth in a steadily subsiding basin, the kerogen is affected
by increased temperature and pressure.
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After burial and preservation, organic matter can go through three phases leading to kerogen
degradation (Fig. I-2):
Figure I-2: General scheme of the evolution of the organic fraction (McCarthy et al., 2011)
I.4.1. Diagenesis
This phase occurs in shallow subsurface environments at low temperatures and near-normal
pressures. It includes two processes, biogenic decay supported by bacteria, and abiogenic
reactions (Selley, 1985). Diagenesis results in a decrease of oxygen and a correlative increase of
the carbon content. It is also characterized by a decrease in the H/O and O/C ratios (e.g. Tissot &
Welte 1978).
I.4.2. Catagenesis
This phase is marked by an increase in temperature and pressure, and occurs in deeper
subsurface environments. It results in a decrease of the hydrogen content due to generation of
hydrocarbons. Petroleum is released from kerogen during this stage. Oil is released during the
initial phase of the catagenesis, at temperatures between 60 and 120ºC. With increasing
temperature and pressure (approximately 120-225 ºC), wet gas and subsequently dry gas are
released along with increasing amounts of methane (e.g. Tissot & Welte, 1978; Selley, 1985).
Catagenesis is characterized by a reduction of aliphatic bands due to a disubstitution on aromatic
nuclei with increased aromatization of naphthenic rings.
I.4.3. Metagenesis
This is the last stage in the thermal alteration of organic matter. It occurs at high pressures and
temperatures (200 to 250 ºC) in subsurface environments leading to metamorphism and a decline
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of the hydrogen-carbon ratio. Generally only methane is released until only a carbon-rich solid
residue is left. At temperatures over 225 ºC, the kerogen is inert and only small amounts of
carbon remain as graphite (Selley 1985).
I.5. PETROLEUM CHEMICAL COMPOSITION
I.5.1. Definition of petroleum
Petroleum is a fossilized mass that has accumulated below the earth’s surface from time
immemorial. Raw petroleum is known as crude (petroleum) oil or mineral oil. It is a mixture of
various organic substances and is the source of hydrocarbon.
I.5.2. Composition of petroleum
The compounds in crude petroleum oil are essentially hydrocarbon or substituted hydrocarbons
in which the major elements are carbon at 85%-90% and hydrogen at 10%-14% and the rest with
non-hydrocarbon elements sulfur (0.2%-0.3%), nitrogen (<0.1-2%), oxygen (1%-5%), and
organo-metallic compounds of nickel, vanadium, arsenic, lead, and other metals (Table I-2).
Table I-2: The hydrocarbon weight % values are averages.
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Chapter II: THE PETROLEUM SYSTEM CONCEPT
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II.1. Definition of petroleum system
The petroleum system is a unifying concept that encompasses all of the disparate elements and
processes of petroleum geology. Practical application of petroleum systems can be used in
exploration, resource evaluation, and research.
Petroleum: describes a compound that includes high concentrations of any of the following
substances:
• Thermal and biological hydrocarbon gas found in conventional reservoirs as well as in gas
hydrates, tight reservoirs, fractured shale, and coal.
• Condensates.
• Crude oils.
• Natural bitumen in reservoirs, generally in siliciclastic and carbonate rocks.
System: describes the interdependent elements and processes that form the functional unit that
creates hydrocarbon accumulations.
II.2. Elements of petroleum system
II.2.1. Source rock
The source rocks are mainly organic rich sediment, which are very fine-grained and
impermeable. These sediments have the potential to generate petroleum and are termed as Source
Rock. To be a source rock, a rock must have three features:
- Quantity of organic matter
- Quality capable of yielding moveable hydrocarbons
- Thermal maturity
Source rocks can be divided into at least four major categories (Table II-1):
Table II-1: The mains categories of source rocks
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II.2.2. Reservoir Rock
This element is a kind of porous or permeable lithological unit(s) which retains the
immigrating oil and gas from source rock. Oil and gas usually accumulate on the top of water
and they are always there relatively to their difference of densities. The reservoir rock are
basically analyzed by means of assessing their porosity a permeability but also its analysis
takes ranges into various fields such as stratigraphy, structural analysis, sedimentology,
paleontology and reservoir engineering disciplines. In case the reservoir has yet been
identified, key characteristic crucial to hydrocarbons exploration are bulk rock volume and net-
to-gross ratio. The bulk rock volume (gross volume of the rock above the water-hydrocarbons
contact) is obtained from of sedimentary packages while the net-to-gross ratio (the proportion
of sedimentary packages in a reservoir rock) estimations are gotten from analogues and wire
lines logs.
II.2.3. Cap rock or seal
It is a lithological unit(s) with low permeability which restricts hydrocarbons to escape from
the reservoir (Fig. II-1). It is made of chalks, shale or evaporates. Its analysis bases on
assessing the extent and thickness to know how much cap rock is efficient to oil and gas
retention. According to lithological deformation that might have been happen, the cap rock
may be found in various types. The tectonic movements the crust experiences cause the
anticline and syncline seals and the matter of consequences of their shapes; the convex form is
more enjoyable to petroleum exploration than concave one. That is why always the seismology
experiments are always carried out to assess how well they can reach the reservoir by aiming at
seal with a concave shape as to ease and make efficient the petroleum exploration.
Figure II-1: Cap rock.
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II.2.4. Trap
The trap is structural or stratigraphic feature that ensures a fixed and firm position of seal and
reservoir which avoids the escape of oil and gas (Fig. II-2).
Structural traps
Are formed as a result of changes in the structure of the subsurface due to processes such as
folding and faulting, leading to the formation of domes, anticlines, and folds. Examples of this
kind of trap are an anticline trap, a fault trap and a salt dome trap.
They are more easily delineated and more prospective than their stratigraphic counterparts, with
the majority of the world's petroleum reserves being found in structural traps.
Figure II-2: Different types of trap structures.
Stratigraphic traps
Stratigraphic traps are formed as a result of lateral and vertical variations in the thickness,
texture, porosity or lithology of the reservoir rock. Examples of this type of trap are
an unconformity trap, a lens trap and a reef trap.
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Hydrodynamic traps
Hydrodynamic traps are a far less common type of trap. They are caused by the differences in
water pressure that are associated with water flow, creating a tilt of the hydrocarbon-water
contact.
II.3. Processes of petroleum system
II.3.1. Maturation
The assessment of the reservoir quality (nature) involves maturation analysis by which they
know the length of time of petroleum generation or expulsion.
II.3.2. Migration
Migration is the process of moving oil and gas from the source rock to the reservoir pores
when it is trapped after its generation. The main factors of the oil and gas migration are
compression, buoyancy, chemical potential; thermal expansion, topography, maturation
(increase in volume with time), and gravitational separation of hydrocarbons and water from
each other.
Figure II-3: Diagram illustating Petroleum system ingredients
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Chapter III: The Rock-Eval pyrolysis
19

III.1. Introduction
The well-known Rock-Eval pyrolysis method (Espitalie et al., 1977, 1980, 1985/86) is now
widely used for the standard characterization of sedimentary organic matter in petroleum
exploration.
For a whole-rock sample, the pyrolysis recording of hydrocarbon generation as a function of
temperature usually shows two well-defined peaks. Espitalié et al., (1977) stated that the first
peak (S1) represents the free and adsorbed hydrocarbons already present, vaporized at 300°C,
and that the second peak (S2) represents the hydrocarbons generated directly from the kerogen,
by thermal cracking at 30o-500°C.According to them, SI is a measure of the bitumen content
and S2 is a measure of the insoluble kerogen content, expressed in kg/ton of rock. The ratioS1/
(S1 + S2) (production index, PI) is an evaluation of the transformation ratio of kerogen into oil
(in the absence of migration). The temperature Tmax recorded at the maximum of hydrocarbon
generation during pyrolysis, is used in kerogen maturation rank evaluation. The hydrogen
index, HI (S2/organic car-bon), is used for characterizing the type and origin of the kerogen.
III.2. Definition of pyrolysis
Pyrolysis is the decomposition of organic matter by heating in the absence of oxygen. Organic
geochemists use pyrolysis to measure richness and maturity of potential source rocks. In a
pyrolysis analysis, the organic content is pyrolyzed in the absence of oxygen, then combusted.
The amount of hydrocarbons and carbon dioxide released is measured. The most widely used
pyrolysis technique is Rock-Eval.
III.3. Principle of Rock-Eval pyrolysis
The oven was initially kept isothermally at 300℃ for 3minutes during which time the free
hydrocarbons are volatilized and the S1 peak is measured by the Flame Ionization Detector
(FID). Pyrolysis of organic matter was later performed at 300-600℃ with a temperature rise of
20

25 ℃/ min. This is the phase of volatilization of the higher carbon number hydrocarbons
compounds (>C40) as well as the cracking of non -volatile organic matter. The hydrocarbons
released from this thermal cracking are measured as the S2 peak (by FID). The temperature at
which S2 reaches its maximum depends on the nature and thermal maturity of the kerogen and
this is measured as Tmax. The CO2 produced from kerogen cracking is trapped in the 300 -
390℃ range. The trap is heated, and CO2 is released and detected on a Thermal Conductivity
Detector (TCD) or IR detector during the cooling of the Pyrolysis oven (S3 peak). The HI was
determined as the yield of reduced products of pyrolysis (S2) relative to the TOC (mg HC/g
TOC) and OI is the yield of the oxygen and bound organic carbon (S3).
III.4. Rock-Eval I
Marketed in 1977, it contains a single pyrolysis furnace whose temperature varies from 300°C
to 600°C. It is a semi-automatic device. The recording of the analysis signals and the
calculation of the parameters already carried out manually requires the integration of an
integrator and a recorder into the ROCK-EVAL device (Fig. III-1).
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Figure III-1: Schematic cross section of the first commercial Rock-Eval I (from Espitalité and
al., 1977)
III.5. Rock-Eval II
Designed in 1979, it contains a pyrolysis furnace and an oxidation furnace (Fig. III-2). It can
be equipped (optionally) with a module for the analysis of residual organic carbon, allowing
calculating the TOC or Total Organic Carbon.
22

Figure III-2: Schematic cross section of the Rock-Eval II (Espitalié et al., 1985)
III.6. Rock-Eval III
It is an improved and simpler version from the ROCK-EVAL II (Fig. III-3). It can be used
directly on drilling sites. It is characterized by:
- Improved reliability of fluid circuits, as it separately analyzes gas and oil,
- Further automation due to:
A microprocessor
An automatic scanner for analyzing 50 samples in a row
- The possibility of measuring carbon directly on the sample Pyrolyzed.
The temperature of the pyrolysis in the ROCK-EVAL III varies between 180 ° C and 600 ° C.
Figure III-3: Schematic cross section of the Rock-Eval III (Espitalié et al., 1985)
III.7. Rock-Eval 6
Latest version of the ROCK-EVAL, marketed in 1996. It has a program of pyrolysis
temperature ranging from 100°C to 850°C (Fig. III-4). This makes it possible to analyze light
hydrocarbons, heavy oils and kerogen type III (higher plants), as well as mineral carbon.
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Figure III-4: Schematic cross section of the Rock-Eval 6 (Behar et al., 2001).
PARAMETERS REGISTERED BY PYROLYSIS ROCK-EVAL (Fig. III-5):
S1 = the amount of free hydrocarbons (gas and oil) in the sample (in milligrams of hydrocarbon
per gram of rock). If S1 >1 mg/g, it may be indicative of an oil show. S1 normally increases with
depth. Contamination of samples by drilling fluids and mud can give an abnormally high value
for S1.
S2 = the amount of hydrocarbons generated through thermal cracking of nonvolatile organic
matter. S2 is an indication of the quantity of hydrocarbons that the rock has the potential of
producing should burial and maturation continue.
S3 = the amount of CO2 (in milligrams CO2 per gram of rock) produced during pyrolysis of
kerogen. S3 is an indication of the amount of oxygen in the kerogen and is used to calculate the
oxygen index (see below). Contamination of the samples should be suspected if abnormally high
S3 values are obtained. High concentrations of carbonates that break down at lower temperatures
than 390°C will also cause higher S3 values than expected.
Tmax = the temperature at which the maximum release of hydrocarbons from cracking of kerogen
occurs during pyrolysis (top of S2peak). Tmax is an indication of the stage of maturation of the
organic matter.
HI = hydrogen index (HI = [100 x S2]/TOC). HI is a parameter used to characterize the origin of
organic matter. Marine organisms and algae, in general, are composed of lipid- and protein-rich
organic matter, where the ratio of H to C is higher than in the carbohydrate-rich constituents of
land plants. HI typically ranges from ~100 to 600 in geological samples.
OI = oxygen index (OI = [100 x S3]/TOC). OI is a parameter that correlates with the ratio of O to
C, which is high for polysacharride-rich remains of land plants and inert organic material
24

(residual organic matter) encountered as background in marine sediments. OI values range from
near 0 to ~150.
PI = Production index (PI = S1/ [S1 + S2]). PI is used to characterize the evolution level of the
organic matter.
PC = pyrolyzable carbon (PC = 0.083 x (S1 + S2)). PC corresponds to carbon content of
hydrocarbons volatilized and pyrolyzed during the analysis.
Figure III-5: Pyrogramme showing different Rock-Eval pyrolysis of organic matter.
25

Chapter IV: Areas of application of Rock-Eval pyrolysis
IV.1.Introduction
Successful petroleum exploration relies on detailed analysis of the petroleum system in a given
area. Identification of potential source rocks, their maturity and kinetic parameters, and their
regional distribution are best accomplished by rapid screening of rock samples (cores and/or
cuttings) using the Rock-Eval apparatus. The technique has been routinely used for about fifteen
years and has become a standard tool for hydrocarbon exploration. We will describe how the
new functions of the latest version of Rock-Eval (Rock-Eval 6) have expanded applications of
the method in petroleum geoscience. Examples of new applications are illustrated for source
rock characterization, reservoir geochemistry, and environmental studies, including
quantification.
IV.1. Exploration areas
Successful petroleum exploration relies on detailed analysis of the petroleum system in a given
area. Identification of potential source rocks, their maturity and kinetic parameters, and their
regional distribution are best accomplished by rapid screening of rock samples (cores and/or
cuttings) using the Rock-Eval apparatus (Figures IV-1, IV-2 and IV-3). The technique has been
26

routinely used for about fifteen years and has become a standard tool for hydrocarbon
exploration.
Figure IV-1: PP/TOC illustrating the quantitative and qualitative assessment of source rock
evolution of single rock characteristics
Figure IV-2: Tmax/Production Index plot showing stage of thermal maturity of source rock
27

Figure IV-3: Type and maturity degree of organic matter
IV.3. Production areas
Geochemistry of reservoirs is an area of growing interest with remarkable economic importance
because it can be used to evaluate reservoir continuity during field appraisal, to identify non-
productive reservoir zones, and to analyze commingled oils for production allocation
calculations (e.g. Kaufman, 1990; England and Cubitt, 1995).
The Rock-Eval method has already been successfully applied in reservoir geochemistry,
especially for the detection of tar-mats and for the prediction of oil API gravities (Trabelsi et al.,
1994). For reservoir geochemistry, the main advantage of Rock-Eval 6 is its capability to
perform both pyrolysis and oxidation of the sample up to 850°C at various rates.
Figure IV-3 is an example of Rock-Eval 6 results for four different reservoir rocks: three
sandstones and one carbonate. The first sample represents a conventional oil accumulation that
produces a large S1 peak and a smaller S2 peak. Almost no CO and CO2 are generated during
oxidation.
The second sample shows a small S1 peak, a bimodal S2 peak (small S2a and large S2b) and
significant amounts of CO and CO2 released during oxidation. This sample is from a
28

conventional tar-mat, i.e. a reservoir rock accumulated with crude oil enriched in resins and
asphaltenes. For the last sandstone reservoir, we still observe the S1, S2a and S2b peaks but we
also observe an important CO2 peak produced during oxidation at high temperature (near
800°C). Since we also observed this peak in the rock sample after decarbonatation, it cannot be
caused by carbonate decomposition of minerals in the sandstone matrix. This peak corresponds
to the combustion of refractory material associated with pyrobitumen in the sample. Therefore it
seems possible, from the comparison of the oxidation curves of two tar-mat levels, to distinguish
a conventional tar-mat deposited in the reservoir from a pyrobitumen produced by in-place
secondary cracking of an oil accumulation. This distinction is very important since it can guide
exploration and production strategies in oil fields with tar-mats.
The carbonate reservoir sample shows the same pattern in the FID trace as that observed for the
conventional tar-mat in the sandstone reservoir. This is typical of the large amounts of resins and
asphaltenes present in the rock. During the oxidation phase of the sample, the strong CO2
production at about 500°C and the CO production correspond to the residual organic carbon,
whereas the very large amount of CO2 produced at higher temperature corresponds to the
decomposition of the carbonate matrix.
29

Figure IV-4: Examples of appling Rock-Eval 6 to the study of reservoir rocks
IV.4. Environmental areas
Due to its economic, environmental and industrial importance, the characterization of soils
contaminated by hydrocarbons is another area where research is very active. Rock-Eval 6
expands the application of pyrolysis methodology to oil-contaminated sites by making it possible
to start the analysis at low temperature (100°C). Furthermore, heating rates can be adjusted so as
to release the different petroleum cuts (e.g., gasoline, diesel oil, heavy oils, lubricant oils, and
gas plant distillation residues). In this application (called Pollut-Eval), the vaporized
hydrocarbons are identified by the FID and the signal is integrated for full quantification. A
complete carbon mass balance is then carried out through oxidation of the residue and
continuous quantification of CO2 by the infrared detectors. For these types of studies, the
apparatus is equipped with a cooled auto sampler that reduces the loss of light compounds. The
equipment thus provides the parameters needed to characterize a contaminated site: what
pollutant, how much and where? Due to the short duration of the analysis (30 min), the time
30

needed to evaluate the extent of a contaminated site is drastically decreased compared to routine
techniques that involve the extraction of the pollutant prior to its analysis by chromatography,
infrared or chromatography-mass spectrometry. Furthermore, when applied on site, the
measurements can be used to optimize the drilling program (Ducreux et al., 1997). Rock-Eval 6
data can be correlated to standard environmental data such as infrared response. They are also
complementary to infrared or gas chromatographic analyses because they allow rapid screening
of a large number of samples, thus helping to identify the samples that are worthy of additional
study. An example of the application of Rock-Eval 6 data for two industrial sites is presented in
figure IV-5. The upper part of the figure shows contamination by diesel oil and polyaromatic
hydrocarbons in a soil near an old gas plant. The FID trace indicates two main peaks
corresponding to the mixture of these hydrocarbons and the CO and CO2 traces during oxidation
are characteristic of the combustion of the heavy residue accompanying these products in the
pollution. The second example is taken from contaminated soil near a service station. Light
gasoline-range compounds are released early during pyrolysis and no significant amounts of CO
and CO2 are recorded during oxidation.
Figure IV-5: Examples of applying Rock-Eval 6 to the study of contaminated soils
IV.5. organic matter recent
Interest in the quantitative and qualitative analysis of soil organic matter (SOM) has been
motivated by its effective role in evaluating the chemical, biological and physical properties of
soils (e.g. van Cleve & Powers, 1995, Karlen et al., 1997, Robert, 1996 and Balesdent, 1996).
31

Another interest has been provided by uncertainties on the effective role of source or sink that
soils can effectively play in the global carbon cycle, with for example consequences on the
greenhouse effect and climate change (Eswaran et al., 1993, Batjes, 1996, Adams & Faure, 1996
and Carter et al., 1997). For these two reasons, and because of considerable spatial variations in
the amount and composition of SOM, there is a need for techniques allowing for its fast and easy
quantitation and characterization. Rock-Eval pyrolysis allows one to determine the total organic
carbon content (TOC wt. %) of rocks and sediments (Espitalite et al., 1977, Espitalite et al.,
1985a, Espitalite et al., 1985b and Peters, 1986). The same applies to soil samples (this paper)
without the decarbonation required for classical combustion techniques. It also provides
information on the composition of the OM, especially through the Hydrogen and Oxygen Index
values (HI and OI) much used with other natural organic materials, e.g. kerogens, and known to
correlate with H/C and O/C ratios (Espitalié et al., 1985b). Rock-Eval pyrolysis thus provides
valuable information on the elemental composition of organic materials that is otherwise difficult
to obtain because of the difficulty of isolating the OM without alteration (Stevenson, 1982 and
Espitalite et al., 1977). The original goal of Rock-Eval pyrolysis was to rapidly obtain
quantitative and qualitative information on the amounts of hydrocarbons and the type of kerogen
present in sedimentary rocks, on the degree of thermal maturity of the kerogen and, if possible,
on its approximate
Composition equivalent to that determined by elemental analysis. However, because of the
simplicity of this technique it has been used for the analysis of soils and immature sediments
(e.g. Disnar & Trichet, 1984, Sifeddine et al., 1995, Ariztegui et al., 1996, Buillit et al., 1997, Di-
Giovanni et al., 1998, Di-Giovanni et al., 1999 and Disnar et al., 2000). Here we present results
of an analytical survey covering a variety of soils resulting from different soil formation
processes, in different continents and with different climates.
IV.6. Limit of use of Rock-Eval: influence of the mineral matrix
To ascertain the potential effects of the mineral matrix on determination of source rock kinetic
parameters, isolated kerogen was mixed with common sedimentary minerals and analyzed by
non-standard Rock Eval pyrolysis. These results were then processed with the computer program
KINETICS to determine the distribution of activation energies and the frequency factor for each
of the mixtures. The kinetic parameters derived from these experiments show that quartz, calcite,
and dolomite at low total organic carbon contents retain part of the S2 material, thus shifting the
activation energy distribution to higher values than observed for the isolated kerogen. As the
amount of organic matter increases, the retention of the S2 material is minimized and the
activation energy distribution becomes more like the isolated kerogen. Clay minerals have
32

different effects on the activation energy distribution. At low organic matter (1–2% TOC),
montmorillinite shifts the activation energy distribution to lower values than observed with the
isolated kerogen. This reflects the catalytic effect that the montmorillinite has on the
hydrocarbon generation reactions. As the amount of organic matter increases, the catalytic sites
deactivate thus minimizing the catalytic effect and the activation energy distribution becomes
more like the isolated kerogen. Kaolinite, like montmorillinite, shifts the activation energy
distribution to lower values than observed for the isolated kerogen. However, as the amount of
organic matter increases, there is no change in the activation energy distribution. This steady
state for the kinetic parameters for kerogen mixed with kaolinite suggests that the catalytic sites
in kaolinite are not deactivated by the hydrocarbon generation reactions. Instead, they remain
active and continue to influence the hydrocarbon generation reactions.
These data suggest that the mineral matrix and the amount, as well as the type, of organic matter
present in a source rock are important factors in determining the hydrocarbon generation kinetic
parameters for the rock. Both retention of S2 material on non-clay minerals and catalysis by clay
minerals may influence the resulting kinetics. It is, therefore, very important that care is taken to
select representative samples of a source rock interval for kinetics analysis. The organically
richest sample or one from a non-representative lithofacies may yield misleading results and
adversely influence the outcome of modeling studies based on them.
Figure IV-6: Influence of mineral matrix on hydrocarbon yield ( type I kerogen: calcite;
type I kerogen: Ca-montmorillonite).
33

Geochemical characterization of Bou Dabbous Formation (Ypresian)
The Bou Dabbous Formation was sampled along CBBD cross section. A total of 36 samples
were collected and analyzed using Rock-Eval pyrolysis.
The screening results which are summarized in table V and graphically illustrated on figures
V-1, V-2 and V-3 indicate that the Bou Dabbous formation can be rated as having fair to
good TOC contents ranging from 0.36 to 1.92% (Mean TOC value: 1.12%). Pyrolysis results
indicate fair to excellent petroleum potentials ranging from 1.10 to 10.96 Kg of
Hydrocarbons/t of rock (Mean Petroleum potential 5.86 Kg of HC/t of rock).
Table V: Rock-Eval pyrolysis and TOC results of Bou Dabbous formation outcropping at
CPBD cross section)
SAMBLES TOC S1 S2 S3 Tmax HI OI BI BB ~Equi R0
CBBD-32 1,24 0,06 5,73 0,56 427 462 45 0,01 5,73 0,53
CBBD -31 1,76 0,16 10,32 0,56 426 586 32 0,02 10,32 0,51
CBBD -30 1,12 0,10 5,99 0,65 431 535 58 0,02 5,99 0,60
CBBD -29 1,61 0,17 9,72 0,39 425 604 24 0,02 9,72 0,49
CBBD -28 0,73 0,02 2,01 0,70 436 275 96 0,01 2,01 0,69
CBBD -27 0,73 0,02 1,97 0,82 434 270 112 0,01 1,97 0,65
CBBD -26 0,44 0,02 1,67 0,43 432 380 98 0,01 1,67 0,62
CBBD -25 0,36 0,02 1,35 0,38 434 375 106 0,01 1,35 0,65
CBBD -24 0,36 0,03 1,65 0,30 433 458 83 0,02 1,65 0,63
CBBD -23 1,16 0,11 6,42 0,58 431 553 50 0,02 6,42 0,60
CBBD -22 1,31 0,13 7,04 0,46 432 537 35 0,02 7,04 0,62
CBBD -21 1,26 0,11 5,93 0,67 430 471 53 0,02 5,93 0,58
CBBD -20 1,47 0,32 10,64 0,40 431 724 27 0,03 10,64 0,60
CBBD -19 1,57 0,25 10,55 0,52 430 672 33 0,02 10,55 0,58
CBBD -18 1,60 0,26 11,01 0,51 430 688 32 0,02 10,55 0,58
CBBD -17 1,57 0,20 9,89 0,56 430 630 36 0,02 9,89 0,58
CBBD -16 0,80 0,07 3,15 0,73 434 394 91 0,02 3,15 0,65
CBBD -15 1,09 0,13 5,57 0,68 434 511 62 0,02 5,57 0,65
CBBD -14 1,07 0,09 5,91 0,39 433 552 36 0,02 5,91 0,63
CBBD -13 1,10 0,10 5,96 0,40 432 542 36 0,02 5,91 0,62
CBBD -12 1,65 0,25 9,52 0,35 430 577 21 0,03 9,52 0,58
CBBD -11 0,81 0,07 3,47 0,53 433 428 65 0,02 3,47 0,63
CBBD -10 1,60 0,23 9,38 0,38 433 586 24 0,02 9,38 0,63
CBBD -9 1,92 0,29 10,86 0,41 431 566 21 0,03 10,86 0,60
CBBD -8 0,75 0,06 2,86 0,20 427 381 27 0,02 2,86 0,53
CBBD -7 1,45 0,17 4,83 0,44 425 333 30 0,03 4,83 0,49
CBBD -6 1,11 0,25 5,39 0,14 426 486 13 0,04 5,39 0,51
CBBD -5 1,25 0,26 6,02 0,21 429 482 17 0,04 6,02 0,56
CBBD -4 0,40 0,02 1,10 0,31 430 275 78 0,02 1,10 0,58
CBBD -3 0,69 0,06 3,73 0,32 433 541 46 0,02 3,73 0,63
CBBD -2 0,77 0,05 3,22 0,28 429 418 36 0,02 3,22 0,56
CBBD -1 1,15 0,13 5,29 0,44 430 460 38 0,02 5,29 0,58
35

Figure V-1: Geochemical log of CBBD cross section the Bou Dabbous Rock Eval Byrolysis
data.
36

0
1
10
100
0,1 1 10 100
PetroleumPotentiel(KgHC/tofrock)
Total Organic Carbon (% rock)
CBBD
CBBD
Very poor GoodFairPoor Very good
VerygoodGoodFair.PoorVerypoor
QUALITATIVE ASSESSEMENT OF ORGANIC CONTENT
QUANTITATIVEASSESSMENTOFYIELD
Figure V-2: Quantitative and qualitative assessment of the Bou Dabbous formation from CBBD
cross section
In terms of origin and quality, the organic matter contained in the Bou Dabbous formation,
appears to be composed of type II kerogen (marine organic matter) containing probably some
terrestrial input or bad preserved marine organic matter (Fig. V-3).
Based mainly on Tmax values which vary between and 425 and 436°C and the low
Production Index (PI) values (<0.04), the Bou Dabbous source rock from CPBD locality
seems to be immature (Fig. V-4)
37

0
100
200
300
400
500
600
700
800
900
1 000
0 100 200 300 400
HydrogenIndex(mgHC/gofTOC)
Oxygen Index (mg CO2/g TOC)
CBBD
CBBD
I
II
III
Figure V-3: HI/OI diagram showing the type of the Bou Dabbous organic matter
from CBBD cross section.
38

0
100
200
300
400
500
600
700
800
900
400 420 440 460 480 500 520
HI(mgHC/gofTOC)
T max (°C)
CBBD
I
II
0.5%R0
1.0% R0
1.5%R0
III
Oil
&
Gas
Gas
Oil
Immature
Oil window
Post
mature
Figure V-4: HI/Tmax diagram showing the type and the maturity stage of the Bou
Dabbous organic matter from CBBD cross section.
39

GENERAL CONCLUSION
The new Rock-Eval 6 pyroanalyzer marks an important step in the development of programmed
pyrolysis systems. This apparatus provides new functionalities and parameters that expand
applications of the technique in petroleum geoscience. Problems related to the older Rock-Eval
systems have been ameliorated. The major improvements and their scientific impact can be
summarized as follows:
- Mineral carbon determination:
-> Improved characterization of marly/carbonate source rocks
-> Detection of carbonate types (e.g., siderite, calcite, dolomite)
-> enhanced characterization of hydrocarbons in carbonate reservoirs
-> Possible correction of matrix effects
- Oxygen indices:
-> Impact on source rocks facies analysis
-> Impact on the knowledge of source rocks preservation conditions
- Improved measurements of TOC and Tmax:
-> Better analysis of type III source rocks
-> Better analysis of heavy bitumen in reservoirs (tar-mat studies)
-> Better characterization of coals
40

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42

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